As filed with the Securities
and Exchange Commission on May 30, 2012
Registration Statement No. 333-177260
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Amendment No. 6
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
ARMSTRONG RESOURCE PARTNERS,
L.P.
(Exact name of registrant as
specified in its charter)
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Delaware
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1221
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20-5609027
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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 Resource Partners, L.P.
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.
Armstrong Teasdale LLP
7700 Forsyth Boulevard, Suite 1800
St. Louis, Missouri 63105
(314) 552-6631
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D. Rhett Brandon, Esq.
Simpson Thacher & Bartlett LLP
425 Lexington Avenue
New York, New York 10017
(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
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 MAY 30, 2012 |
Common
Units
ARMSTRONG RESOURCE PARTNERS,
L.P.
Limited Partner Interests
This is the initial public offering of our common units. We are
offering common units representing
limited partner interests in Armstrong Resource Partners, L.P.
No public market currently exists for our common units. We
currently expect the initial public offering price to be between
$ and
$ per common unit.
We have applied to list our common units on the Nasdaq Capital
Market (Nasdaq) under the symbol
ARPS. There is no assurance that this
application will be approved. We are an emerging growth
company, as such term is defined in Section 2(a)(19) of
the Securities Act of 1933, as amended.
Investing in our common units involves risks. You should read
the section entitled Risk Factors beginning on
page 22 for a discussion of certain risk factors that you
should consider before investing in our common units. These
risks include the following:
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Cash distributions are not guaranteed and may fluctuate with our
performance and the establishment of financial reserves and at
the discretion of our general partner.
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We may not have sufficient cash to enable us to pay any
distributions.
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Cost reimbursements due to our general partner may be
substantial and will reduce our cash available for distribution
to unitholders.
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Unitholders other than Yorktown may not remove our general
partner even if they wish to do so.
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The fiduciary duties of officers and managers of Elk Creek GP,
as general partner of Armstrong Resource Partners, L.P., may
conflict with those of officers and directors of Armstrong
Energy, Inc., which we refer to as Armstrong Energy.
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Our partnership agreement limits our general partners
fiduciary duties to our unitholders and restricts the remedies
available to our unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
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Armstrong Energys board of directors may change the
management and allocation policies relating to Armstrong
Resource Partners without the approval of our unitholders.
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Holders of our common units may not have any remedies if any
action by Armstrong Energys directors or officers in
relation to Armstrong Energy has an adverse effect on only
Armstrong Resource Partners common units.
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Yorktown will continue to have significant influence over us,
including control over decisions that require the approval of
unitholders, which could limit your ability to influence the
outcome of key transactions, including a change of control.
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Conflicts of interest could arise among our general partner and
us or the unitholders.
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Our unitholders share of our income will be taxable to
them for federal income tax purposes even if they do not receive
any cash distributions from us.
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Restrictions in or a failure by our lessee to comply with the
terms of the Senior Secured Credit Facility, on which we serve
as co-borrower with respect to the Senior Secured Term Loan and
guarantor with respect to the Senior Secured Revolving Credit
Facility and the Senior Secured Term Loan, could adversely
affect our business, financial condition, results of operations,
ability to make distributions to unitholders and value of our
common units.
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Our lessee could satisfy obligations to its customers with coal
from properties other than ours, depriving us of the ability to
receive royalty payments.
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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 Common
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Unit
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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 Resource Partners, L.P. before
expenses
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$
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$
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The underwriters have an option exercisable within 30 days
from the date of this prospectus to purchase up
to additional common units from us
at the public offering price, less the underwriting discount.
The common units 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 common units against
payment in New York, New York on or
about ,
2012.
Stifel
Nicolaus Weisel
Prospectus,
dated ,
2012
TABLE OF
CONTENTS
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Page
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ii
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1
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22
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50
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52
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53
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54
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55
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57
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59
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68
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78
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110
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128
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130
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134
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139
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142
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143
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154
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156
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176
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178
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184
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184
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184
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184
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185
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F-1
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EX-1.1 |
EX-10.62 |
EX-23.2 |
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 units 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 units 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, 2011. 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.
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
common units of limited partnership interest 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 22 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 Armstrong Resource
Partners, the Partnership, we,
our, and us are to Armstrong Resource
Partners, L.P. and its subsidiaries taken as a whole. References
to Armstrong Energy, Inc. and Armstrong
Energy are to Armstrong Energy, Inc. and its subsidiaries
taken as a whole. References to limited partners
include holders of common units representing limited partnership
interests in Armstrong Resource Partners.
As described more fully below, concurrently with the offering
of common units of Armstrong Resource Partners, L.P. being made
pursuant to this prospectus, Armstrong Energy, Inc. is engaging
in an offering of its common stock. This prospectus relates
solely to the offering of the common units of Armstrong Resource
Partners, L.P. and does not relate to the concurrent offering by
Armstrong Energy, Inc., which will be made by a separate
prospectus.
About the
Partnership
We are a limited partnership formed in 2008 to engage in the
business of management and leasing of coal properties and
collection of coal production royalties in the Western Kentucky
region of the Illinois Basin. We currently own approximately
65 million tons of coal reserves and, as of March 31,
2012, had a 50.81% undivided interest in approximately
140 million tons of coal reserves owned by Armstrong
Energy, all located in Ohio and Muhlenberg counties in Western
Kentucky. Our coal is generally low chlorine, high sulfur coal.
Our outstanding limited partnership interests (common
units), representing 98.36% of our common units, are owned
by investment funds managed by Yorktown Partners LLC
(collectively, Yorktown). We are not engaged in the
permitting, production or sale of coal, nor in the operation or
reclamation of coal mining activity. We are a fee mineral and
surface rights owning entity. It is our intention to remain a
coal leasing enterprise and not to engage in coal production
ourselves.
We currently lease all of our reserves to Armstrong Energy, our
sole lessee, in exchange for royalty payments in the amount of
7% of the revenue received from coal sold from those reserves.
Armstrong Energy is a diversified producer of low chlorine, high
sulfur thermal coal from the Illinois Basin with both surface
and underground mines. Armstrong Energy is currently deferring
the cash payment of those royalty payments. Partially as a
result of those deferrals, as of December 31, 2011 we were
owed approximately $5.7 million from Armstrong Energy.
We intend to use the net proceeds from this offering to purchase
an additional estimated 8% to 10% partial undivided interest in
the reserves in which we had, as of March 31, 2012, a
50.81% interest. See Business Developments
and Certain Relationships and Related Party
Transactions Membership Interest Purchase
Agreement. The actual percentage acquired will depend on
the fair value of the reserves at the time of the acquisition
and the net proceeds received in this offering. In addition, our
interest as a joint tenant in common with Armstrong Energy in
the majority of Armstrong Energys coal reserves could be
increased as a result of an additional acquisition through the
offset of unpaid deferred royalties owed to us.
We expect Armstrong Energy to continue to defer royalty payments
due to us and we do not plan to pay distributions to any of our
unitholders, except for amounts necessary to enable unitholders
to pay anticipated income tax liabilities, for the foreseeable
future. As a result, we expect to continue to acquire an
increasing percentage undivided interest in Armstrong
Energys coal reserves for the foreseeable future through
the offset of deferred royalties owed to us by Armstrong Energy.
We are a co-borrower under Armstrong Energys
$100.0 million term loan (the Senior Secured Term
Loan) and a guarantor on the $50.0 million revolving
credit facility (the Senior Secured Revolving Credit
Facility, and together with the Senior Secured Term Loan,
the Senior Secured Credit Facility) and the Senior
Secured Term Loan. Substantially all of our assets and Armstrong
Energys assets are pledged to secure
1
borrowings under the Senior Secured Credit Facility. Under the
terms of the Senior Secured Credit Facility, without the consent
of all lenders (if there are fewer than three lenders at the
time of any dividend or distribution) or the lenders having more
than 50% of the aggregate commitments (if there are three or
more lenders at the time of any dividend or distribution) under
that facility, we are currently prohibited from making dividend
payments or other distributions to our unitholders in excess of
$5.0 million per year and $10.0 million in aggregate,
except for dividends or other distributions in amounts necessary
to enable unitholders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership until
February 9, 2016, the date on which the Senior Secured
Credit Facility matures. We are not permitted to borrow
additional funds under the Senior Secured Credit Facility and as
such, it is not a source of liquidity for us.
A wholly owned subsidiary of Armstrong Energy, Inc., Elk Creek
GP, LLC (Elk Creek GP), is our general partner.
Pursuant to our Second Amended and Restated Agreement of Limited
Partnership, to be effective upon the closing of this offering
(the Partnership Agreement), Elk Creek GP has the
exclusive authority to conduct, direct and manage all of our
activities. By virtue of Armstrong Energys control of Elk
Creek, GP, our results are consolidated in Armstrong
Energys historical consolidated financial statements.
Pursuant to our existing partnership agreement, effective
October 1, 2011 (the Existing Partnership
Agreement), Yorktown unilaterally may remove Elk Creek GP
as our general partner in some circumstances. As a result,
Armstrong Energy will no longer consolidate our results in its
financial statements (the Deconsolidation).
2011 was the first year we recognized revenue under our
leases to Armstrong Energy. Based on its coal production during
2011 and the three months ended March 31, 2012, Armstrong
Energy is obligated to pay us $7.2 million and
$2.1 million, respectively, for production royalties under
our leases for such period. In addition, we earned a credit and
collateral support fee as a result of our financing activities
in the amount of $1.15 million and $0.3 million in
2011 and the three months ended March 31, 2012,
respectively.
The following table summarizes our coal reserves as of
December 31, 2011. All of our reserves are leased to
Armstrong Energy.
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Gross Clean Recoverable
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Tons
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Net Clean Recoverable Tons
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Quality Specifications (As
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(Proven and Probable
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(Proven and Probable
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Received)(2)
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Reserves)(1)
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Reserves)(1)
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Heat
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SO2
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Mining
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Proven
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Probable
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Proven
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Probable
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Value
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Content
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Ash
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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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Reserves
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Reserves
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Total
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(Btu/Lb)
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(Lbs/MMBtu)
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(%)
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(In thousands)
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(In thousands)
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Owned Reserves
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Elk Creek(4)
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U
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56,430
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8,985
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65,415
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56,430
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8,985
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65,415
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11,792
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4.5
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7.6
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Partially Owned Reserves
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Reserves in Active Production(5)
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Midway
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S
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19,377
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1,427
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20,805
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7,644
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563
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8,207
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11,315
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4.8
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10.0
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Parkway
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U
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7,535
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5,434
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12,969
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2,973
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2,144
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5,116
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11,931
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4.4
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7.1
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East Fork(6)
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S
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2,287
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550
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2,837
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902
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217
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1,119
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11,136
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7.6
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11.2
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Equality Boot
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S
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21,841
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1,151
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22,992
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(7)
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8,616
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454
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9,070
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11,587
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5.7
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8.8
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Lewis Creek
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S
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6,160
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101
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6,261
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2,430
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40
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2,470
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11,420
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4.0
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9.5
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Maddox
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S
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512
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512
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202
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202
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11,315
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4.8
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10.0
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Total Partially Owned Reserves in Active Production
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57,712
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8,663
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66,376
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22,767
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3,418
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26,185
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Additional Reserves
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ken
|
|
|
S
|
|
|
|
17,166
|
|
|
|
3,854
|
|
|
|
21,020
|
|
|
|
6,772
|
|
|
|
1,520
|
|
|
|
8,292
|
|
|
|
11,809
|
|
|
|
5.0
|
|
|
|
7.5
|
|
Other
|
|
|
S/U
|
|
|
|
40,145
|
|
|
|
12,016
|
|
|
|
52,159
|
(8)
|
|
|
15,837
|
|
|
|
4,740
|
|
|
|
20,578
|
|
|
|
11,300
|
|
|
|
4.5
|
|
|
|
8.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Additional Reserves
|
|
|
|
|
|
|
57,311
|
|
|
|
15,870
|
|
|
|
73,179
|
|
|
|
22,609
|
|
|
|
6,261
|
|
|
|
28,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
171,453
|
|
|
|
33,518
|
|
|
|
204,970
|
|
|
|
101,807
|
|
|
|
18,663
|
|
|
|
120,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Determined as of December 31, 2011. Gross amounts reflect
the combined 100% joint ownership interest of Armstrong Resource
Partners and Armstrong Energy in reserves in active production.
Net amounts |
2
|
|
|
|
|
reflect our 39.45% undivided interest in such jointly controlled
reserves which were acquired on February 9, 2011. Upon
completion of this offering, we intend to use the net proceeds
to us to acquire from Armstrong Energy an additional undivided
interest in certain of Armstrong Energys coal reserves.
See Use of Proceeds. 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. |
|
(2) |
|
Quality specifications displayed on an as received
basis, assuming 11% moisture. If derived from multiple seams,
data represents an average. |
|
(3) |
|
U = Underground; S = Surface |
|
(4) |
|
We commenced production at the Kronos underground mine in
September 2011. |
|
(5) |
|
Reserves that are in active production as of December 31,
2011. |
|
(6) |
|
Warden and Kronos surface pits. Production at the Kronos pit
ceased in August 2011. |
|
(7) |
|
Includes approximately 0.3 million tons related to reserves
for which Armstrong Energy owns or leases from us only a partial
joint interest and royalties on extractions may be payable to
other owners. |
|
(8) |
|
Includes approximately 1.9 million tons related to reserves
for which Armstrong Energy owns or leases from us only a partial
joint interest and royalties on extractions may be payable to
other owners. |
The following table summarizes the ownership status of our
reserves by mine as of December 31, 2011 and our
lessees historical production from our coal reserves. Our
acquisition of our ownership interest in these reserves became
effective February 9, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Clean Recoverable
|
|
|
|
|
|
|
|
|
|
|
|
Gross Production(2)
|
|
|
Net Production(2)
|
|
|
|
Tons
|
|
|
Net Clean Recoverable Tons
|
|
|
|
|
|
Year
|
|
|
|
|
|
Year
|
|
|
|
(Proven and Probable
|
|
|
(Proven and Probable
|
|
|
Year Ended
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
Reserves)(1)
|
|
|
Reserves)(1)
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
Reserve
|
|
Owned
|
|
|
Leased
|
|
|
Total
|
|
|
Owned
|
|
|
Leased
|
|
|
Total
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
(In thousands)
|
|
|
(In thousands)
|
|
|
(Tons in thousands)
|
|
|
(Tons in thousands)
|
|
|
Owned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Elk Creek(3)
|
|
|
61,890
|
|
|
|
3,525
|
|
|
|
65,415
|
|
|
|
61,890
|
|
|
|
3,525
|
|
|
|
65,415
|
|
|
|
|
|
|
|
|
(4)
|
|
|
|
|
|
|
|
|
Partially Owned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midway
|
|
|
20,805
|
|
|
|
|
|
|
|
20,805
|
|
|
|
8,207
|
|
|
|
|
|
|
|
8,207
|
|
|
|
1,614.8
|
|
|
|
1,589.2
|
|
|
|
637.0
|
|
|
|
626.9
|
|
Parkway
|
|
|
2,326
|
|
|
|
10,643
|
|
|
|
12,969
|
|
|
|
918
|
|
|
|
4,199
|
|
|
|
5,116
|
|
|
|
1,485.9
|
|
|
|
1,491.9
|
|
|
|
586.2
|
|
|
|
588.6
|
|
East Fork(5)
|
|
|
2,193
|
|
|
|
645
|
|
|
|
2,837
|
|
|
|
865
|
|
|
|
254
|
|
|
|
1,119
|
|
|
|
1,641.1
|
|
|
|
745.9
|
|
|
|
647.4
|
|
|
|
294.3
|
|
Equality Boot
|
|
|
22,992
|
|
|
|
|
|
|
|
22,992
|
(6)
|
|
|
9,070
|
|
|
|
|
|
|
|
9,070
|
|
|
|
330.8
|
|
|
|
1,916.8
|
|
|
|
130.5
|
|
|
|
756.2
|
|
Lewis Creek
|
|
|
6,261
|
|
|
|
|
|
|
|
6,261
|
|
|
|
2,470
|
|
|
|
|
|
|
|
2,470
|
|
|
|
|
|
|
|
474.9
|
|
|
|
|
|
|
|
187.4
|
|
Maddox
|
|
|
512
|
|
|
|
|
|
|
|
512
|
|
|
|
202
|
|
|
|
|
|
|
|
202
|
|
|
|
|
|
|
|
24.9
|
|
|
|
|
|
|
|
9.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Active
|
|
|
55,089
|
|
|
|
11,288
|
|
|
|
66,376
|
|
|
|
21,732
|
|
|
|
4,453
|
|
|
|
26,185
|
|
|
|
5,072.6
|
|
|
|
6,243.6
|
|
|
|
2,001.1
|
|
|
|
2,463.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ken
|
|
|
21,020
|
|
|
|
|
|
|
|
21,020
|
|
|
|
8,292
|
|
|
|
|
|
|
|
8,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
35,427
|
|
|
|
16,732
|
|
|
|
52,159
|
(7)
|
|
|
13,977
|
|
|
|
6,601
|
|
|
|
20,578
|
|
|
|
572.1
|
(8)
|
|
|
398.8
|
(8)
|
|
|
225.7
|
|
|
|
157.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Additional
|
|
|
56,447
|
|
|
|
16,732
|
|
|
|
73,179
|
|
|
|
22,269
|
|
|
|
6,601
|
|
|
|
28,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
173,426
|
|
|
|
31,545
|
|
|
|
204,970
|
|
|
|
105,891
|
|
|
|
14,579
|
|
|
|
120,470
|
|
|
|
5,644.7
|
|
|
|
6,642.4
|
|
|
|
2,226.8
|
|
|
|
2,620.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
Proven and probable reserves refers to coal that can
be economically extracted or produced at the time of the reserve
determination. |
|
(2) |
|
Determined as of December 31, 2011. Gross amounts reflect
the combined 100% joint ownership interest of Armstrong Resource
Partners and Armstrong Energy in reserves in active production.
Net production amounts reflect our 39.45% undivided interest in
such jointly controlled reserves as if we had this ownership
since January 1, 2010. Our actual proportion of sales began
in February 2011 and amounted to approximately 2.5 million
tons for the year ended December 31, 2011. Upon completion
of this offering, |
3
|
|
|
|
|
we intend to use the net proceeds to acquire from Armstrong
Energy an additional undivided interest in certain of Armstrong
Energys coal reserves. See Use of Proceeds. |
|
(3) |
|
Commenced production at the Kronos mine in September 2011. |
|
(4) |
|
The Kronos underground mine produced approximately
0.2 million tons of coal in 2011, but the production was
capitalized and not included in our results of operations
because the mine was still in the developmental phase. |
|
(5) |
|
Warden and Kronos surface pits. Production at the Kronos pit
ceased in August 2011. |
|
(6) |
|
Includes approximately 0.3 million tons related to
reserves for which Armstrong Energy owns or leases from us only
a partial joint interest and royalties on extractions may be
payable to other owners. |
|
(7) |
|
Includes approximately 1.9 million tons related to reserves
for which Armstrong Energy owns or leases from us only a partial
joint interest and royalties on extractions may be payable to
other owners. |
|
(8) |
|
Includes production from the Big Run mine, which ceased
operation in October 2011. |
On March 30, 2012, Armstrong Energy transferred an 11.36%
undivided interest in certain of its land and mineral reserves
to Armstrong Resource Partners in exchange for aggregate
consideration of $25.7 million. This increased Armstrong
Resource Partners interest in certain properties of
Armstrong Energy to 50.81%. See Business
Developments.
Royalty
Business
We are a royalty business. Royalty businesses principally own
and manage mineral reserves. As an owner of mineral reserves, we
typically are not responsible for operating mines, but instead
enter into leases with mine operators granting them the right to
mine and sell reserves from our property in exchange for a
royalty payment. A typical lease has a 5- to
10-year base
term, with the lessee having an option to extend the lease for
additional terms. Leases may include the right to renegotiate
rents and royalties for the extended term. At this time we have
a single lessee, Armstrong Energy, and each of the leases with
it has an initial term of 10 years.
Our royalty revenues are calculated based on a percentage of the
gross sales price of the aggregate tons of coal sold by a
lessee. Our royalty revenues are affected by changes in
long-term and spot commodity prices, sales volumes, our
lessees coal supply contracts with its customers and the
coal prices specified therein, and the royalty rates in our
lease. The prevailing price for coal depends on a number of
factors, including the supply-demand relationship, the price and
availability of alternative fuels, global economic conditions,
and governmental regulations.
We do not operate any mines, and thus we do not bear ordinary
operating costs and have limited direct exposure to
environmental, permitting, and labor risks because we do not
have any operations that could cause environmental damage, do
not have any permits which are subject to revocation and do not
have any employees or labor force. Instead, our lessee, as
operator, is subject to environmental laws, permitting
requirements, and other regulations adopted by various
governmental authorities. In addition, our lessee generally
bears all labor-related risks, including retiree health care
legacy costs, black lung benefits, and workers
compensation costs associated with operating the mines. However,
our royalty revenues may be negatively affected by any decreases
in our lessees production volumes and revenues due to
these risks. We typically pay property taxes and then are
reimbursed by our lessee for the taxes on its leased property
pursuant to the terms of the lease.
Our lessees 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 the
coal mined from our reserves. Adverse weather conditions, such
as floods or blizzards, can impact our lessees ability to
mine and ship our coal and its customers ability to take
delivery of coal.
Our lessee, Armstrong Energy, has historically deferred the
payment to us of cash royalties pursuant to a Royalty Deferment
and Option Agreement which it has entered into with us, and we
expect that Armstrong Energy will continue to make such
deferrals for the foreseeable future. Pursuant to the terms of
that Agreement, in the event that Armstrong Energy exercises its
deferral right we have the right to acquire additional undivided
4
interests in coal reserves controlled by Armstrong Energy. We
expect that for the foreseeable future all or a substantial
portion of our royalty revenues will be used by us to acquire
such additional coal reserve interests.
Coal
Leases
We earn our coal royalty revenues under long-term leases that
require our lessee to make royalty payments to us based on a
percentage of the gross sales price of the aggregate tons of
coal it sells.
In addition to the terms described above, our leases impose
obligations on our lessee to diligently mine the leased coal
using modern mining techniques, indemnify us for any damages we
incur in connection with the lessees mining operations,
including any damages we may incur on account of our
lessees failure to fulfill reclamation or other
environmental obligations, conduct mining operations in
compliance with all applicable laws, obtain our written consent
prior to assigning the lease, and maintain commercially
reasonable amounts of general liability and other insurance. The
leases grant us the right to review all lessee mining plans and
maps, enter the leased premises to examine mine workings, and
conduct audits of lessees compliance with lease terms. In
the event of default by our lessee, our leases give us the right
to terminate the lease and take possession of the leased
premises.
About
Armstrong Energy, Inc.
Armstrong Energy, Inc. was formed in 2006 to acquire and develop
a large coal mining operation. Armstrong Energy holds a 0.3%
equity interest in us through its wholly-owned subsidiary, Elk
Creek GP, which is our general partner. As of December 31,
2011, of Armstrong Energy, Inc.s total controlled reserves
of 326 million tons, 65 million tons (20%) are wholly
owned by us, and 140 million tons (43%) are held by
Armstrong Energy and us as joint
tenants-in-common
with 49.19% and 50.81% interests, respectively, and the balance
of the reserves Armstrong Energy controls are leased by
Armstrong Energy from a third party, and are not included in
Armstrong Resource Partners option to purchase an
additional interest.
Armstrong Energy markets its coal primarily to electric utility
companies as fuel for their steam-powered generators. Based on
2011 production, Armstrong Energy is the sixth largest producer
in the Illinois Basin and the second largest in Western
Kentucky. It commenced production in the second quarter of 2008
and currently operates seven mines, including five surface and
two underground, and is seeking permits for three additional
mines. Armstrong Energys revenue increased from zero in
2007 to $299.3 million in 2011. For the year ended
December 31, 2011, it produced 6.6 million tons of
coal, with seven mines in operation, and currently expects a
significant increase in its production for 2012 compared to
2011. During the three months ended March 31, 2012, it
produced 2.2 million tons of coal, with seven mines in
operation. The majority of the foregoing production is derived
from coal reserves in which we obtained an undivided interest
during 2011 and that Armstrong Energy now leases from us.
Business
Developments
In 2009 and 2010, Armstrong Energy borrowed an aggregate
principal amount of $44.1 million from us, 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 Armstrong Energys coal
reserves. Under the terms of these borrowings, we had the option
to acquire interests in coal reserves then held by Armstrong
Energy in Muhlenberg and Ohio Counties in satisfaction of the
loans we had made to Armstrong Energy. On February 9, 2011,
we exercised this option. In connection with that exercise, we
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 us, 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, we acquired a 39.45%
undivided interest as a joint tenant in common with Armstrong
Energy in the majority of its coal reserves, excluding its
reserves in Union and Webster Counties. The aggregate amount
paid by us to acquire our interest in these reserves was the
equivalent of approximately $69.5 million, which has been
included as a component of mineral rights, net and land in our
consolidated balance sheet as of December 31, 2011.
On February 9, 2011, Armstrong Energy entered into lease
agreements with us pursuant to which we granted Armstrong Energy
leases to our 39.45% undivided interest in the mining properties
described above and licenses to
5
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 us a production
royalty equal to 7% of the sales price of the coal which
Armstrong Energy mines from our properties. Under the terms of
these agreements, we retain 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 us when due and a
default by Armstrong Energy under any agreement, indenture or
other obligation to any creditor that, in our opinion, 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 we can
terminate one or more of the lease agreements. In addition,
Armstrong Energy has agreed to indemnify us 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.
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 by Armstrong Energy,
which represents the fair value of the assets transferred. As
noted above, the Deconsolidation was effective October 1,
2011. Subsequently, the long-term obligation will be reflected
on Armstrong Energys 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.
Effective February 9, 2011, Armstrong Energy entered into
an agreement with us pursuant to which we granted Armstrong
Energy the option to defer payment of the 7% production royalty
described above. In consideration for the granting of the option
to defer these payments, Armstrong Energy granted us 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 Armstrong Energy would satisfy payment of any deferred
royalties by selling part of its interest in the aforementioned
coal reserves to us at fair market value for such reserves
determined at the time of the exercise of such option.
On February 9, 2011, we also entered into a lease and
sublease agreement with Armstrong Energy relating to the 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
previously paid $12 million of advance royalties to us
which are recoupable against future production royalties,
subject to certain limitations.
Based upon Armstrong Energys current estimates of
production for 2012, we anticipate that Armstrong Energy will
owe us royalties under the above-mentioned license and lease
arrangements of approximately $14.8 million in 2012 of
which $5.6 million will be recoupable against the advance
royalty payment referred to above.
In December 2011, we 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 Energy pursuant to which Armstrong Energy agreed to
sell to us, indirectly through contribution of a partial
undivided interest in reserves to a limited liability company
and transfer of its membership interests in such limited
liability company, an additional partial undivided interest in
reserves controlled by Armstrong Energy. In exchange for
Armstrong Energys agreement to sell a partial undivided
interest in those reserves, we paid Armstrong Energy
$20.0 million. In addition to the cash paid, certain
amounts due to us totaling $5.7 million were forgiven by
Armstrong Energy, which resulted in aggregate consideration of
$25.7 million. This transaction, which closed in March
2012, resulted in the transfer by Armstrong Energy of an 11.36%
undivided interest in certain of its land and mineral reserves
to us. We agreed to lease the newly transferred mineral reserves
to Armstrong Energy on the same terms as the February 2011
lease. As of March 31, 2012, we had a 50.81% undivided
interest in certain of the land and mineral reserves of
Armstrong Energy.
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Concurrent
Offering
Concurrent with this offering of common units, Armstrong Energy,
Inc. is offering its common stock pursuant to a separate initial
public offering (the Concurrent AE Offering).
Armstrong Energy indirectly holds a 0.3% equity interest in us.
See Business Our Organizational History.
If the Concurrent AE Offering and the related transactions
between Armstrong Resource Partners and Armstrong Energy are
completed, we expect that Armstrong Energy will use
approximately $40.0 million of the net proceeds from the
Concurrent AE Offering to repay a portion of Armstrong
Energys outstanding borrowings under its Senior Secured
Term Loan, and that it will use the balance to repay a portion
of its outstanding borrowings under the Senior Secured Revolving
Credit Facility and for general corporate purposes, including to
fund capital expenditures relating to Armstrong Energys
mining operations and working capital. See Description of
Indebtedness and Certain Relationships and Related
Party Transactions Concurrent Transactions with
Armstrong Energy. While Armstrong Energy intends to
consummate the Concurrent AE Offering simultaneously with this
offering of common units, the completion of this offering is not
subject to the completion of the Concurrent AE Offering and the
completion of the Concurrent AE Offering is not subject to the
completion of this offering. This description and other
information in this prospectus regarding the Concurrent AE
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 stock of Armstrong Energy, Inc.
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
2011, 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 42% of all
electricity generation in the United States in 2011. On a
long-term basis, 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 coal-fired generation
will continue to remain the largest single source of electricity
generation in 2035, at 39% of total generation by 2035, compared
to approximately 42% during 2011.
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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 48% from 2010 through 2015
and by 108% from 2010 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 12%
increase in flue gas desulfurization (FGD) installed
on the coal-fired generation fleet from 199 gigawatts in 2010 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 new
mercury and air toxics standards (MATS) for power
plants. Currently, the EIA estimates that approximately 63% of
all U.S. coal-fired generation capacity has FGD technology
installed or under construction. 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 115 million tons in 2011 to
64 million tons in 2015, due to reserve depletion,
regulatory-driven decreases in Central
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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 2011 and is projected
to rise from 921 million tons in 2011 to 1.1 billion
tons by 2017. 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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Strategy
Our primary business strategy is to enhance unitholder value by
executing the following strategies:
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Continue to grow our interest in our coal reserve holdings
through additional investments in our existing proven and
probable reserves. 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. Pursuant to the terms of a Royalty Deferment and
Option Agreement with our sole lessee, Armstrong Energy, we have
the right to acquire additional undivided interests in coal
reserves controlled by Armstrong Energy in the event that
Armstrong defers cash payment to us for royalties due. We expect
that for the foreseeable future all or a substantial portion of
our royalty revenues will be used by us to acquire additional
coal reserve interests and will not be a source of cash for the
payment of dividends or other distributions to our unitholders.
Except for distributions in amounts necessary to enable
unitholders to pay anticipated income tax liabilities arising
from their ownership interests in the Partnership, which will be
paid, if at all, solely at the discretion of Elk Creek GP, our
general partner, we do not anticipate paying any distributions
for the foreseeable future.
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Expand and diversify our coal reserve
holdings. We will consider opportunities to
expand our reserves through acquisitions of additional coal
reserves in the Illinois Basin. We will consider acquisitions of
coal reserves that are high quality, long-lived and that are of
sufficient size to yield significant production or serve as a
platform for complementary acquisitions.
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Pursue additional royalty opportunities. We
intend to pursue opportunities to maximize qualifying income
from royalty based arrangements. We plan to pursue royalty
opportunities that are complementary to our existing asset base.
Additionally, we may also seek opportunities in new royalty or
qualifying income producing business lines to the extent that we
can utilize our existing infrastructure, relationships and
expertise.
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Competitive
Strengths
We believe that the following competitive strengths will enable
us to effectively execute our business strategy:
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Our lessee has a demonstrated track record for successfully
completing reserve acquisitions, securing required permits,
developing new mines and producing coal. Since
Armstrong Energys formation in 2006, it has successfully
acquired coal reserves and opened eight 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 its market
area. We believe this resulted from Armstrong Energys deep
management experience and disciplined approach to the
development of its
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operations and its focus on providing competitively priced
Illinois Basin coal. We believe this will enable Armstrong
Energy to continue to grow its 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, 2011, we either owned or had an interest in
approximately 205 million tons of clean recoverable (proven
and probable) coal reserves. Our reserves represent underground
mineable coal, which, in combination with our lessees coal
processing facilities, enhance our lessees ability to meet
its customers requirements for blends of coal with
different characteristics. Further, the comparatively low
chlorine content of our coal relative to other Illinois Basin
coal provides our lessee with an additional competitive
advantage in meeting the desired coal fuel profile of its
customers.
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Our reserves are strategically located to allow access to
multiple transportation options for delivery. Our
lessees mines are located adjacent to the Green River and
near its preparation, loading, and transportation facilities,
providing its customers with rail, barge, and truck
transportation options. In addition, our lessee has invested in
the potential construction of a coal export terminal along the
Mississippi Riverfront south of New Orleans. We believe this
will also enable Armstrong Energy to sell our coal in both the
domestic and export markets.
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We are well-positioned to pursue additional reserve
acquisitions. Our management team has
successfully acquired and integrated properties. Since 2008, we
have acquired over 120 million tons of proven and probable
reserves.
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We have a highly experienced management team with a long
history of acquiring, building and operating coal
businesses. We do not have any officers or
directors. We are managed and operated by the board of directors
and executive officers of Armstrong Energy, Inc., the parent
corporation of our general partner, Elk Creek GP. The members of
Armstrong Energys senior management team have a
demonstrated track record of acquiring, building and operating
coal businesses profitably and safely. In addition, members of
Armstrong Energys senior management team have significant
experience managing the financial and organizational growth of
businesses, including public companies.
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Management
and Relationship with Armstrong Energy
We do not have any officers or directors. We are managed and
operated by the board of directors and executive officers of
Armstrong Energy, Inc., the parent corporation of our general
partner, Elk Creek GP.
The following chart depicts the organization and ownership of
Armstrong Resource Partners, L.P. prior to giving effect to the
offering of common units being made hereby or to the Concurrent
AE Offering, but
9
assuming conversion of our Series A convertible preferred
units and conversion of Armstrong Energys Series A
preferred stock:
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Reserves owned solely by Armstrong Resource Partners. These
include the reserves assigned to our Kronos and Lewis Creek
underground mines. |
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Reserves controlled jointly by Armstrong Resource Partners (with
a 50.81% undivided interest as of March 31, 2012) and
Armstrong Energy (with a 49.19% undivided interest as of
March 31, 2012). If this offering and the Concurrent AE
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 this 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 Energy. |
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The following chart depicts the organization and ownership of
Armstrong Resource Partners, L.P. after giving effect to the
offering of common units being made hereby and the Concurrent AE
Offering.
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Reserves owned solely by Armstrong Resource Partners. These
include the reserves assigned to our Kronos and Lewis Creek
underground mines. |
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Reserves controlled jointly by Armstrong Resource Partners and
Armstrong Energy. Assuming an offering price of
$ per unit, the midpoint of the
price range set forth on the front cover page of this
prospectus, and an estimated purchase price of
$17.5 million for our additional interest in the partially
owned reserves, we intend to acquire an additional estimated 8%
to 10% partial undivided interest in certain reserves of
Armstrong Energy with the net proceeds from this offering. The
actual percentage acquired will depend on the fair value of the
reserves at the time of the acquisition and the net proceeds
received in this offering. In addition, our interest as a joint
tenant in common with Armstrong Energy in the majority of
Armstrong Energys coal reserves could be increased as a
result of an additional acquisition through the offset of unpaid
deferred royalties owed to us. |
Partnership
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.armstrongresourcepartners.com. Information on, or accessible
through, our website is not part of, or incorporated by
reference in, this prospectus. We are organized under the laws
of the State of Delaware.
Cash
Distribution Policy and Restrictions on Dividends
Pursuant to our Partnership Agreement, within 45 days
following the end of each quarter, we may, in our sole and
exclusive discretion, distribute an amount equal to some or all
of our available cash to unitholders of record on the applicable
record date. The payment of distributions, if any, is solely
within the discretion of Elk Creek GP, our general partner.
However, the Senior Secured Credit Facility restricts our
ability to pay distributions. Under the terms of the Senior
Secured Credit Facility, without the consent of all lenders (if
there are fewer than three lenders at the time of any dividend
or distribution) or the lenders having more than 50% of the
aggregate commitments
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(if there are three or more lenders at the time of any dividend
or distribution) under that facility, we are currently
prohibited from making dividend payments or other distributions
to our unitholders in excess of $5.0 million per year and
$10.0 million in aggregate, except for dividends or other
distributions in amounts necessary to enable unitholders to pay
anticipated income tax liabilities arising from their ownership
interests in the Partnership until February 9, 2016, the
date on which the Senior Secured Credit Facility matures.
Our lessee, Armstrong Energy, has historically deferred the
payment to us of cash royalties pursuant to a Royalty Deferment
and Option Agreement which it has entered into with us, and we
expect that Armstrong Energy will continue to make such
deferrals for the foreseeable future. Pursuant to the terms of
that Agreement, in the event that Armstrong Energy exercises its
deferral right, we have the right to acquire additional
undivided interests in coal reserves controlled by Armstrong
Energy. We expect that for the foreseeable future all or a
substantial portion of our royalty revenues will be used by us
to acquire such additional coal reserve interests and will not
be a source of cash for the payment of dividends or other
distributions to our unitholders.
Except for distributions in amounts necessary to enable
unitholders to pay anticipated income tax liabilities arising
from their ownership interests in the Partnership, which will be
paid, if at all, solely at the discretion of Elk Creek, GP, our
general partner, we do not anticipate paying any distributions
for the foreseeable future.
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.
Yorktown is the largest owner of our limited partnership
interests and is also the largest shareholder of Armstrong
Energy, Inc. Bryan H. Lawrence, founder and principal of
Yorktown Partners LLC, is also a board member of Armstrong
Energy. 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 to
Armstrong Energys board, the adoption or amendment of
provisions in Armstrong Energys charter and bylaws, the
approval of mergers, and other significant corporate
transactions that may affect us because we are managed by
Armstrong Energys directors and executive officers. See
Risk Factors.
Conflicts
of Interest and Fiduciary Duties
General. Conflicts of interest exist and may
arise in the future as a result of the relationships between
Armstrong Energy and its affiliates (including our general
partner) on the one hand, and our Partnership and our
unitholders, on the other hand. The directors and officers of
Armstrong Energy have fiduciary duties to manage its affiliates,
including our general partner, in a manner beneficial to its
owners. At the same time, Armstrong Energy, through control of
our general partner, Elk Creek GP, has a fiduciary duty to
manage our Partnership in a manner beneficial to us and our
unitholders.
Whenever a conflict arises between Armstrong Energy and its
affiliates, on the one hand, and our Partnership or any other
partner, on the other, Armstrong Energy will resolve that
conflict. Armstrong Energy may, but is not required to, seek
approval of such resolution from the conflicts committee of
Armstrong Energys board of directors. Delaware law
provides that Delaware limited partnerships may, in their
partnership agreements, restrict or expand the fiduciary duties
owed by the general partner or other managing entity to limited
partners and the partnership. Our Partnership Agreement limits
the liability of, and reduces the fiduciary duties owed by, our
general partner and Armstrong Energy to our common unitholders.
Our Partnership Agreement also restricts the remedies available
to our unitholders for actions that might otherwise constitute a
breach of fiduciary duty by our general partner or Armstrong
Energy. By purchasing a common unit, a unitholder is treated as
having consented to various actions and potential conflicts of
interest contemplated in the Partnership Agreement that might
otherwise be considered a breach of fiduciary duty or other
duties under applicable state law.
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For a more detailed description of the conflicts of interest and
the fiduciary duties of our general partner and Armstrong
Energy, please read Conflicts of Interest and Fiduciary
Duties. For a description of other relationships with our
affiliates, please read Certain Relationships and Related
Party Transactions.
Armstrong Energy will not be in breach of its obligations under
the Partnership Agreement or its duties to us or our unitholders
if the resolution of the conflict is considered to be fair and
reasonable to us. Any resolution is considered to be fair and
reasonable to us if that resolution is:
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approved by the conflicts committee, although Armstrong Energy
is not obligated to seek such approval and Armstrong Energy may
adopt a resolution or course of action that has not received
approval;
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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fair to us, taking into account the totality of the
relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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In resolving a conflict, Armstrong Energy, including its
conflicts committee, may, unless the resolution is specifically
provided for in the Partnership Agreement, consider:
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the relative interests of any party to such conflict and the
benefits and burdens relating to such interest;
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any customary or accepted industry practices or historical
dealings with a particular person or entity;
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generally accepted accounting practices or principles; and
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such additional factors it determines in its sole discretion to
be relevant, reasonable or appropriate under the circumstances.
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Conflicts of interest could arise in the situations described
below, among others.
Actions taken by Armstrong Energy may affect the amount of
cash available for distribution to unitholders.
The amount of cash that is available for distribution to
unitholders is affected by decisions of Armstrong Energy
regarding such matters as:
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the volume of coal production and the royalties generated from
our reserves;
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the prices at which coal sales are made, and thereby the royalty
revenues generated by the leased coal reserves;
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the election to defer the payment of any royalties pursuant to
the Royalty Deferment and Option Agreement with Western Mineral
Development, LLC, our wholly owned subsidiary (Western
Mineral), (see Certain Relationships and Related
Party Transactions Royalty Deferment and Option
Agreement);
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Armstrong Energys agreement with coal customers to defer
or reschedule contractually committed coal sales;
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decisions by Armstrong Energy to idle or close any operation due
to market conditions, force majeure, or for other operating
reasons;
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amount and timing of asset purchases and sales;
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cash expenditures;
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borrowings; and
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the issuance of additional common units.
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In addition, borrowings by us and our affiliates do not
constitute a breach of any duty owed by us or Armstrong Energy
to the unitholders.
The Partnership Agreement provides that we and our subsidiaries
may borrow funds from Armstrong Energy and its affiliates.
Armstrong Energy and its affiliates may borrow funds from us or
our subsidiaries.
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We do not have any officers or employees and rely solely
on officers and employees of Armstrong Energy, Inc. and its
affiliates.
We do not have any officers or employees and rely solely on
officers and employees of Armstrong Energy, Inc. and its
affiliates. Affiliates of Armstrong Energy conduct businesses
and activities of their own in which we have no economic
interest. If these separate activities are significantly greater
than our activities, there could be material competition for the
time and effort of the officers and employees who provide
services to Armstrong Energy. The officers of Armstrong Energy
are not required to work full time on our affairs. These
officers devote significant time to the affairs of Armstrong
Energy and its affiliates and are compensated by these
affiliates for the services rendered to them.
Restrictions in or a failure by our lessee to comply with
the terms of the Senior Secured Credit Facility, on which we
serve as co-borrower with respect to the Senior Secured Term
Loan and guarantor with respect to the Senior Secured Revolving
Credit Facility and the Senior Secured Term Loan, could
adversely affect our business, financial condition, results of
operations, ability to make distributions to unitholders and
value of our common units.
The Senior Secured Credit Facility limits our ability to, among
other things:
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incur additional debt;
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make distributions on or redeem or repurchase common units;
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make certain investments and acquisitions;
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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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merge or consolidate with another company; and
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transfer or otherwise dispose of assets.
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The Senior Secured Credit Facility also contains covenants
requiring us to maintain certain financial ratios. Please read
Description of Indebtedness.
The Senior Secured Credit Facility restricts our ability to pay
distributions. Except for distributions in amounts necessary to
enable unitholders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership, which
will be paid, if at all, solely at the discretion of Elk Creek
GP, our general partner, we do not anticipate paying any
distributions for the foreseeable future. In addition, we are
unable to pay distributions until the restrictions on
distributions by us to our limited partners imposed by the
Senior Secured Credit Facility have been lifted. See Cash
Distribution Policy and Restrictions on Distributions.
In addition, the provisions of the Senior Secured Credit
Facility may affect our ability to obtain future financing and
pursue attractive business opportunities and our flexibility in
planning for, and reacting to, changes in business conditions. A
failure to comply with the provisions of the Senior Secured
Credit Facility could result in a default or an event of default
that could enable our lenders to declare the outstanding
principal of that debt, together with accrued and unpaid
interest, to be immediately due and payable. If the payment of
the debt is accelerated, our assets may be insufficient to repay
such debt in full, and our unitholders could experience a
partial or total loss of their investment.
We are not permitted to borrow additional funds under the Senior
Secured Credit Facility and as such, it is not a source of
liquidity for us.
We reimburse Armstrong Energy and its affiliates for
expenses.
We reimburse Armstrong Energy and its affiliates for costs
incurred in managing and operating us, including costs incurred
in rendering corporate staff and support services to us.
Armstrong Energy determines the expenses that are allocable to
us in any reasonable manner determined by Armstrong Energy in
its sole discretion.
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Armstrong Energy intends to limit its liability regarding
our obligations.
Armstrong Energy intends to limit its liability under
contractual arrangements so that the other party has recourse
only to our assets, and not against Armstrong Energy or its
assets. The Partnership Agreement provides that any action taken
by Armstrong Energy to limit its liability or our liability is
not a breach of Armstrong Energys fiduciary duties, even
if we could have obtained more favorable terms without the
limitation on liability.
Unitholders have no right to enforce obligations of
Armstrong Energy and its affiliates under agreements with
us.
Any agreements between us on the one hand, and Armstrong Energy
and its affiliates, on the other, do not grant to the
unitholders, separate and apart from us, the right to enforce
the obligations of Armstrong Energy and its affiliates in our
favor and Armstrong Energy has the power and authority to
conduct our business without unitholder or conflict committee
approval, on such terms as it determines to be necessary or
appropriate.
Contracts between us, on the one hand, and Armstrong
Energy and its affiliates, on the other, are not the result of
arms-length negotiations.
The Partnership Agreement allows Armstrong Energy to pay itself
or its affiliates for any services rendered to us, provided
these services are rendered on terms that are fair and
reasonable. Armstrong Energy may also enter into additional
contractual arrangements with any of its affiliates on our
behalf. Neither the Partnership Agreement nor any of the other
agreements, contracts and arrangements between us, on the one
hand, and Armstrong Energy and its affiliates, on the other, are
the result of arms-length negotiations.
We may not choose to retain separate counsel for ourselves
or for the holders of common units.
The attorneys, independent auditors and others who have
performed services for us in the past were retained by Armstrong
Energy, its affiliates and us and have continued to be retained
by Armstrong Energy, its affiliates and us. Attorneys,
independent auditors and others who perform services for us are
selected by Armstrong Energy or the conflicts committee and may
also perform services for Armstrong Energy and its affiliates.
We may retain separate counsel for ourselves or the holders of
common units in the event of a conflict of interest arising
between Armstrong Energy and its affiliates, on the one hand,
and us or the holders of common units, on the other, depending
on the nature of the conflict. We do not intend to do so in most
cases.
Elk Creek GP, Armstrong Energy, and their respective
affiliates may compete with us.
The Partnership Agreement provides that Elk Creek GP, Armstrong
Energy, and their respective affiliates will not be prohibited
from engaging in activities in which they compete directly with
us.
Director
Independence
For a discussion of the independence of the members of the board
of directors of Armstrong Energy under applicable standards,
please read Management Board of Directors and
Board Committees.
Review,
Approval or Ratification of Transactions with Related
Persons
If a conflict or potential conflict of interest arises between
Armstrong Energy and its affiliates (including our general
partner) on the one hand, and our Partnership and our limited
partners, on the other hand, the resolution of any such conflict
or potential conflict is addressed as described under
Conflicts of Interest.
For a description of our other relationships with our
affiliates, please read Certain Relationships and Related
Party Transactions.
Emerging
Growth Company Status
We are an emerging growth company, as defined in
Section 2(a)(19) of the Securities Act of 1933, as amended (the
Securities Act), as modified by the Jumpstart Our
Business Startups Act of 2012 (the JOBS
15
Act). As such, we are eligible to take advantage of
certain exemptions from various reporting requirements that are
applicable to other public companies that are not emerging
growth companies including, but not limited to, not being
required to comply with the auditor attestation requirements of
Section 404 of the Sarbanes-Oxley Act of 2002 (the
Sarbanes-Oxley Act), reduced disclosure obligations
regarding executive compensation in our periodic reports. We
have not made a decision whether to take advantage of these
exemptions.
In addition, Section 107 of the JOBS Act also provides that an
emerging growth company can take advantage of the
extended transition period provided in Section 7(a)(2)(B) of the
Securities Act for complying with new or revised accounting
standards. However, we are choosing to opt out of any extended
transition period, and as a result, we will comply with new or
revised accounting standards on the relevant dates on which
adoption of such standards is required for non-emerging growth
companies. Section 107 of the JOBS Act provides that our
decision to opt out of the extended transition period for
complying with new or revised accounting standards is
irrevocable.
We could remain an emerging growth company for up to
five years, or until the earliest of (a) the last day of the
first fiscal year in which our annual gross revenues exceed $1
billion, (b) the date that we become a large accelerated
filer as defined in Rule 12b-2 under the Securities
Exchange Act of 1934, as amended (the Exchange Act),
which would occur if the market value of our common units that
are held by non-affiliates exceeds $700 million as of the last
business day of our most recently completed second fiscal
quarter, or (c) the date on which we have issued more than $1
billion in non-convertible debt during the preceding three-year
period.
16
The
Offering
The following summary contains basic information about this
offering and the common units 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 our common units, we encourage you to read
this entire prospectus, including, without limitation, the
sections of this prospectus entitled Risk Factors
and Description of the Common Units, and the
documents attached to this prospectus.
|
|
|
Common Units Offered to the Public |
|
common units. |
|
|
|
Over-Allotment Option |
|
We have granted the underwriters an option to purchase up to an
additional common units, equal to
10% of the common units offered in this offering, at the public
offering price, less the underwriters discount, within
30 days after the date of this prospectus. |
|
|
|
Units to be Outstanding Immediately After this Offering
|
|
12,461,977 common units (or 12,561,977 common units if the
underwriters exercise in full their over-allotment option) and
38,023 general partner units held by our general partner. |
|
Units Held by Our Existing Unitholders Immediately After this
Offering
|
|
11,461,977 common units (or 11,461,977 common units if the
underwriters exercise in full their over-allotment option) and
38,023 general partner units held by our general partner. |
|
|
|
Use of Proceeds |
|
We expect to receive net proceeds from this offering of
approximately $17.5 million (or approximately
$19.4 million if the underwriters exercise in full their
option to purchase additional units) after deducting estimated
underwriting discounts and commissions, and after our offering
expenses estimated at $1.1 million, assuming the units are
offered at $ per unit, which is the
midpoint of the estimated offering price range shown on the
front cover page of this prospectus. We intend to use the net
proceeds from this offering of approximately $17.5 million
to purchase an additional partial undivided interest in
substantially all of the coal reserves and real property owned
by Armstrong Energy previously subject to options exercised by
us on February 9, 2011. See Certain Relationships and
Related Party Transactions Western Diamond and
Western Land Coal Reserves Sale Agreement. See Use
of Proceeds and Description of Indebtedness. |
|
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Cash Distributions |
|
Pursuant to the terms of our Partnership Agreement, within
45 days following the end of each quarter, we may, in our
sole and exclusive discretion, distribute an amount equal to
some or all of our available cash (as defined in the
Partnership Agreement) to unitholders of record on the
applicable record date. The payment of distributions, if any, is
solely within the discretion of Elk Creek GP. |
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However, the Senior Secured Credit Facility restricts our
ability to pay distributions. Under the terms of the Senior
Secured Credit Facility, without the consent of all lenders (if
there are fewer than three lenders at the time of any dividend
or distribution) or the lenders having more than 50% of the
aggregate commitments (if there are three or more lenders at the
time of any dividend or distribution) under that facility, we
are currently prohibited from making dividend payments or other
distributions to our unitholders in |
17
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excess of $5.0 million per year and $10.0 million in
aggregate, except for dividends or other distributions in
amounts necessary to enable unitholders to pay anticipated
income tax liabilities arising from their ownership interests in
the Partnership until February 9, 2016, the date on which
the Senior Secured Credit Facility matures. |
|
|
|
Our lessee, Armstrong Energy, has historically deferred the
payment to us of cash royalties pursuant to a Royalty Deferment
and Option Agreement which it has entered into with us, and we
expect that Armstrong Energy will continue to make such
deferrals for the foreseeable future. Pursuant to the terms of
that Agreement, in the event that Armstrong Energy exercises its
deferral right, we have the right to acquire additional
undivided interests in coal reserves controlled by Armstrong
Energy. We expect that for the foreseeable future all or a
substantial portion of our royalty revenues will be used by us
to acquire such additional coal reserve interests and will not
be a source of cash for the payment of dividends or other
distributions to our unitholders. |
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|
Except for distributions in amounts necessary to enable
unitholders to pay anticipated income tax liabilities arising
from their ownership interests in the Partnership, which will be
paid, if at all, solely at the discretion of Elk Creek, GP, our
general partner we do not anticipate paying any distributions
for the foreseeable future. |
|
Issuance of Additional Common Units |
|
Our general partner may issue additional common units, and you
will have no preemptive right to purchase such common units. |
|
Voting Rights |
|
Unlike holders of common stock in a corporation, you will have
only limited voting rights on matters affecting our business.
You will have no right to elect our general partner or the
directors of its parent corporation on an annual or other
regular basis. Yorktown unilaterally may remove our general
partner in some circumstances. Please read
Withdrawal or Removal of the General
Partner. |
|
Proposed Symbol |
|
ARPS |
Except as otherwise indicated, information in this prospectus
reflects or assumes the following:
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a 7.6047-to-1 unit split of our common units and general
partner units to be effected prior to the effectiveness of the
registration statement of which this prospectus forms a part;
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the automatic conversion of all of our outstanding Series A
convertible preferred units into an aggregate of 1,068,376
common units which we expect will occur immediately subsequent
to the completion of this offering, at an assumed initial public
offering price of $ per unit, which
is the midpoint of the price range set forth on the cover of
this prospectus, as described above; and
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no exercise of the underwriters option to purchase up to
an additional common units.
|
Risk
Factors
Investing in our common units involves a high degree of risk.
You should carefully consider the following risk factors, those
other risks described in Risk Factors, and the other
information in this prospectus, before
18
deciding whether to invest in our common units. The following
risks are discussed in more detail in Risk Factors
beginning on page 22:
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Cash distributions are not guaranteed and may fluctuate with our
performance and the establishment of financial reserves and at
the discretion of our general partner.
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We may not have sufficient cash to enable us to pay any
distributions.
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Cost reimbursements due to our general partner may be
substantial and will reduce our cash available for distribution
to unitholders.
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Unitholders other than Yorktown may not remove our general
partner even if they wish to do so.
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The fiduciary duties of officers and managers of Elk Creek GP,
as general partner of Armstrong Resource Partners, L.P., may
conflict with those of officers and directors of Armstrong
Energy.
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Our partnership agreement limits our general partners
fiduciary duties to our unitholders and restricts the remedies
available to our unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
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|
Armstrong Energys board of directors may change the
management and allocation policies relating to Armstrong
Resource Partners without the approval of our unitholders.
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Holders of our common units may not have any remedies if any
action by Armstrong Energys directors or officers in
relation to Armstrong Energy has an adverse effect on only
Armstrong Resource Partners common units.
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|
Yorktown will continue to have significant influence over us,
including control over decisions that require the approval of
unitholders, which could limit your ability to influence the
outcome of key transactions, including a change of control.
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|
Conflicts of interest could arise among our general partner and
us or the unitholders.
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Our unitholders share of our income will be taxable to
them for federal income tax purposes even if they do not receive
any cash distributions from us.
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Restrictions in or a failure by our lessee to comply with the
terms of the Senior Secured Credit Facility, on which we serve
as co-borrower with respect to the Senior Secured Term Loan and
guarantor with respect to the Senior Secured Revolving Credit
Facility and the Senior Secured Term Loan, could adversely
affect our business, financial condition, results of operations,
ability to make distributions to unitholders and value of our
common units.
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Our lessee could satisfy obligations to its customers with coal
from properties other than ours, depriving us of the ability to
receive royalty payments.
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19
Summary
Historical 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 Resource Partners, L.P.
and its subsidiaries. The summary historical financial data for
the years ended December 31, 2009, 2010 and 2011 and the
balance sheet data as of December 31, 2009, 2010 and 2011
are derived from our audited financial statements included
herein. The summary historical financial data for the three
months ended March 31, 2012 and 2011 and the balance sheet
data as of March 31, 2012 and 2011 are derived from our
unaudited financial statements provided herein.
Historical results and unaudited pro forma consolidated
financial information are for illustrative and informational
purposes only and are not necessarily indicative of results we
expect in future periods. You should read the following summary
with Selected Historical Consolidated Financial and
Operating Data, Managements Discussion and
Analysis of Financial Condition and Results of Operations,
and our financial statements and related notes appearing
elsewhere in this prospectus.
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|
|
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|
|
|
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|
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Three Months
|
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|
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Year Ended December 31,
|
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Ended March 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
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|
(In thousands, except per unit amounts)
|
|
|
Results of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,789
|
|
|
$
|
1,238
|
|
|
$
|
3,081
|
|
Costs and expenses
|
|
|
330
|
|
|
|
817
|
|
|
|
7,605
|
|
|
|
802
|
|
|
|
4,717
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(330
|
)
|
|
|
(817
|
)
|
|
|
184
|
|
|
|
436
|
|
|
|
(1,636
|
)
|
Interest expense
|
|
|
(1,723
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
161
|
|
|
|
4,209
|
|
|
|
1,009
|
|
|
|
1,009
|
|
|
|
|
|
Other income (expense), net
|
|
|
(2
|
)
|
|
|
(60
|
)
|
|
|
1,148
|
|
|
|
162
|
|
|
|
256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(1,894
|
)
|
|
$
|
3,332
|
|
|
$
|
2,341
|
|
|
$
|
1,607
|
|
|
$
|
(1,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Earnings (loss) per limited partner unit, basic, without giving
effect to the unit split
|
|
$
|
(2.62
|
)
|
|
$
|
2.96
|
|
|
$
|
1.74
|
|
|
$
|
1.20
|
|
|
$
|
(1.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Earnings (loss) per limited partner unit, diluted, without
giving effect to the unit split
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|
$
|
(2.62
|
)
|
|
$
|
2.96
|
|
|
$
|
1.73
|
|
|
$
|
1.20
|
|
|
$
|
(1.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per limited partner unit, basic and diluted,
assuming unit split(1)
|
|
$
|
(0.34
|
)
|
|
$
|
0.39
|
|
|
$
|
0.23
|
|
|
$
|
1.60
|
|
|
$
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Balance Sheet Data (at period end)
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total assets
|
|
$
|
91,097
|
|
|
$
|
137,929
|
|
|
$
|
167,559
|
|
|
$
|
144,623
|
|
|
$
|
166,037
|
|
Working capital
|
|
|
215
|
|
|
|
155
|
|
|
|
619
|
|
|
|
155
|
|
|
|
651
|
|
Total debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
89,497
|
|
|
|
125,929
|
|
|
|
156,181
|
|
|
|
132,536
|
|
|
|
155,278
|
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Royalty coal tons sold by lessee (unaudited)
|
|
|
|
|
|
|
|
|
|
|
2,717
|
|
|
|
458
|
|
|
|
1,012
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
(308
|
)
|
|
$
|
13,792
|
|
|
$
|
8,007
|
|
|
$
|
2,221
|
|
|
$
|
2,095
|
|
Investing activities
|
|
|
(12,424
|
)
|
|
|
(46,892
|
)
|
|
|
(33,007
|
)
|
|
|
(7,221
|
)
|
|
|
339
|
|
Financing activities
|
|
|
12,722
|
|
|
|
33,100
|
|
|
|
25,000
|
|
|
|
5,000
|
|
|
|
(2,434
|
)
|
EBITDA (unaudited)(2)
|
|
|
(332
|
)
|
|
|
(877
|
)
|
|
|
8,084
|
|
|
|
1,212
|
|
|
|
3,086
|
|
EBITDA is calculated as follows (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(1,894
|
)
|
|
$
|
3,332
|
|
|
$
|
2,341
|
|
|
$
|
1,607
|
|
|
$
|
(1,380
|
)
|
Depletion
|
|
|
|
|
|
|
|
|
|
|
3,841
|
|
|
|
614
|
|
|
|
1,555
|
|
Unit-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
2,911
|
|
|
|
|
|
|
|
2,911
|
|
Interest, net
|
|
|
1,562
|
|
|
|
(4,209
|
)
|
|
|
(1,009
|
)
|
|
|
(1,009
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(332
|
)
|
|
$
|
(877
|
)
|
|
$
|
8,084
|
|
|
$
|
1,212
|
|
|
$
|
3,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
|
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|
(1) |
|
Per unit calculation reflects the assumed 7.6047-to-1 unit split
to be effected prior to the effectiveness of the registration
statement of which this prospectus forms a part. |
|
(2) |
|
EBITDA is a non-GAAP financial measure, and when analyzing our
operating performance, investors should use 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 EBITDA as a supplemental financial measure. EBITDA is
defined as net income (loss) before interest, net, unit
compensation expense and depletion. |
|
|
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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 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 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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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 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.
|
21
RISK
FACTORS
An investment in our common units involves significant risks.
Common units representing limited partner interests are
inherently different from the capital stock of a corporation,
although many of the business risks to which we are subject are
similar to those that would be faced by a corporation engaged in
a similar business. In addition to matters described elsewhere
in this prospectus, you should carefully consider the following
risks involved with an investment in our common units. 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 units or
our business and operating results. If that occurs, the value of
our common units could decline and you could lose some or all of
your investment.
Risks
Related to Our Business
We
depend on one lessee, Armstrong Energy, for all of our revenues.
If Armstrong Energy does not manage its operations well, its
production volumes and our coal royalty revenues could
decrease.
We depend on a sole lessee, Armstrong Energy, for all of our
revenues and therefore, depend on Armstrong Energy to
effectively manage its operations on our properties. Our lessee
makes its own business decisions with respect to its operations,
including decisions relating to:
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the method of mining;
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|
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timing of new mine openings;
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|
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planned production and sales volumes;
|
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|
|
credit review of its customers;
|
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|
|
marketing of the coal mined;
|
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|
coal transportation arrangements;
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|
employee wages;
|
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permitting;
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surety bonding; and
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mine closure and reclamation.
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We depend on Armstrong Energy for all of our coal royalty
revenues, and the loss of or significant reduction in production
from Armstrong Energy would have a material adverse effect on
our coal royalty revenues.
A failure on the part of Armstrong Energy to make coal royalty
payments could give us the right to terminate the lease,
repossess the property, and enforce payment obligations under
the lease. If we repossessed any of our properties, we would
seek to find a replacement lessee. We may not be able to find a
replacement lessee and, if we find a replacement lessee, we may
not be able to enter into a new lease on favorable terms within
a reasonable period of time. In addition, the outgoing lessee
could be subject to bankruptcy proceedings that could further
delay the execution of a new lease or the assignment of the
existing lease to another operator. If we enter into a new
lease, the replacement operator may not achieve the same levels
of production or sell coal at the same price as the lessee it
replaced. In addition, it may be difficult for us to secure new
or replacement lessees for small or isolated coal reserves,
since industry trends toward consolidation favor larger-scale,
higher technology mining operations to increase productivity
rates.
22
Coal
prices are subject to change and a substantial or extended
decline in prices could reduce our coal royalty revenues and the
value of our coal reserves.
A substantial or extended decline in coal prices from historical
levels could have a material adverse effect on our lessees
operations and on the quantities of coal that may be
economically produced from our properties. This, in turn, could
reduce our coal royalty revenues and the value of our coal
reserves. The prices and volume of coal sold by Armstrong
Energy, and consequently our royalty revenues, 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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Coal
mining operations are subject to operating risks that could
result in lower coal royalty revenues.
Our coal royalty revenues are dependent on the level of
production from our coal reserves achieved by Armstrong Energy,
our lessee. The level of Armstrong Energys production is
subject to operating conditions or events beyond its or our
control, including:
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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 Armstrong Energys operating areas, such
as coalbed methane extraction or oil and gas development.
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These conditions or events could cause a delay or halt of
production or shipments, or our lessees operating costs
could increase significantly. Any interruptions to the
production of coal from our reserves could reduce our coal
royalty revenues.
We may
not be able to grow and our business will be adversely affected
if we are unable to replace or increase our reserves through
acquisitions.
Because our reserves decline as our lessee mines our coal, our
future success and growth depends, in part, upon our ability to
acquire additional coal reserves that are economically
recoverable. If we are unable to negotiate purchase agreements
to replace
and/or
increase our coal reserves on acceptable terms, our coal royalty
revenues will decline as our coal reserves are depleted. In
addition, if we are unable to successfully integrate the
companies, businesses, or properties we are able to acquire, our
coal royalty revenues may decline and we could, therefore,
experience a material adverse effect on our business, financial
condition, or results of operations. If we acquire additional
coal reserves, there is a possibility that any acquisition could
be dilutive to earnings and reduce our ability to make
distributions to unitholders. Any debt we incur to finance an
acquisition may similarly affect our ability to make
distributions to unitholders. Our ability to make acquisitions
in the future also could be limited by restrictions under our
existing or future debt agreements, competition from other coal
companies for attractive properties, or the lack of suitable
acquisition candidates.
Competition
within the coal industry could adversely affect the ability of
our lessee to sell coal.
Our lessee competes 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 most important factors on which it competes 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 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 lessees 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
lessees failure to compete successfully could have a
material adverse effect on our coal royalty revenues.
International demand for U.S. coal also affects competition
within the coal 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 volumes demanded and materially and
adversely affect our coal royalty revenues.
Substantially all of the coal sold by our lessee is used 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
24
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 lessees business, and the level of our coal royalty
revenue, is closely linked to domestic demand for electricity,
and any changes in coal consumption by U.S. electric power
generators would likely impact our lessees business and
our royalty revenue stream over the long term. In 2011, our
lessee sold a substantial majority of our coal to domestic
electric power generators, and it has multi-year coal supply
agreements in place with electric power generators for a
significant portion of its 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 decreased by 0.6% during 2011 compared with 2010,
and U.S. electric generation from coal decreased by 5.5% in
2011 compared with 2010. 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 lessees
customers, such as those caused by decreased electricity demand
and increased competition, could also adversely affect our
royalty revenues. 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 lessees ability to sell coal to
its 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
royalty revenue stream.
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 or volumes sold for our
lessees coal. Declines in the prices at which our lessee
sells coal mined from our reserves could reduce our revenues and
materially and adversely affect our business and results of
operations.
In 2011, a substantial majority of the tons of coal sold by our
lessee 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.
Current developments in natural gas production processes have
25
lowered the cost and increased the supply, resulting in greater
use of natural gas for electricity generation. According to the
EIA, total electricity generation in the United States decreased
by 0.5% during 2011 compared with 2010, and U.S. electric
generation from coal decreased by 6.1% in 2011 compared with
2010 and is expected to decreased by a further 10% in 2012.
While the EIA projects that electricity generation will grow at
an annual average rate of 0.8% through 2035, it projects that
the percentage of electricity generated from coal will decrease
to 39% of total generation by 2035, compared with 42% during
2011.
The EIA projects coal-fueled electric power generation to
decline in 2012, primarily driven by depressed near-term natural
gas prices that are resulting in elevated levels of
coal-to-gas
switching. If
coal-to-gas
switching lasts for a prolonged period during 2012 due to
significantly depressed natural gas prices, there may be more
substantial unfavorable impacts to all coal supply regions.
Recent mild weather and weaker international and domestic
economies have also negatively impacted coal markets. All of the
foregoing could reduce demand for our lessees coal, which
could reduce the price of coal that our lessee mines and sells
from our reserves, thereby reducing our royalty revenues and
materially and adversely affecting our business and results of
operations.
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 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 our lessee mines and sells from our reserves,
thereby reducing our royalty revenues and materially and
adversely affecting our business and results of operations.
Inaccuracies
in our estimates of our coal reserves could materially adversely
affect the quantities and value of our reserves.
Our estimates of our reserves may vary substantially from the
actual amounts of coal that our lessee may be able to
economically recover. 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 our lessees
mines are currently located;
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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 attributed to any particular group
of properties, classification of reserves based on a risk of
recovery and estimates of future net cash flows expected from
those 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,
revenue, and expenditures with respect to our reserves will
likely vary from estimates, and these variations may be
material. As a result, you should not place undue reliance on
the coal reserve data included in this prospectus.
26
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, could adversely affect our lessees operating
costs or disrupt or delay its production, potentially reducing
our royalty revenues.
Our lessees coal mining operations use significant amounts
of steel, electricity, diesel fuel, explosives, rubber tires,
and other mining and industrial supplies. The cost of the roof
bolts it uses in its underground mining operations depends on
the price of scrap steel. Our lessee also uses significant
amounts of diesel fuel and tires for the trucks and other heavy
machinery it uses. If the prices of mining and other industrial
supplies, particularly steel-based supplies, diesel fuel, and
rubber tires, increase, our lessees operating costs may be
adversely affected, which may cause a reduction in production.
In addition, if our lessee is unable to procure these supplies,
its coal mining operations may be disrupted or it could
experience a delay or halt in production, which would have a
negative effect on our royalty revenues.
A
defect in title or the loss of a leasehold interest in certain
property could limit our lessees ability to mine our coal
reserves or result in significant unanticipated
costs.
A title defect or the loss of one of our or Armstrong
Energys leases could adversely affect its ability to mine
the associated coal reserves. We and our lessee may not verify
title to our properties or associated coal reserves until our
lessee has committed to developing those properties or coal
reserves. Armstrong Energy may not commit to develop property or
coal reserves until it has obtained necessary permits and
completed exploration. As such, the title to our property that
our lessee intends to lease or coal reserves that it intends to
mine may contain defects restricting or prohibiting its ability
to conduct mining operations. Similarly, Armstrong Energys
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 mining operations on properties
where these defects exist, we or Armstrong Energy may incur
unanticipated costs. In addition, some leases require Armstrong
Energy to produce a minimum quantity of coal and require it to
pay minimum production royalties. Armstrong Energys
inability to satisfy those requirements may cause the leasehold
interest to terminate.
The
availability and reliability of transportation facilities and
fluctuations in transportation costs could affect the demand for
our lessees coal or impair its ability to supply coal to
its customers.
Our lessee depends upon barge, rail, and truck transportation
systems to deliver coal to its customers. Disruptions in
transportation services due to weather-related problems,
mechanical difficulties, strikes, lockouts, bottlenecks, and
other events could impair our lessees ability to supply
coal to its 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
coal from our reserves is disrupted or if transportation costs
increase significantly and our lessee is unable to find
alternative transportation providers, our lessees coal
mining operations may be disrupted or it could experience a
delay or halt of production, thereby resulting in decreased coal
royalty revenues to us.
Changes
in purchasing patterns in the coal industry could make it
difficult for our lessee to extend its existing multi-year coal
supply agreements or to enter into new agreements in the
future.
A substantial decrease in the amount of coal sold by our lessee
pursuant to supply agreements with terms of one year or more
could reduce the certainty of the price and amounts of coal sold
and subject our coal royalty revenue stream to increased
volatility. Changes in the coal industry may cause some of our
lessees customers not to renew, extend, or enter into new
multi-year coal supply agreements 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
lessees customers from entering into multi-year coal
supply agreements. If a lower percentage of our lessees
revenues are generated under supply agreements with terms of one
year or more, our coal royalty revenues will be increasingly
affected by changes in spot market coal prices.
In addition, price adjustment, price re-opener, and other
similar provisions in supply agreements with terms of one year
or more may reduce the protection from short-term coal price
volatility traditionally
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provided by such agreements. Some of our lessees supply
agreements contain provisions which allow for the price at which
coal is purchased to be renegotiated at periodic intervals.
These price re-opener provisions may automatically set a new
price based on the prevailing market price or, in some
instances, require the parties to agree on a new price. In some
circumstances, failure of the parties to agree on a price under
a price re-opener provision can lead to termination of the
agreement. Any adjustment or renegotiation leading to a
significantly lower contract price could result in decreased
coal royalty revenues. Accordingly, supply agreements with terms
of one year or more may provide only limited protection during
adverse market conditions.
The
loss of, or significant reduction in purchases by, our
lessees largest customers could adversely affect our coal
royalty revenues.
For the year ended December 31, 2011, our lessee derived
approximately 63% of its total coal revenues from sales to its
two largest customers Louisville Gas and Electric
(LGE) and Tennessee Valley Authority
(TVA). For the fiscal year ended December 31,
2011, coal sales to LGE and TVA constituted approximately 35%
and 28% of our lessees total coal revenues, respectively.
Our lessees multi-year coal supply agreements with LGE
expire in 2015 and 2016, and its multi-year coal supply
agreements with TVA expire in 2013 and 2018; however, most of
its multi-year coal supply agreements with LGE and TVA contain
re-opener provisions pursuant to which either party can request
re-opening to renegotiate price and other terms for the
remaining term of such agreement, and, subsequent to any such
re-opening, the failure to reach an agreement can lead to the
termination of such agreement. In addition, one of our
lessees 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 our lessee 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 lessees arrangements with LGE
or TVA are terminated early pursuant to the re-opener
provisions, or our lessee fails to extend or renew its
arrangements with LGE or TVA, our coal royalty revenues could be
negatively impacted.
If our lessees
multi-year
coal supply agreements with LGE or TVA are terminated or if our
lessee fails to extend or renew its
multi-year
coal supply agreements with LGE or TVA, our lessee may be unable
to timely replace such agreements. In such a case, our coal
royalty revenues could be materially and adversely affected.
Our
lessee could satisfy obligations to its customers with coal from
properties other than ours, depriving us of the ability to
receive royalty payments.
We do not control our lessees business operations. Our
lessees customer supply agreements do not generally
require our lessee to satisfy its obligations to its customers
with coal mined from our reserves. Several factors may influence
a lessees decision to supply its customers with coal mined
from properties we do not own or lease, including the royalty
rates under the lessees lease with us, mining conditions,
transportation costs and availability, and customer coal
specifications. If a lessee satisfies its obligations to its
customers with coal from properties we do not own or lease,
production under our lease will decrease and we will receive
lower coal royalty revenues.
Our
assets and our lessees operations are concentrated in
Western Kentucky and the Illinois Basin, and a disruption within
that geographic region could adversely affect the
Partnerships performance.
Our reserves and Armstrong Energys operations 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 lessees ability to operate
its business and our coal royalty revenues could be negatively
impacted.
Some
officers of Armstrong Energy may spend a substantial amount of
time managing the business and affairs of Armstrong Energy and
its affiliates other than us.
Officers may face a conflict regarding the allocation of their
time between our business and the other business interests of
Armstrong Energy. 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
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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.
Our
lessees ability to operate its business effectively could
be impaired if it fails to attract and retain key management
personnel.
Armstrong Energys ability to operate its business and
implement its strategies depends on the continued contributions
of its executive officers and key employees. In particular,
Armstrong Energy depends significantly on its senior
managements long-standing relationships within its
industry. The loss of any of its senior executives could have a
material adverse effect on Armstrong Energys business, and
therefore, on our royalty revenue. In addition, our lessee
believes that its future success will depend on its 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. Our lessee may
not be able to continue to employ key personnel or attract and
retain qualified personnel in the future, and its failure to
retain or attract key personnel could have a material adverse
effect on Armstrong Energys ability to effectively operate
its business, and therefore, on our royalty revenue.
We may
be subject to various legal proceedings, which may have an
adverse effect on our business.
From time to time, we may be involved in 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.
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 royalty revenues.
Efficient coal mining using modern techniques and equipment
requires skilled laborers in multiple disciplines such as
equipment operators, mechanics, electricians, and engineers,
among others. The industry has from time to time encountered
shortages for these types of skilled labor. If the coal industry
experience shortages of skilled labor in the future or an
increase in labor prices, our lessees labor and overall
productivity or costs could be materially and adversely
affected, thereby reducing our royalty revenues.
Our
lessees work force could become unionized in the future,
which could adversely affect the stability of our lessees
production and materially reduce our
profitability.
All of our lessees mines are operated by non-union
employees, though its 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 some or all of our lessees operations
were to become unionized, it could adversely affect its
productivity and increase the risk of work stoppages. In
addition, our lessees operations may be adversely affected
by work stoppages at unionized companies, particularly if union
workers were to orchestrate boycotts against our lessees
operations. Any unionization of our lessees employees
could adversely affect the stability of production from our
reserves through potential strikes, slowdowns, picketing and
work stoppages, and reduce our coal royalty revenues.
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 lessees business and therefore, our royalty
revenues.
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 lessees production and business
activity. Future terrorist attacks, rumors or threats of war,
actual conflicts involving the United States or its allies, or
military or trade disruptions affecting our lessees
customers may significantly affect our lessees operations
and those of its 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
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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 lessees business and our
coal royalty revenues.
Even
if the restrictions on distributions by us to our limited
partners imposed by the Senior Secured Credit Facility are
lifted, we may not have sufficient cash to enable us to pay
quarterly distributions on our common units following
establishment of cash reserves and payment of costs and
expenses, including reimbursement of expenses to our general
partner.
The Senior Secured Credit Facility restricts our ability to pay
distributions. Even if such restrictions are lifted, we may not
have sufficient cash each quarter to pay quarterly distributions
on our common units. The amount of cash we can distribute on our
common units principally depends upon the amount of coal royalty
revenues we receive, which will fluctuate from quarter to
quarter based on, among other things:
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the amount of coal produced from our properties, which could be
adversely affected by, among other things, operating
difficulties and unfavorable geologic conditions;
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the price at which coal mined from our reserves is able to be
sold, which price is affected by the supply of and demand for
domestic and foreign coal;
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the level of operating costs relating to the mining of our coal
reserves, as well as reimbursement of expenses to our general
partner and its affiliates. Our Partnership Agreement does not
set a limit on the amount of expenses for which our general
partner and its affiliates may be reimbursed;
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with respect to our coal reserves, the proximity to and capacity
of transportation facilities;
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the price and availability of alternative fuels;
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the impact of future environmental and climate change
regulations, including those impacting coal-fired power plants;
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the level of worldwide energy and steel consumption;
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prevailing economic and market conditions;
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difficulties by our lessee in collecting receivables because of
credit or financial problems of purchasers of coal mined from
our reserves;
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the effects on the mining of coal from our reserves of new or
expanded health and safety regulations;
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domestic and foreign governmental regulation, including changes
in governmental regulation of the mining industry, the electric
utility industry or the steel industry;
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changes in tax laws;
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weather conditions; and
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force majeure.
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Our lessee, Armstrong Energy, has historically deferred the
payment to us of cash royalties pursuant to a Royalty Deferment
and Option Agreement which it has entered into with us, and we
expect that Armstrong Energy will continue to make such
deferrals for the foreseeable future. Pursuant to the terms of
that Agreement, in the event that Armstrong Energy exercises its
deferral right, we have the right to acquire additional
undivided interests in coal reserves controlled by Armstrong
Energy. We expect that for the foreseeable future all or a
substantial portion of our royalty revenues will be used by us
to acquire such additional coal reserve interests and will not
be a source of cash for the payment of dividends or other
distributions to our unitholders.
For a description of additional restrictions and factors that
may affect our ability to pay cash distributions, please read
Cash Distribution Policy and Restrictions on
Distributions.
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Debt
we incur in the future may limit our flexibility to obtain
financing and to pursue other business
opportunities.
Our future level of debt could have important consequences to
us, including the following:
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our ability to obtain additional financing, if necessary, for
acquisitions or other purposes may be impaired or such financing
may not be available on favorable terms;
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our funds available for future business opportunities and
distributions to unitholders will be reduced by that portion of
our cash flow required to make interest payments on our debt;
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we may be more vulnerable to competitive pressures or a downturn
in the coal mining business or the economy generally; and
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our flexibility in responding to changing business and economic
conditions may be limited.
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Our ability to service our debt will depend upon, among other
things, our future financial performance, which will be affected
by prevailing economic conditions and financial, business,
regulatory and other factors, some of which are beyond our
control. If our results are not sufficient to service our future
indebtedness, we will be forced to take actions such as reducing
distributions, reducing or delaying our business activities,
acquisitions, investments or capital expenditures, selling
assets or seeking additional equity capital. We may not be able
to effect any of these actions on satisfactory terms or at all.
Restrictions
in or a failure by our lessee to comply with the terms of the
Senior Secured Credit Facility, on which we serve as co-borrower
with respect to the Senior Secured Term Loan and guarantor with
respect to the Senior Secured Revolving Credit Facility and the
Senior Secured Term Loan, could adversely affect our business,
financial condition, results of operations, ability to make
distributions to unitholders and value of our common
units.
The Senior Secured Credit Facility limits our ability to, among
other things:
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incur additional debt;
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make distributions on or redeem or repurchase common units;
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make certain investments and acquisitions;
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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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merge or consolidate with another company; and
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transfer or otherwise dispose of assets.
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The Senior Secured Credit Facility also contains covenants
requiring us to maintain certain financial ratios. Please read
Description of Indebtedness.
The Senior Secured Credit Facility restricts our ability to pay
distributions. Except for distributions in amounts necessary to
enable unitholders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership, which
will be paid, if at all, solely at the discretion of Elk Creek,
GP, our general partner, we do not anticipate paying any
distributions for the foreseeable future. In addition, we are
unable to pay distributions until the restrictions on
distributions by us to our limited partners imposed by the
Senior Secured Credit Facility have been lifted. See Cash
Distribution Policy and Restrictions on Distributions.
In addition, the provisions of the Senior Secured Credit
Facility may affect our ability to obtain future financing and
pursue attractive business opportunities and our flexibility in
planning for, and reacting to, changes in business conditions. A
failure to comply with the provisions of the Senior Secured
Credit Facility could result in a default or an event of default
that could enable our lenders to declare the outstanding
principal of that debt, together with accrued and unpaid
interest, to be immediately due and payable. If the payment of
the debt is accelerated, our assets may be insufficient to repay
such debt in full, and our unitholders could experience a
partial or total loss of their investment.
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We are not permitted to borrow additional funds under the Senior
Secured Credit Facility and as such, it is not a source of
liquidity for us.
We
will not be required by Section 404 of the Sarbanes-Oxley
Act to evaluate the effectiveness of our internal controls until
the year following our first annual report and our independent
registered public accounting firm is not required to formally
attest to the effectiveness of our internal controls while we
qualify as an emerging growth company. We have
identified internal 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 not currently required to comply with the SEC rules that
implement Sections 302 and 404 of the Sarbanes-Oxley Act,
and are therefore not required to make a formal assessment of
the effectiveness of our internal controls over financial
reporting for that purpose. Upon becoming a public company, we
will be required to comply with certain of these rules, which
will require management to certify financial and other
information in our quarterly and annual reports and provide an
annual management report on the effectiveness of our internal
control over financial reporting. Though we will be required to
disclose changes made in our internal control and procedures on
a quarterly basis, we will not be required to make our first
annual assessment of our internal control over financial
reporting pursuant to Section 404 until the year following
our first annual report required to be filed with the SEC.
Additionally, our independent registered public accounting firm
is not required to formally attest to the effectiveness of our
internal control over financial reporting until we are no longer
an emerging growth company as defined in the JOBS
Act. At such time, our independent registered public accounting
firm may issue a report that is adverse in the event it is not
satisfied with the level at which our controls are documented,
designed or operating. Further, we may take advantage of other
accounting and disclosure related exemptions afforded to
emerging growth companies from time to time.
Under applicable SEC and Public Company Accounting Oversight
Board rules and regulations, 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 interim
consolidated financial statements will not be prevented or
detected. We have identified deficiencies constituting a
material weakness 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 depletion.
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 consolidated financial statements
may be inaccurate, we may face restricted access to the capital
markets and our common unit price may be adversely affected.
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 adversely affect
our coal royalty revenue stream.
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.
On March 27, 2012, the EPA released its proposed rule that
would establish, for the first time, new source performance
standards under the federal Clean Air Act for
CO2
emissions from new fossil fuel-fired
32
electric utility generating power plants. The proposed rule
would require new plants greater than 25 megawatts to meet an
output based standard of 1000 pounds of
CO2
per megawatt hour, based on the performance of natural gas
combined cycle technology. New coal-fired power plants could
meet the standard either by employing carbon capture and storage
technology at start up or through later application of such
technologies provided that the aforementioned output standard
was met on average over a
30-year
period. Public comments concerning the proposed rule have been
solicited for submission within 60 days after the
publication of the proposed rule, and future public hearings
will be scheduled to discuss the proposal. If adopted, the
proposed rule could negatively impact the price of coal such
that it would be less attractive to utilities and ratepayers.
Moreover, there is currently no large-scale use of carbon
capture and storage technologies in domestic coal-fired power
plants, and as a result, there is a risk that such technology
may not be commercially practical in limiting emissions as
otherwise required by the proposed rule.
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, particularly coal, which could have a material
adverse effect on our royalty revenues. See
Business Regulation and Laws
Climate Change.
Extensive
environmental requirements, including existing and potential
future requirements relating to air emissions, affect our
lessees customers and could reduce the demand for coal as
a fuel source, which could adversely affect our coal royalty
revenue stream.
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 coal consumers 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 to decline and reduce the
demand for our coal, thereby reducing our coal royalty revenues.
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. A decrease in the price and demand
for our coal would cause our coal royalty revenues to decline.
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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 royalty payments.
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 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
lessees coal and the price our lessee will receive, which
could materially and adversely affect our royalty payments.
Our
lessees failure to obtain and renew permits and approvals
necessary for its mining operations could materially reduce our
royalty revenues.
We depend on our lessees coal production for all of our
revenues. Our lessee, in turn, must maintain various federal and
state permits and approvals to mine our coal reserves within the
timeline specified in its 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 continuation 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. The 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 lessees
applications to obtain and maintain permits that are important
to its mining 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, our lessee submits the necessary permit applications
12 to 30 months before it plans to mine a new area. Some of
its required mining permits are becoming increasingly difficult
to obtain within the time frames to which our lessee was
previously accustomed, and in some instances our lessee has had
to delay the mining of coal in certain areas covered by an
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 lessees ability to efficiently and
economically conduct its mining activities, we could suffer a
material reduction in our coal royalty revenues. See
Business Regulation and Laws.
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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.
Federal
or state regulatory agencies have the authority to order certain
of our lessees mines to be temporarily or permanently
closed under certain circumstances, which could materially and
adversely affect our coal royalty revenues.
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 our lessee to be
allowed to reopen the mine. In the event that these agencies
order the closing of our lessees mines, our coal royalty
revenues could materially decline.
Extensive
environmental laws and regulations impose significant costs on
our lessees mining operations, and future laws and
regulations could materially increase those costs or limit our
lessees ability to produce and sell coal, which would
cause our coal royalty revenues to decrease.
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 or our lessee have been
or will be at all times in compliance with the applicable laws
and regulations. Failure to comply with these laws and
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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 lessees mines,
thereby reducing our coal royalty revenues.
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 our lessee to change operations
significantly, which could negatively impact production and
reduce our coal royalty revenues. 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 lessees financial condition and results of
operations and thereby reduce our royalty revenues. See
Business Regulation and Laws.
We may
become liable under federal and state mining statutes if our
lessee is unable to pay mining reclamation costs.
The SMCRA and similar state statutes impose on mine operators
the responsibility of restoring the land to its original state
or compensating the landowner for types of damages occurring as
a result of mining operations, and require mine operators to
post performance bonds to ensure compliance with any reclamation
obligations. Regulatory authorities may attempt to assign the
liabilities of our lessee to us if our lessee is not financially
capable of fulfilling those obligations. See
Business Regulation and Laws.
We
could become liable under federal and state Superfund and waste
management statutes if our lessee is unable to pay environmental
cleanup costs.
The Comprehensive Environmental Response, Compensation and
Liability Act, known as CERCLA or
Superfund, and similar state laws create liabilities
for the investigation and remediation of releases and threatened
releases of hazardous substances to the environment and damages
to natural resources. As land owners, we are potentially subject
to these liabilities. See Business Regulation
and Laws for more information.
Changes
in the legal and regulatory environment could complicate or
limit our lessees business activities, result in
litigation, or materially adversely affect production, which
could reduce our coal royalty revenues.
The conduct of our lessees business 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
our lessee operates. 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,
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
U.S. 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 U.S. 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.
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 our
lessees current or future mines operate and could increase
our lessees operating costs or otherwise may prevent,
delay or reduce our lessees planned production, any of
which could adversely affect our lessees coal production
and our royalty revenue stream.
Although we are unable to quantify the full impact, implementing
and our lessees compliance with new laws and regulations
could have an adverse impact on our lessees business and
results of operations and could result in harsher sanctions in
the event of any violations. See Business
Regulation and Laws.
Risks
Related to This Offering and Our Common Units
An
active, liquid trading market for our common units may not
develop.
Prior to this offering, there has not been a public market for
our common units. We cannot predict the extent to which investor
interest in us will lead to the development of a trading market
on Nasdaq or
37
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 units that you purchase.
Our
common unit 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
our common units 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 common units at or above the
initial public offering price due to a number of factors such as
those listed in Risks Related to the
Partnership. Some of the factors that could negatively
affect our common units 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, Armstrong Energy, 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 of Armstrong
Energy;
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actions of our general partner;
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speculation in the press or investment community;
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a large volume of sellers of our common units 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 securities markets have 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 price of our common units, regardless of
our actual operating performance.
In the past, following periods of market volatility, securities
holders 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 common unit may not accurately reflect its
actual value.
The initial public offering price of the common units 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 units, and may not be
indicative of prices that will prevail in the open market
following this offering.
Cash
distributions are restricted under the terms of the Senior
Secured Credit Facility and even if these restrictions are
lifted, distributions are not guaranteed and may fluctuate with
our performance and the establishment of financial reserves and
at the discretion of our general partner.
The Senior Secured Credit Facility restricts our ability to pay
distributions. Except for distributions in amounts necessary to
enable unitholders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership, which
will be paid, if at all, solely at the discretion of Elk Creek,
GP, our general partner, we do not anticipate paying any
distributions for the foreseeable future. In addition, we are
unable to pay distributions until the restrictions on
distributions by us to our limited partners imposed by the
Senior Secured Credit Facility have been lifted. See Cash
Distribution Policy and Restrictions on Distributions.
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Because distributions on the common units are dependent on the
amount of coal royalty revenues we receive, even if restrictions
under the Senior Secured Credit Facility are removed,
distributions may fluctuate. The actual amount of cash that is
available to be distributed each quarter will depend on numerous
factors, some of which are beyond our control and the control of
our general partner or Armstrong Energy. Cash distributions are
dependent primarily on cash flow, including cash flow from
financial reserves and working capital borrowings, and not
solely on profitability, which is affected by non-cash items.
Therefore, cash distributions might be made during periods when
we record losses and might not be made during periods when we
record profits.
Our lessee, Armstrong Energy, has historically deferred the
payment to us of cash royalties pursuant to a Royalty Deferment
and Option Agreement which it has entered into with us, and we
expect that Armstrong Energy will continue to make such
deferrals for the foreseeable future. Pursuant to the terms of
that Agreement, in the event that Armstrong Energy exercises its
deferral right, we have the right to acquire additional
undivided interests in coal reserves controlled by Armstrong
Energy. We expect that for the foreseeable future all or a
substantial portion of our royalty revenues will be used by us
to acquire such additional coal reserve interests and will not
be a source of cash for the payment of dividends or other
distributions to our unitholders.
The
fiduciary duties of officers and managers 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., 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 managers 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.
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 Energy may borrow
under the Senior Secured Credit Agreement or other borrowing
facilities Armstrong Energy may enter into guaranteed by
Armstrong Resource Partners and other matters. Armstrong Energy
may continue to, but is under no obligation 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
unitholders. In addition, Armstrong Energy 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 unitholders, on the other hand.
Armstrong Energy has 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.
Our
partnership agreement limits our general partners
fiduciary duties to our unitholders and restricts the remedies
available to our unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Fiduciary duties owed to our unitholders by our general partner
are prescribed by law and the partnership agreement. The
Delaware Revised Uniform Limited Partnership Act, or the
Delaware Act, provides that Delaware limited partnerships may,
in their partnership agreements, restrict the fiduciary duties
owed by the general partner to limited partners and the
partnership. Our partnership agreement contains provisions that
39
reduce the standards to which our general partner would
otherwise be held by state fiduciary duty law. For example, our
partnership agreement:
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limits the liability and reduces the fiduciary duties of our
general partner, while also restricting the remedies available
to our unitholders for actions that, without these limitations,
might constitute breaches of fiduciary duty. As a result of
purchasing common units, our unitholders consent to some actions
and conflicts of interest that might otherwise constitute a
breach of fiduciary or other duties under applicable state law;
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permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its limited call right, its
voting rights with respect to the units it owns, its
registration rights and its determination whether or not to
consent to any merger or consolidation of the Partnership;
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provides that our general partner shall not have any liability
to us or our unitholders for decisions made in its capacity as
general partner so long as it acted in good faith, meaning our
general partner honestly believed that the decision was in the
best interests of the Partnership;
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generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
and not involving a vote of our unitholders must be on terms no
less favorable to us than those generally being provided to or
available from unrelated third parties or be fair and
reasonable to us and that, in determining whether a
transaction or resolution is fair and reasonable,
our general partner may consider the totality of the
relationships between the parties involved, including other
transactions that may be particularly advantageous or beneficial
to us; and
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provides that our general partner and its officers and managers
will not be liable for monetary damages to us or our limited
partners for any acts or omissions unless there has been a final
and non-appealable judgment entered by a court of competent
jurisdiction determining that our general partner or those other
persons acted in bad faith or engaged in fraud or willful
misconduct.
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By purchasing a common unit, a common unitholder will become
bound by the provisions of the partnership agreement, including
the provisions described above. See Description of the
Common Units Transfer of Common Units.
Armstrong
Energys board of directors may change the management and
allocation policies relating to Armstrong Resource Partners
without the approval of our unitholders.
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 limited partnership, our partnership
agreement, Armstrong Energys certificate of incorporation
or Armstrong Energys bylaws, and Armstrong Energys
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 Armstrong Energy, 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 us or
our unitholders.
Holders
of our common units may not have any remedies if any action by
Armstrong Energys directors or officers in relation to
Armstrong Energy has an adverse effect on only Armstrong
Resource Partners common units.
Principles of Delaware law and the provisions of the certificate
of incorporation and by-laws may protect decisions of Armstrong
Energys board of directors in relation to Armstrong Energy
that have a disparate impact upon holders of our common units.
Under the principles of Delaware law and the Delaware business
40
judgment rule, you may not be able to successfully challenge
decisions in relation to Armstrong Energy that you believe have
a disparate impact upon the holders of Armstrong Resource
Partners common units if Armstrong Energys 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 Energy will 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.
Yorktown
will continue to have significant influence over us, including
control over decisions that require the approval of unitholders,
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
own beneficially 11,273,874 common units, which represents
approximately 90.5% of our outstanding common units (or 89.8% if
the underwriters exercise their option to purchase additional
units in full). As a result, Yorktown will retain the ability to
direct and control our business affairs. Yorktown will have
influence over our decisions to enter into any corporate
transaction regardless of whether others believe that the
transaction is in our best interests.
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 units, 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 unitholders of an opportunity to receive a premium
for their common units as part of a sale of our company and
might ultimately affect the market price of our common units.
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, related
regulations of the Securities and Exchange Commission (the
SEC) and the requirements of Nasdaq or other stock
exchange on which our common units are listed, with which we are
not required to comply as a private company. Under the current
rules of the SEC, beginning with fiscal 2013, we must perform
system and process evaluation and testing of our internal
control over financial reporting to allow management to report
on the effectiveness of our internal control over financial
reporting, as required by Section 404 of the Sarbanes-Oxley
Act. Beginning with fiscal 2018, or such earlier time as we are
no longer an emerging growth company as defined in
the JOBS Act, our independent registered public accounting firm
also will be required to report on our internal control over
financial reporting. We will need to:
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institute a more comprehensive compliance function;
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comply with rules promulgated by Nasdaq or any other stock
exchange on which our common units are 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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Complying with these statutes, regulations and requirements will
occupy a significant amount of time of the officers and
directors of Armstrong Energy who manage us and will
significantly increase our costs and expenses. In addition, we
could be required to expend significant management time and
financial resources to correct any material weaknesses in our
internal control over financial reporting that may be identified.
We are
an emerging growth company within the meaning of the JOBS Act,
and if we decide to take advantage of certain exemptions from
various reporting requirements applicable to emerging growth
companies, our common units could be less attractive to
investors.
We are an emerging growth company within the meaning
of the JOBS Act. We are eligible to take advantage of certain
exemptions from various reporting requirements that are
applicable to other public companies that are not emerging
growth companies, including, but not limited to, reduced
disclosure about our executive compensation and omission of
compensation discussion and analysis. In addition, we will not
be subject to certain requirements of Section 404 of the
Sarbanes-Oxley Act, including the additional level of review of
our internal control over financial reporting as may occur when
outside auditors attest as to our internal control over
financial reporting. As a result, our unitholders may not have
access to certain information they may deem important. We will
remain an emerging growth company for up to five years, though
we may cease to be an emerging growth company earlier under
certain circumstances. If we take advantage of any of these
exemptions, we do not know if some investors will find our
common units less attractive as a result. The result may be a
less active trading market for our common units and the market
price of our common units may be more volatile.
If
securities or industry analysts do not publish research or
reports about our business, if they adversely change their
recommendations regarding our common units, or if our operating
results do not meet their expectations, the price and trading
volume of our common units could decline.
The trading market for our common units 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 units. This lack
of research coverage could adversely affect the price of our
common units. We do not have any control over these reports or
analysts. If any of the analysts who cover us downgrades our
common units, or if our operating results do not meet the
analysts expectations, our common unit 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 unit price and trading volume to decline and our common
units to be less liquid.
You
will incur immediate dilution in the book value of your common
units as a result of this offering.
The initial public offering price of our common units is
considerably more than the as adjusted, net tangible book value
per outstanding unit. 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 common units.
Investors purchasing common units in this offering will incur
immediate dilution of $6.18 in as adjusted, net tangible book
value per unit, based on the assumed initial public offering
price of $ per unit, 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 12.9% of the
total consideration paid by our unitholders to purchase common
units. 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 common units will
further dilute your percentage ownership of us.
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Our
general partner may not be able to organize and effectively
manage a publicly traded operating company, which could
adversely affect our overall financial position.
Some of the senior executive officers or directors who will
manage our lessee and us, through our general partner, have not
previously organized or managed a publicly traded company, and
those senior executive officers and directors may not be
successful in doing so. The demands of organizing and managing a
publicly traded company are much greater as compared to a
private company and some of these senior executive officers and
directors may not be able to meet those increased demands.
Failure to organize and effectively manage us or our lessee
could adversely affect our overall financial position or
royalties.
Cost
reimbursements due to our general partner may be substantial and
will reduce our cash available for distribution to
unitholders.
Prior to making any distribution on the common units, we will
reimburse our general partner and its affiliates, including
officers and directors of Armstrong Energy, for all expenses
incurred on our behalf. The reimbursement of expenses and the
payment of fees could adversely affect our ability to make
distributions. The general partner has sole discretion to
determine the amount of these expenses. In addition, our general
partner and its affiliates may provide us services for which we
will be charged reasonable fees as determined by the general
partner. See Certain Relationships and Related Party
Transactions Administrative Services Agreement.
Unitholders
other than Yorktown may not remove our general partner even if
they wish to do so.
Armstrong Energy, Inc., the parent corporation of our general
partner, manages and operates us. Unlike the holders of common
stock in a corporation, unitholders have only limited voting
rights on matters affecting our business. Unitholders have no
right to elect our general partner or the directors of Armstrong
Energy on an annual or any other basis.
Furthermore, if unitholders other than Yorktown are dissatisfied
with the performance of our general partner, they currently have
no practical ability to remove our general partner or otherwise
change its management. Yorktown unilaterally may remove our
general partner in some circumstances. Unitholders other than
Yorktown have no right to remove our general partner.
In addition, the following provisions of our Partnership
Agreement may discourage a person or group from attempting to
change our management:
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generally, if a person acquires 20% or more of any class of
units then outstanding other than from our general partner or
its affiliates, the units owned by such person cannot be voted
on any matter; and
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limitations upon the ability of unitholders to call meetings or
to acquire information about our operations, as well as other
limitations upon the unitholders ability to influence the
manner or direction of management.
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As a result of these provisions, the price at which the common
units will trade may be lower because of the absence or
reduction of a takeover premium in the trading price.
We may
issue additional common units without unitholder approval, which
would dilute a unitholders existing ownership
interests.
Our general partner may cause us to issue an unlimited number of
common units, without unitholder approval (subject to applicable
Nasdaq rules). We may also issue at any time an unlimited number
of equity securities ranking junior or senior to the common
units without unitholder approval (subject to applicable Nasdaq
rules). The issuance of additional common units or other equity
securities of equal or senior rank will have the following
effects:
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an existing unitholders proportionate ownership interest
in us will decrease;
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the amount of cash available for distribution on each common
unit may decrease;
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the relative voting strength of each previously outstanding
common unit may be diminished; and
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the market price of the common units may decline.
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Our
general partner has a limited call right that may require
unitholders to sell their common units at an undesirable time or
price.
If at any time our general partner and its affiliates own 80% or
more of the units, the general partner will have the right, but
not the obligation, which it may assign to any of its
affiliates, to acquire all, but not less than all, of the
remaining common units held by unaffiliated persons at a price
generally equal to the then current market price of the common
units. As a result, unitholders may be required to sell their
common units at a time when they may not desire to sell them or
at a price that is less than the price they would like to
receive. They may also incur a tax liability upon a sale of
their common units.
Unitholders
may not have limited liability if a court finds that unitholder
actions constitute control of our business.
Our general partner generally has unlimited liability for our
obligations, such as our debts and environmental liabilities,
except for those contractual obligations that are expressly made
without recourse to our general partner. Under Delaware law,
however, a unitholder could be held liable for our obligations
to the same extent as a general partner if a court determined
that the right of unitholders to remove our general partner or
to take other action under our Partnership Agreement constituted
participation in the control of our business. In
addition,
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act provides
that under some circumstances, a unitholder may be liable to us
for the amount of a distribution for a period of three years
from the date of the distribution.
Conflicts
of interest could arise among our general partner and us or the
unitholders.
These conflicts may include the following:
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we do not have any employees and we rely solely on the
directors, officers, and employees of Armstrong Energy;
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under our Partnership Agreement, we reimburse the general
partner and Armstrong Energy for the costs of managing and for
operating the Partnership;
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the amount of cash expenditures, borrowings and reserves may
affect cash available to pay distributions to unitholders;
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the general partner tries to avoid being liable for Partnership
obligations. The general partner is permitted to protect its
assets in this manner by our Partnership Agreement. Under our
Partnership Agreement the general partner would not breach its
fiduciary duty by avoiding liability for Partnership obligations
even if we can obtain more favorable terms without limiting the
general partners liability;
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under our Partnership Agreement, the general partner may pay its
affiliates for any services rendered on terms fair and
reasonable to us. The general partner may also enter into
additional contracts with any of its affiliates on behalf of us.
Agreements or contracts between us and our general partner (and
its affiliates) are not necessarily the result of arms-length
negotiations; and
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the general partner would not breach our Partnership Agreement
by exercising its call rights to purchase limited partnership
interests or by assigning its call rights to one of its
affiliates or to us.
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The
control of our general partner may be transferred to a third
party without unitholder consent. A change of control may result
in defaults under certain of our debt instruments and the
triggering of payment obligations under compensation
arrangements.
Elk Creek GP, our general partner, may transfer its general
partner interest to a third party in a merger or in a sale of
all or substantially all of its assets without the consent of
our unitholders. Furthermore, our Partnership Agreement does not
restrict Elk Creek GPs general partner from transferring
its general partnership interest in Elk Creek GP to a third
party. The new owner of our general partner would then be in a
position to replace the board of directors and officers with its
own choices and to control their decisions and actions.
In addition, a change of control would constitute an event of
default under our revolving credit agreement. During the
continuance of an event of default under our revolving credit
agreement, the administrative agent may terminate any
outstanding commitments of the lenders to extend credit to us
and/or
declare all amounts payable by us immediately due and payable. A
change of control also may trigger payment obligations under
various compensation arrangements with our officers.
Tax
Risks
In addition to reading the following risk factors, please read
Material Tax Consequences for a more complete
discussion of the expected material federal income tax
consequences of owning and disposing of common units.
Our
tax treatment depends on our status as a partnership for federal
income tax purposes. If the Internal Revenue Service were to
treat us as a corporation for federal income tax purposes, which
would subject us to entity-level taxation, then our cash
available for distribution to our unitholders would be
substantially reduced.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the
Internal Revenue Service (IRS) on this or any other
tax matter affecting us.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe we will
be treated as a corporation based on our current operations, a
change in our business or a change in current law could cause us
to be treated as a corporation for federal income tax purposes
or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of
35.0%, and would likely pay state and local income tax at
varying rates. Distributions would generally be taxed again as
corporate distributions, and no income, gains, losses,
deductions, or credits would flow through to you. Because a tax
would be imposed upon us as a corporation, our cash available
for distribution to you would be substantially reduced.
Therefore, if we were treated as a corporation for federal
income tax purposes there would be material reduction in the
anticipated cash flow and after-tax return to our unitholders,
likely causing a substantial reduction in the value of our
common units.
The
tax treatment of publicly traded partnerships or an investment
in our common units could be subject to potential legislative,
judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The tax treatment of publicly traded partnerships or an
investment in our common units could be subject to potential
legislative, judicial, or administrative changes and differing
interpretations, possibly on a retroactive basis. Recently, the
Obama Administration and members of the U.S. Congress have
considered substantive changes to the existing federal income
tax laws that affect certain publicly traded partnerships,
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which, if enacted, may or may not be applied retroactively. Any
such changes could negatively impact the value of an investment
in our common units. Further, changes in current state law may
subject us to additional entity-level taxation by individual
states. Because of widespread state budget deficits and other
reasons, several states are evaluating ways to subject
partnerships to entity-level taxation through the imposition of
state income, franchise, and other forms of taxation. Imposition
of any such taxes may substantially reduce the cash available
for distribution to you.
Our
unitholders share of our income will be taxable to them
for federal income tax purposes even if they do not receive any
cash distributions from us.
Because you will be treated as a partner to whom we will
allocate taxable income which could be different in amount than
the cash we distribute, you will be required to pay any federal
income taxes and, in some cases, state and local income taxes,
on your share of our taxable income even if you receive no cash
distributions from us. You may not receive cash distributions
from us equal to your share of our taxable income or even equal
to the actual tax liability that results from that income.
Certain
United States federal income tax preferences currently available
with respect to coal exploration and development may be
eliminated in future legislation.
Among the changes contained in President Obamas Budget
Proposal for Fiscal Year 2013 (the Budget Proposal)
is the elimination of certain key federal income tax preferences
relating to coal exploration and development. The Budget
Proposal would (i) eliminate current deductions and the
60-month
amortization for exploration and development costs relating to
coal and other hard mineral fossil fuels, (ii) repeal the
percentage depletion allowance with respect to coal properties,
(iii) repeal capital gains treatment of coal and lignite
royalties, and (iv) 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 federal income tax laws could increase the
taxable income allocable to our unitholders and negatively
impact the value of an investment in our common units.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely impacted and the
cost of any IRS contest will reduce our cash available for
distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes or
any other matter affecting us. The IRS may adopt positions that
differ from the conclusions of our counsel expressed in this
prospectus or from the positions we take, and the IRSs
positions may ultimately be sustained. It may be necessary to
resort to administrative or court proceedings to sustain some or
all of our counsels conclusions or the positions we take,
and such positions may not ultimately be sustained. A court may
not agree with some or all of our counsels conclusions or
the positions we take. Any contest with the IRS, and the outcome
of any IRS contest, may have a materially adverse impact on the
market for our common units and the price at which they trade.
In addition, our costs of any contest with the IRS will be borne
indirectly by our unitholders and our general partner because
the costs will reduce our cash available for distribution.
Tax
gain or loss on the disposition of our common units could be
more or less than expected.
If you sell your common units, you will recognize a gain or loss
for federal income tax purposes equal to the difference between
the amount realized and your tax basis in those common units.
Because distributions in excess of your allocable share of our
net taxable income decrease your tax basis in your common units,
the amount, if any, of such prior excess distributions with
respect to the common units you sell will, in effect, become
taxable income to you if you sell such common units at a price
greater than your tax basis in those common units, even if the
price you receive is less than your original cost. Furthermore,
a substantial portion
46
of the amount realized on any sale of your common units, whether
or not representing gain, may be taxed as ordinary income due to
potential recapture items, including depletion recapture and
depreciation recapture. In addition, because the amount realized
includes your share of our nonrecourse liabilities, if you sell
your common units, you may incur a tax liability in excess of
the amount of cash you receive from the sale. See Material
United Tax Consequences Disposition of Common
Units Recognition of Gain or Loss for a
further discussion of the foregoing.
Tax-exempt
entities and
non-U.S.
persons face unique tax issues from owning our common units that
may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as
employee benefit plans and individual retirement accounts (known
as IRAs), and
non-U.S. persons
raises issues unique to them. For example, all or a substantial
portion of our income allocated to organizations that are exempt
from federal income tax, including IRAs and other retirement
plans, may be unrelated business taxable income and taxable to
them. Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file federal income tax returns and pay tax
on their share of our taxable income. If you are a tax-exempt
entity or a
non-U.S. person,
you should consult a tax advisor before investing in our common
units.
We
will treat each purchaser of common units as having the same tax
benefits without regard to the actual common units purchased.
The IRS may challenge this treatment, which could adversely
affect the value of the common units.
Because we cannot match transferors and transferees of common
units and to maintain the uniformity of the economic and tax
characteristics of our common units, we will adopt depreciation
and amortization positions that may not conform to all aspects
of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to you. Our counsel is unable to opine as to
the validity of such filing positions. It also could affect the
timing of these tax benefits or the amount of gain from your
sale of common units and could have a negative impact on the
value of our common units or result in audit adjustments to your
tax returns. See Material Tax Consequences Tax
Consequences of Common Unit Ownership
Section 754 Election for a further discussion of the
effect of the depreciation and amortization positions we will
adopt.
We
prorate our items of income, gain, loss, and deduction for
federal income tax purposes between transferors and transferees
of our common units each month based upon the ownership of our
common units on the first day of each month, instead of on the
basis of the date a particular common unit is transferred. The
IRS may challenge this treatment, which could change the
allocation of items of income, gain, loss, and deduction among
our unitholders.
We will prorate our items of income, gain, loss, and deduction
for federal income tax purposes between transferors and
transferees of our common units each month based upon the
ownership of our common units on the first day of each month,
instead of on the basis of the date a particular common unit is
transferred. The use of this proration method may not be
permitted under existing Treasury Regulations, and, accordingly,
our counsel is unable to opine as to the validity of this
method. If the IRS were to challenge this method or new Treasury
regulations were issued, we might be required to change the
allocation of items of income, gain, loss, and deduction among
our unitholders. See Material Tax Consequences
Disposition of Common Units Allocations Between
Transferors and Transferees.
47
A
unitholder whose common units are loaned to a short
seller to effect a short sale of common units may be
considered as having disposed of those common units. If so, it
would no longer be treated for federal income tax purposes as a
partner with respect to those common units during the period of
the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose common units are loaned to a
short seller to effect a short sale of common units
may be considered as having disposed of the loaned common units,
it may no longer be treated for federal income tax purposes as a
partner with respect to those common units during the period of
the loan to the short seller and the unitholder may recognize
gain or loss from such disposition. Moreover, during the period
of the loan to the short seller, any of our income, gain, loss,
or deduction with respect to those common units may not be
reportable by the unitholder and any cash distributions received
by the unitholder as to those common units could be fully
taxable as ordinary income. Our counsel has not rendered an
opinion regarding the treatment of a unitholder where common
units are loaned to a short seller to effect a short sale of
common units; therefore, our unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to consult a tax advisor
to discuss whether it is advisable to modify any applicable
brokerage account agreements to prohibit their brokers from
loaning their common units.
We
will adopt certain valuation methodologies and monthly
conventions for federal income tax purposes that may result in a
shift of income, gain, loss, and deduction between our general
partner and our unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common
units.
When we issue additional common units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss, and deduction between certain unitholders
and our general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent
purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our valuation methods,
or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of taxable income, gain, loss, and deduction between
our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
taxable gain from our unitholders sale of common units and
could have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our Partnership for federal income tax
purposes.
We will be considered to have technically terminated our
Partnership for federal income tax purposes if there is a sale
or exchange of 50% or more of the total interests in our capital
and profits within a twelve-month period. For purposes of
determining whether the 50% threshold has been met, multiple
sales of the same interest will be counted only once. Our
technical termination would, among other things, result in the
closing of our taxable year for all unitholders, which would
result in us filing two tax returns (and our unitholders could
receive two Schedules K-1 if relief is not available, as
described below) for one fiscal year and could result in a
deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a
taxable year other than a fiscal year ending December 31,
the closing of our taxable year may also result in more than
twelve months of our taxable income or loss being includable in
its taxable income for the year of termination. Our termination
currently would not affect our classification as a partnership
for federal income tax purposes, but instead we would be treated
as a new partnership for tax purposes. If treated as a new
partnership, we must make new tax elections and could be subject
to penalties if
48
we are unable to determine that a termination occurred. The IRS
has recently announced a publicly traded partnership technical
termination relief program whereby, if a publicly traded
partnership that is technically terminated requests special
relief and such relief is granted by the IRS, among other
things, the partnership will have to provide only one
Schedule K-1
to unitholders for the tax year in which the termination occurs
notwithstanding two partnership tax years. See Material
Tax Consequences Disposition of Common
Units Constructive Termination for a
discussion of the consequences of our termination for federal
income tax purposes.
As a
result of investing in our common units, you may become subject
to state and local taxes and return filing requirements in
jurisdictions where we operate or own or acquire
properties.
In addition to federal income taxes, you will likely be subject
to other taxes, including state and local taxes, unincorporated
business taxes, and estate, inheritance or intangible taxes that
are imposed by the various jurisdictions in which we conduct
business or control property now or in the future, even if you
do not live in any of those jurisdictions. You will likely be
required to file state and local income tax returns and pay
state and local income taxes in some or all of these various
jurisdictions. Further, you may be subject to penalties for
failure to comply with those requirements. We initially expect
to conduct business in Kentucky, which currently imposes a
personal income tax on individuals. As we make acquisitions or
expand our business, we may control assets or conduct business
in additional states that impose a personal income tax. It is
your responsibility to file all federal, state, and local tax
returns. Our counsel has not rendered an opinion on the state or
local tax consequences of an investment in our common units.
49
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:
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market demand for coal and electricity;
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geologic conditions, weather and other inherent risks of coal
mining that are beyond our or our lessees control;
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competition within our industry and with producers of competing
energy sources;
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excess production and production capacity;
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our ability to acquire or develop coal reserves in an
economically feasible manner;
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inaccuracies in our estimates of our coal reserves;
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availability and price of mining and other industrial supplies,
including steel-based supplies, diesel fuel, rubber tires and
explosives;
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availability of skilled employees and other workforce factors;
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disruptions in the quantities of coal produced from our reserves
as a consequence of weather or equipment or mine failures;
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our lessees ability to collect payments from its customers;
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defects in title or the loss of a leasehold interest;
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railroad, barge, truck and other transportation performance and
costs affecting the timing or delivery of our lessees coal
to customers;
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our lessees ability to secure new coal supply arrangements
or to renew existing coal supply arrangements;
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our lessees relationships with, and other conditions
affecting, its customers;
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the deferral of contracted shipments of coal by our
lessees customers;
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our ability to service our outstanding indebtedness;
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our ability to comply with the restrictions imposed by Armstrong
Energys Senior Secured Credit Facility and other financing
arrangements, as applicable to us;
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the availability and cost of surety bonds;
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terrorist attacks, military action or war;
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50
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our lessees ability to obtain and renew various permits,
including permits authorizing the disposition of certain mining
waste;
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existing and future legislation and regulations affecting both
our lessees coal mining operations and its 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;
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customers ability to meet existing or new regulatory
requirements and associated costs, including disposal of coal
combustion waste material;
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Armstrong Energys ability to attract/retain key management
personnel;
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efforts to organize our lessees workforce for
representation under a collective bargaining agreement; and
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the other factors affecting our business described below under
the caption Risk Factors.
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51
USE OF
PROCEEDS
We estimate that the net proceeds to us from the sale of our
common units in this offering will be $17.5 million, at an
assumed initial public offering price of
$ per unit, 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. Our net proceeds will increase by
approximately $1.9 million if the underwriters option
to purchase additional units is exercised in full. Each $1.00
increase (decrease) in the assumed initial public offering price
of $ per unit, 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
$0.9 million, or $1.0 million if the
underwriters option is exercised in full, assuming the
number of units 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 the net proceeds from this offering to purchase
an additional estimated 8% to 10% partial undivided interest in
substantially all of the coal reserves and real property owned
by Armstrong Energy previously subject to options exercised by
us on February 9, 2011. As of March 31, 2012, we had a
50.81% interest in such reserves. The actual percentage acquired
will depend on the fair value of the reserves at the time of
acquisition. See Certain Relationships and Related Party
Transactions Western Diamond and Western Land Coal
Reserves Sale Agreement. Armstrong Energy intends to use
the proceeds of the sale of the partial undivided interest to us
to repay a portion of Armstrong Energys outstanding
borrowings under the Senior Secured Revolving Credit Facility.
52
CAPITALIZATION
The following table shows:
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Our capitalization as of March 31, 2012; and
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Our pro forma capitalization as of December 31, 2011, as
adjusted to reflect the net proceeds from this offering of
common units at an assumed public offering price of
$ per unit (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.
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We derived this table from, and it should be read in conjunction
with and is qualified in its entirety by reference to, our
historical 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 and
Managements Discussion and Analysis of Financial
Condition and Results of Operations.
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As of March 31, 2012
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As
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Actual
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Adjusted(1)(2)(3)
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(unaudited)
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(In thousands)
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Cash and cash equivalents
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$
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155
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$
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17,655
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Total long-term debt
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$
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$
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Partners capital:
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Series A preferred units
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20,000
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Common unitholders
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134,877
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172,377
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General partner
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401
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401
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Total partners capital
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155,278
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172,778
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Total capitalization
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$
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155,278
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$
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172,778
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(1) |
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Each $1.00 increase or decrease in the assumed public offering
price of $ per unit would increase
or decrease, respectively, each of total partners capital
and total capitalization by approximately $0.9 million,
after deducting the underwriting discount and estimated offering
expenses payable by us. We may also increase or decrease the
number of units we are offering. Each increase of
0.1 million units offered by us, together with a
concomitant $1.00 increase in the assumed offering price to
$ per unit, would increase total
partners capital and total capitalization by approximately
$2.9 million. Similarly, each decrease of 0.1 million
units offered by us, together with a concomitant $1.00 decrease
in the assumed offering price to
$ per unit, would decrease total
partners capital and total capitalization by approximately
$2.7 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. |
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(2) |
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Reflects the conversion of the outstanding Series A
convertible preferred units as a result of the consummation of
this offering into 1,068,376 common units based on an assumed
initial public offering price of
$ per unit (the midpoint of the
range on the cover of this prospectus). |
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(3) |
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Does not reflect the expected acquisition of an additional
estimated 8% to 10% partial undivided interest in certain
reserves of Armstrong Energy with the net proceeds from this
offering. See Use of Proceeds. |
53
DILUTION
Dilution is the amount by which the offering price paid by the
purchasers of units sold in this offering will exceed the pro
forma net tangible book value per unit after the offering. On a
pro forma basis as of March 31, 2012, after giving effect
to the offering of common units, the conversion of our
Series A convertible preferred units into 1,068,376 common
units, and the application of the related net proceeds, and
assuming the underwriters option to purchase additional
common units is not exercised, our net tangible book value was
$172.8 million, or $13.82 per unit. Purchasers of common
units in this offering will experience substantial and immediate
dilution in net tangible book value per common unit for
financial accounting purposes, as illustrated in the following
table:
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Assumed initial public offering price per common unit
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$
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Net tangible book value per unit before the offering(1)
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$
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14.89
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Decrease in net tangible book value per unit attributable to
purchasers in the offering
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(1.07
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)
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Less: Pro forma net tangible book value per unit after the
offering(2)
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13.82
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Immediate dilution in tangible net book value per unit to
purchasers in the offering(3)
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$
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6.18
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(1) |
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Determined by dividing the sum of the 38,023 general
partner units and the 10,393,601 common units held by its
affiliates, into the net tangible book value of our assets. |
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(2) |
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Determined by dividing the total number of units to be
outstanding after this offering (12,461,977 common units and
38,023 general partner units) into our pro forma net tangible
book value, after giving effect to the application of the
expected net proceeds of this offering. |
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(3) |
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If the initial public offering price were to increase or
decrease by $1.00 per common unit, then dilution in net tangible
book value per common unit would equal $13.90 and $13.75,
respectively. |
The following table sets forth the number of units that we will
issue and the total consideration contributed to us by our
general partner and its affiliates and by the purchasers of
common units in this offering upon the closing of the
transactions contemplated by this prospectus:
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Units Acquired
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Total Consideration
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Number
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Percent
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Amount
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Percent
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(In thousands)
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General partner and affiliates(1)(2)
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11,500
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92.0
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%
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$
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134,700
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87.1
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%
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Purchasers in the offering
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1,000
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8.0
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20,000
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12.9
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Total
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12,500
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100.0
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%
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$
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154,700
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100.0
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%
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(1) |
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Includes 38,023 general partner units acquired by our
general partner and 11,461,977 common units held by its
affiliates. |
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(2) |
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Assumes the underwriters option to purchase additional
common units is not exercised. |
54
CASH
DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
Distributions
of Available Cash
General. Pursuant to our Partnership
Agreement, within 45 days following the end of each
quarter, we may, in the sole and exclusive discretion of Elk
Creek GP, our general partner, distribute an amount equal to
some or all of our available cash with respect to such quarter,
subject to
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act (the
Delaware Act), pro rata to the partners as of the
record date selected by our general partner in its reasonable
discretion. All distributions required under the Partnership
Agreement shall be made subject to
Section 17-607
of the Delaware Act, and the Partnership shall not be required
to distribute any portion of available cash at any time, except
as may be directed in the sole discretion of our general partner.
Definition of Available Cash. Available cash
generally means, for each fiscal quarter ending prior to our
liquidation date:
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the sum of (i) all cash and cash equivalents of our
Partnership and our subsidiaries on hand at the end of such
quarter, and (ii) all additional cash and cash equivalents
of our Partnership and our subsidiaries on hand on the date of
determination of available cash with respect to such quarter
resulting from working capital borrowings made subsequent to the
end of such quarter, less
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the amount of any cash reserves that are necessary or
appropriate in the reasonable discretion of our general partner
to (i) provide for the proper conduct of the business of
our Partnership and our subsidiaries (including reserves for
future capital expenditures and for anticipated future credit
needs of our Partnership and our subsidiaries) subsequent to
such quarter, (ii) comply with applicable law or any loan
agreement, security agreement, mortgage, debt instrument or
other agreement or obligation to which we or any of our
subsidiaries is a party or by which we or it is bound or our or
its assets are subject or (iii) provide funds for further
distributions; provided, however, that
disbursements made by us or any of our subsidiaries or cash
reserves established, increased or reduced after the end of such
quarter but on or before the date of determination of available
cash with respect to such quarter shall be deemed to have been
made, established, increased or reduced, for purposes of
determining available cash, within such quarter if our general
partner so determines.
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Notwithstanding the foregoing, available cash with respect to
the quarter in which our liquidation date occurs and any
subsequent quarter shall equal zero.
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Restrictions under the Senior Secured Credit Facility and the
Royalty Deferment and Option Agreement. The
Senior Secured Credit Facility restricts our ability to pay
distributions. Under the terms of the Senior Secured Credit
Facility, without the consent of all lenders (if there are fewer
than three lenders at the time of any dividend or distribution)
or the lenders having more than 50% of the aggregate commitments
(if there are three or more lenders at the time of any dividend
or distribution) under that facility, we are currently
prohibited from making dividend payments or other distributions
to holders of our partnership interests in excess of
$5.0 million per year and $10.0 million in aggregate,
except for dividends or other distributions in amounts necessary
to enable holders of our partnership interests to pay
anticipated income tax liabilities arising from their ownership
interests in the Partnership until February 9, 2016, the
date on which the Senior Secured Credit Facility matures.
Our lessee, Armstrong Energy, has historically deferred the
payment to us of cash royalties pursuant to a Royalty Deferment
and Option Agreement which it has entered into with us, and we
expect that Armstrong Energy will continue to make such
deferrals for the foreseeable future. Pursuant to the terms of
that Agreement, in the event that Armstrong Energy exercises its
deferral right, we have the right to acquire additional
undivided interests in coal reserves controlled by Armstrong
Energy. We expect that for the foreseeable future all or a
substantial portion of our royalty revenues will be used by us
to acquire such additional coal reserve interests and will not
be a source of cash for the payment of dividends or other
distributions to our limited partners.
55
Except for distributions in amounts necessary to enable limited
partners to pay anticipated income tax liabilities arising from
their ownership interests in the Partnership, which will be
paid, if at all, solely at the discretion of our general partner
we do not anticipate paying any distributions for the
foreseeable future.
Distributions
of Cash Upon Liquidation
If we dissolve in accordance with our Partnership Agreement, we
will sell or otherwise dispose of our assets in a process called
a liquidation. In the event of the dissolution and liquidation
of the Partnership, all receipts received during or after the
quarter in which the liquidation date occurs, other than from
certain working capital borrowings, shall be applied and
distributed solely in accordance with, and subject to the
following terms and conditions.
The liquidator shall proceed to dispose of the assets of the
Partnership, discharge its liabilities, and otherwise wind up
its affairs in such manner and over such period as the
liquidator determines to be in the best interest of the
partners, subject to
Section 17-804
of the Delaware Act and the following:
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The assets may be disposed of by public or private sale or by
distribution in kind to one or more partners on such terms as
the liquidator and such partner or partners may agree. If any
property is distributed in kind, the partner receiving the
property shall be deemed to have received cash equal to its fair
market value; and contemporaneously therewith, appropriate cash
distributions must be made to the other partners. The liquidator
may, in its absolute discretion, defer liquidation or
distribution of the Partnerships assets for a reasonable
time if it determines that an immediate sale or distribution of
all or some of the Partnerships assets would be
impractical or would cause undue loss to the partners. The
liquidator may, in its absolute discretion, distribute the
Partnerships assets, in whole or in part, in kind if it
determines that a sale would be impractical or would cause undue
loss to the partners.
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Liabilities of the Partnership include amounts owed to the
liquidator as compensation for serving in such capacity and
amounts owed to partners otherwise than in respect of their
distribution rights under the Partnership Agreement. With
respect to any liability that is contingent, conditional or
unmatured or is otherwise not yet due and payable, the
liquidator shall either settle such claim for such amount as it
thinks appropriate or establish a reserve of cash or other
assets to provide for its payment. When paid, any unused portion
of the reserve shall be distributed as additional liquidation
proceeds.
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All property and all cash in excess of that required to
discharge liabilities as provided above shall be distributed to
the partners in accordance with, and to the extent of, the
positive balances in their respective capital accounts, as
determined after taking into account all capital account
adjustments (other than those made by reason of distributions
pursuant to this provision for the taxable period of the
Partnership during which the liquidation of the Partnership
occurs (with such date of occurrence being determined pursuant
to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and
such distribution shall be made by the end of such taxable
period (or, if later, within 90 days after said date of
such occurrence).
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56
SELECTED
HISTORICAL
CONSOLIDATED FINANCIAL AND OPERATING DATA
The following table presents our selected historical
consolidated financial and operating data for the periods
indicated. The summary historical financial data for the years
ended December 31, 2008, 2009, 2010 and 2011 and the
balance sheet data as of December 31, 2008, 2009, 2010 and
2011 are derived from the audited financial statements appearing
elsewhere in this prospectus. The selected historical financial
data for the three months ended March 31, 2012 and 2011 and
the balance sheet data as of March 31, 2012 and 2011 are
derived from the unaudited financial statements appearing
elsewhere in this prospectus. 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.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Three Months Ended March 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
|
|
|
Unaudited
|
|
|
|
(In thousands, except per unit amounts)
|
|
|
Results of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,789
|
|
|
$
|
1,238
|
|
|
$
|
3,081
|
|
Costs and expenses
|
|
|
332
|
|
|
|
330
|
|
|
|
817
|
|
|
|
7,605
|
|
|
|
802
|
|
|
|
4,717
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(332
|
)
|
|
|
(330
|
)
|
|
|
(817
|
)
|
|
|
184
|
|
|
|
436
|
|
|
|
(1,636
|
)
|
Interest expense
|
|
|
(4,877
|
)
|
|
|
(1,723
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
|
|
|
|
161
|
|
|
|
4,209
|
|
|
|
1,009
|
|
|
|
1,009
|
|
|
|
|
|
Other income (expense), net
|
|
|
|
|
|
|
(2
|
)
|
|
|
(60
|
)
|
|
|
1,148
|
|
|
|
162
|
|
|
|
256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(5,209
|
)
|
|
$
|
(1,894
|
)
|
|
$
|
3,332
|
|
|
$
|
2,341
|
|
|
$
|
1,607
|
|
|
$
|
(1,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per limited partner unit, basic, without giving
effect to the unit split
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|
$
|
(19.79
|
)
|
|
$
|
(2.62
|
)
|
|
$
|
2.96
|
|
|
$
|
1.74
|
|
|
$
|
1.20
|
|
|
$
|
(1.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per limited partner unit, diluted, without
giving effect to the unit split
|
|
$
|
(19.79
|
)
|
|
$
|
(2.62
|
)
|
|
$
|
2.96
|
|
|
$
|
1.73
|
|
|
$
|
1.20
|
|
|
$
|
(1.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per limited partner unit, basic and diluted,
assuming unit split(1)
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|
$
|
(2.60
|
)
|
|
$
|
(0.34
|
)
|
|
$
|
0.39
|
|
|
$
|
0.23
|
|
|
$
|
0.16
|
|
|
$
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data (at period end)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
78,683
|
|
|
$
|
91,097
|
|
|
$
|
137,929
|
|
|
$
|
167,559
|
|
|
$
|
144,623
|
|
|
$
|
166,037
|
|
Working capital
|
|
|
(28,667
|
)
|
|
|
215
|
|
|
|
155
|
|
|
|
619
|
|
|
|
155
|
|
|
|
651
|
|
Total partners capital
|
|
|
49,791
|
|
|
|
89,497
|
|
|
|
125,929
|
|
|
|
156,181
|
|
|
|
132,536
|
|
|
|
155,278
|
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty coal tons produced by lessee (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,717
|
|
|
|
458
|
|
|
|
1,012
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
(5,255
|
)
|
|
$
|
(308
|
)
|
|
$
|
13,792
|
|
|
$
|
8,007
|
|
|
$
|
2,221
|
|
|
$
|
2,095
|
|
Investing activities
|
|
|
(24,458
|
)
|
|
|
(12,424
|
)
|
|
|
(46,892
|
)
|
|
|
(33,007
|
)
|
|
|
(7,221
|
)
|
|
|
339
|
|
Financing activities
|
|
|
29,878
|
|
|
|
12,722
|
|
|
|
33,100
|
|
|
|
25,000
|
|
|
|
5,000
|
|
|
|
(2,434
|
)
|
EBITDA (unaudited)(2)
|
|
|
(332
|
)
|
|
|
(332
|
)
|
|
|
(877
|
)
|
|
|
8,084
|
|
|
|
1,212
|
|
|
|
3,086
|
|
EBITDA is calculated as follows (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(5,209
|
)
|
|
$
|
(1,894
|
)
|
|
$
|
3,332
|
|
|
$
|
2,341
|
|
|
$
|
1,607
|
|
|
$
|
(1,380
|
)
|
Depletion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,841
|
|
|
|
614
|
|
|
|
1,555
|
|
Unit-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,911
|
|
|
|
|
|
|
|
2,911
|
|
Interest, net
|
|
|
4,877
|
|
|
|
1,562
|
|
|
|
(4,209
|
)
|
|
|
(1,009
|
)
|
|
|
(1,009
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(332
|
)
|
|
$
|
(332
|
)
|
|
$
|
(877
|
)
|
|
$
|
8,084
|
|
|
$
|
1,212
|
|
|
$
|
3,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Per unit calculation reflects the assumed 7.6047-to-1 unit split
to be effected prior the effectiveness of the registration
statement of which this prospectus forms a part. |
57
|
|
|
(2) |
|
EBITDA is a non-GAAP financial measure, and when analyzing our
operating performance, investors should use 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 EBITDA as a supplemental financial measure. EBITDA is
defined as net income (loss) before interest, net, unit
compensation expense and depletion. |
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|
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 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 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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|
|
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 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
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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.
|
58
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.
Overview
We are a limited partnership 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. As of March 31, 2012, we wholly own
approximately 65 million tons of coal reserves and have a
50.81% undivided interest in approximately 140 million tons
of coal reserves, all located in Ohio and Muhlenberg counties in
Western Kentucky. Our coal is generally low chlorine, high
sulfur coal. Our outstanding limited partnership interests
(common units), representing 99.7% of our equity
interests, are owned by investment funds managed by Yorktown
Partners LLC (collectively, Yorktown). We are not
engaged in the permitting, production or sale of coal, nor in
the operation or reclamation of coal mining activity. We are a
fee mineral and surface rights owning entity. It is our
intention to remain a coal leasing enterprise and not to engage
in coal production ourselves.
We currently lease all of our reserves to Armstrong Energy in
exchange for royalty payments in the amount of 7% of the revenue
received from coal sold from those reserves. Armstrong Energy is
a diversified producer of low chlorine, high sulfur thermal coal
from the Illinois Basin with both surface and underground mines.
A subsidiary of Armstrong Energy, Inc., Elk Creek GP, is our
general partner. Pursuant to our Partnership Agreement, Elk
Creek GP has the exclusive authority to conduct, direct and
manage all of our activities. By virtue of Armstrong
Energys control of Elk Creek, GP, our results are
consolidated in Armstrong Energys historical consolidated
financial statements. Pursuant to our Existing Partnership
Agreement, effective October 1, 2011, Yorktown unilaterally
may remove Elk Creek GP as our general partner in some
circumstances. As a result, Armstrong Energy will no longer
consolidate our results in its financial statements (the
Deconsolidation).
2011 was the first year production occurred under our
leases to Armstrong Energy. Based on its coal production during
2011 and the three months ended March 31, 2012. Armstrong
Energy is obligated to pay us $7.2 million and
$2.1 million, respectively, for production royalties under
our leases for such period. In addition, we earned a credit and
collateral support fee as a result of our financing activities
in the amount of $1.15 million and $0.3 million in
2011 and the three months ended March 31, 2012,
respectively.
Factors
that Impact Our Business
Our lessee sells the majority of our coal under multi-year coal
supply agreements. Our lessee intends to continue to enter into
multi-year coal supply agreements for a substantial portion of
their annual coal production, using their remaining production
to take advantage of market opportunities as they present
themselves. We believe their use of multi-year coal supply
agreements reduces their exposure to fluctuations in the spot
price for coal and provides us with a reliable and stable
revenue base with which to earn royalties. Using multi-year coal
supply agreements also allows them to partially mitigate their
exposure to rising costs, to the extent those contracts have
full or partial cost pass through provisions or inflation
adjustment provisions. For example, their contracts with LGE
contain provisions that adjust the price paid for their coal in
the event there is change in the price of diesel fuel, a key
cost component in our coal production. Certain of their other
contracts, such as those with TVA, contain provisions that
permit them to seek additional price adjustments to account for
changes in environmental and other laws and regulations to which
they are subject, to the extent those changes increase the cost
of their production of coal.
59
We believe the other key factors that influence our business are:
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|
|
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.
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 2011 decreased by
approximately 42 million tons, or 4.0%, from 2010 levels.
The decline in U.S. domestic coal consumption during 2011
and early 2012 was partially a function of the switching to
other sources of fuel. However, 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.
Related
Party Transactions
Elk Creek GP, a subsidiary of Armstrong Energy, is our general
partner and owns a 0.3% equity interest in us. Elk Creek GP does
not receive any management fee or other compensation for its
management of the Partnership. However, in accordance with the
partnership agreement, we reimburse Elk Creek GP for expenses
incurred on our behalf. All direct operating, general and
administrative expenses are charged to us as incurred. We also
reimburse indirect general and administrative costs, including
certain legal, accounting, and other professional services
incurred by Elk Creek GP.
Three
Months Ended March 31, 2012 Compared to the Three Months
Ended March 31, 2011
Revenue
Revenue for the three months ended March 31, 2012 totaled
$3.1 million, as compared to $1.2 for the same period of
2011. We began earning revenue under our leases to Armstrong
Energy in February 2011, resulting in a full quarter earned in
2012, compared to a partial quarter in the prior year. Total
tons sold by Armstrong Energy during the three months ended
March 31, 2012 that generated royalty revenues was
approximately 1.0 million tons, resulting in average
royalty revenue per ton of $3.04 compared to 0.5 million
tons and an average royalty per ton of $2.70 for the same period
in 2011.
60
Related
Party Service Expense
Related party service expense of $0.2 million for the three
months ended March 31, 2012 is consistent with that
incurred in the same period of 2011. Amount relates to general
administrative and management services provided by Armstrong
Energy on our behalf.
Depletion
Expense
Depletion expense was $1.6 million for the three months
ended March 31, 2011, as compared to $0.6 million for
the same period of the prior year. The increase is due to
additional production in 2012 under our leases to Armstrong
Energy.
Unit-Based
Compensation Expense
Unit-based compensation expense was $2.9 million for the
three months ended March 31, 2012 compared to zero for the
same period in 2011. This expense relates to restricted unit
grants made in the fourth quarter of 2011 that vested on
March 31, 2012. The fair value of the grants was
$5.8 million, which was recognized ratably over the vesting
period.
Interest
Income
Interest income decreased $1.0 million to zero for the
three months ended March 31, 2012. The decrease is due to
the conversion in February 2011 of amounts owed to us by
Armstrong Energy into an undivided interest in certain mineral
reserves and land of Armstrong Energy.
Other
Income
Other income totaled $0.3 million for the three months
ended March 31, 2012, as compared to $0.2 million for
the same period of 2011. On February 9, 2011, Armstrong
Energy entered into a new credit agreement, whereby we agreed to
be a co-borrower with respect to the Senior Secured Term Loan
and pledged our assets as collateral and became a guarantor with
respect to the Senior Secured Revolving Credit Facility and the
Senior Secured Term Loan. In exchange, Armstrong Energy has
agreed to pay us a credit support fee equal to 1% of the
weighted average outstanding balance under the credit agreement,
which can be as much as $150.0 million. As of
March 31, 2012, the principal amount outstanding under the
credit agreement was $120.0 million and the credit support
fee paid for the three months ended March 31, 2012 and 2011
totaled $0.3 million and $0.1 million, respectively.
Year
Ended December 31, 2011 Compared to the Year Ended
December 31, 2010
Revenue
Revenue for the year ended December 31, 2011 totaled
$7.8 million, as compared to zero for the same period of
2010. The increase is due to 2011 being the first year we
recognized revenue under our leases to Armstrong Energy. Total
tons sold by Armstrong Energy during the year ended
December 31, 2011 that generated royalty revenues was
approximately 2.7 million tons, resulting in average
royalty revenue per ton of $2.87.
Related
Party Service Expense
Related party service expense of $0.7 million for the year
ended December 31, 2011 is consistent with that incurred in
the same period of 2010. Amount relates to general
administrative and management services provided by Armstrong
Energy on our behalf.
61
Depletion
Expense
Depletion expense was $3.8 million for the year ended
December 31, 2011, as compared to zero for the same period
of the prior year. The increase is due to 2011 being the first
year production occurred under our leases to Armstrong Energy
resulting in depletion to only be incurred during the current
year.
Interest
Income
Interest income decreased $3.2 million, or 76.0%, to
$1.0 million for the year ended December 31, 2011, as
compared to $4.2 million for the same period of 2010. The
decrease is due primarily to the conversion in February 2011 of
amounts owed to us by Armstrong Energy into an undivided
interest in certain mineral reserves and land of Armstrong
Energy.
Other
Income
Other income totaled $1.1 million for the year ended
December 31, 2011, as compared to zero for the same period
of 2010. On February 9, 2011, Armstrong Energy entered into
a new credit agreement, whereby we agreed to be a co-borrower
with respect to the Senior Secured Term Loan and pledged our
assets as collateral and became a guarantor with respect to the
Senior Secured Revolving Credit Facility and the Senior Secured
Term Loan. In exchange, Armstrong Energy has agreed to pay us a
credit support fee equal to 1% of the weighted average
outstanding balance under the credit agreement, which can be as
much as $150.0 million. As of December 31, 2011, the
principal amount outstanding under the credit agreement was
$140.0 million and the credit support fee paid for the year
ended December 31, 2011 totaled $1.1 million.
Year
Ended December 31, 2010 Compared to Year Ended
December 31, 2009
Other
Operating, General and Administrative Costs
Other operating, general, and administrative costs decreased
$0.2 million, or 60.2%, to $0.1 million for the year
ended December 31, 2010, as compared to $0.3 million
for the year ended December 31, 2009. The decrease is due
primarily to additional professional fees incurred during 2009
related to a financing that was cancelled.
Related-Party
Service Expense
Related-party service expense increased to $0.7 million for
the year ended December 31, 2010. The increase represents
an allocation of shared accounting and administrative expenses
incurred on our behalf by Armstrong Energy.
Interest
Income
Interest income increased $4.0 million to $4.2 million
for the year ended December 31, 2010, as compared to
$0.2 million for the year prior. The increase is due
primarily to additional interest income earned on promissory
notes made in favor of Armstrong Energy. In November 2009, March
2010, May 2010, and November 2010, we advanced
$11.0 million, $9.5 million, $12.6 million, and
$11.0 million, respectively, to Armstrong Energy in order
for them to meet certain debt service obligations. Each
promissory note bears interest at the greater of 3% per annum or
7% of the sales price for coal sold from certain properties
specified in the promissory notes.
Interest
Expense
Interest expense declined to zero for the year ended
December 31, 2010, as compared to expense of
$1.7 million for the year ended December 31, 2009.
Interest expense incurred during 2009 related to an outstanding
promissory note issued for the acquisition of mineral rights and
other assets, which was paid in full in June 2009.
62
Liquidity
and Capital Resources
Liquidity
Our business is capital intensive and requires substantial
expenditures for purchasing additional reserves. Our principal
liquidity requirements are to finance current operations and
fund capital expenditures, including acquisitions of additional
mineral reserves. Our primary sources of liquidity to meet these
needs have been secured borrowings and contributions from
Yorktown. We are not permitted to borrow additional funds under
the Senior Secured Credit Facility and as such, it is not a
source of liquidity for us.
We believe that cash generated from operations will be
sufficient to meet working capital requirements for at least the
next several years. Our ability to fund acquisitions will depend
upon our 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.
Cash
Flows
The following table reflects cash flows for the applicable
periods:
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|
|
|
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|
Three Months Ended
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|
Year Ended December 31,
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March 31,
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|
2009
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2010
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|
2011
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|
2011
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|
2012
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|
|
(In thousands)
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|
|
|
|
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|
Net cash provided by (used in):
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|
|
|
|
|
|
|
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|
Operating Activities
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|
$
|
(308
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)
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|
$
|
13,792
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|
|
$
|
8,007
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|
|
$
|
2,221
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|
|
$
|
2,095
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|
Investing Activities
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|
$
|
(12,424
|
)
|
|
$
|
(46,892
|
)
|
|
$
|
(33,007
|
)
|
|
$
|
(7,221
|
)
|
|
$
|
339
|
|
Financing Activities
|
|
$
|
12,722
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|
|
$
|
33,100
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|
|
$
|
25,000
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|
|
$
|
5,000
|
|
|
$
|
(2,434
|
)
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Three
Months Ended March 31, 2012 Compared to Three Months Ended
March 31, 2011
Net cash provided by operating activities was $2.1 million
for the three months ended March 31, 2012, a decrease of
$0.1 million from net cash provided by operating activities
of $2.2 million for the same period of 2011. We experienced
a decline in earnings in the three months ended March 31,
2012, as compared to the same period of the prior year, due to
primarily to higher depletion and unit compensation expense,
offset partially by an increase in revenue from higher
production under our leases to Armstrong Energy. We also
experienced a decline in other non-current liabilities in the
current year of approximately $1.0 million related to the
recognition of deferred revenue earned from certain of our
leases to Armstrong Energy.
Net cash provided by investing activities was $0.3 million
for the three months ended March 31, 2012, as compared to
net cash used in investing activities of $7.2 million for
the three months March 31, 2011. For the three months ended
March 31, 2012, we completed the exchange of certain
amounts owed to us by Armstrong Energy totaling
$25.7 million for a 11.36% undivided interest in certain
mineral reserves and land of Armstrong Energy. For the three
months ended March 31, 2011, the net use of cash primarily
relates to the exercise of our option to obtain a 39.45%
undivided interest in certain mineral reserves and land of
Armstrong Energy in satisfaction of certain promissory notes,
plus accrued interest and other long-term receivables owed by
Armstrong Energy totaling approximately $52.5 million. In
connection with that exercise, we 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 us to acquire the undivided interest in
certain mineral reserves and land with a fair value of
$69.5 million. We had a total undivided interest in certain
reserves and land of Armstrong Energy of 50.81% at
March 31, 2012.
Net cash used in financing activities was $2.4 million for
the three months ended March 31, 2012, as compared to net
cash provided in financing activities of $5.0 million for
the same period of the year prior. For the three months ended
March 31, 2012, we repurchased 17,765 common units for
$2.4 million to satisfy the tax obligations of the grantees
who received restricted stock awards. Net cash provided by
financing activities of $5.0 million for the three months
ended March 31, 2011 related to partner contributions made
in connection the acquisition of certain mineral reserves
discussed above.
63
Year
Ended December 31, 2011 Compared to Year Ended
December 31, 2010
Net cash provided by operating activities was $8.0 million
for the year ended December 31, 2011, a decrease of
$5.8 million from net cash provided by operating activities
of $13.8 million for the same period of 2010. The decrease
in cash provided by operating activities was principally
attributable to the reduced receivable related to interest due
from Armstrong Energy of $10.4 million, offset by higher
depletion expense in 2011, as 2011 is the first year production
occurred under our leases with Armstrong Energy and unit
compensation expense related to grants issued in 2011.
Net cash used in investing activities was $33.0 million for
the year ended December 31, 2011 compared to
$46.9 million for the year ended December 31, 2010.
For the year ended December 31, 2011, the net use of cash
primarily relates to the exercise of our option to obtain a
39.45% undivided interest in certain mineral reserves and land
of Armstrong Energy in satisfaction of certain promissory notes,
plus accrued interest and other long-term receivables owed by
Armstrong Energy totaling approximately $52.5 million. In
connection with that exercise, we 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 us to acquire the undivided interest in
certain mineral reserves and land with a fair value of
$69.5 million. The net use of cash for the year ended
December 31, 2010 relates primarily to advances made to
Armstrong Energy.
Net cash provided by financing activities was $25.0 million
for the year ended December 31, 2011 compared to
$33.1 million for the same period of the year prior. This
decrease is due to $8.1 million of higher partner
contributions in 2010, which was loaned to Armstrong Energy for
the repayment of long-term debt and reserves purchases.
Year
Ended December 31, 2010 Compared to Year Ended
December 31, 2009
Net cash provided by operating activities was $13.8 million
for 2010, an increase of $14.1 million from net cash used
in operating activities of $0.3 million for 2009. The
increase in cash provided by operating activities was
principally attributable to an increase in net income of
$5.2 million related to interest earned on promissory notes
and the increase in advance royalties of $8.8 million in
2010 on mineral reserves leased to Armstrong Energy.
Net cash used in investing activities was $46.9 million for
2010 compared to $12.4 million for 2009. The
$34.5 million change was primarily attributable to an
increase in amounts loaned to Armstrong Energy of
$26.1 million for debt service obligations and an increase
in other receivables, net owed by Armstrong Energy of
$8.3 million, primarily related to advance royalties.
Net cash provided by financing activities was $33.1 million
for 2010 compared to $12.7 million for 2009. This
difference was primarily attributable to a decrease in partner
capital contributions of $8.5 million in 2010 and the
repayment of outstanding debt obligations in 2009 of
$28.9 million.
Off-Balance
Sheet Arrangements
In February 2011, Armstrong Energy entered into a 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. We agreed to be a
co-borrower with respect to the Senior Secured Term Loan and
pledged our assets as collateral and became a guarantor with
respect to the Senior Secured Revolving Credit Facility and the
Senior Secured Term Loan. In exchange, Armstrong Energy has
agreed to pay us a credit support fee equal to 1% of the
weighted average outstanding balance under the credit agreement,
which can be as much as $150.0 million. As of
March 31, 2012, the principal amount outstanding under the
credit agreement was $120.0 million and the credit support
fee paid for the three months ended March 31, 2012 totaled
$0.3 million. This debt is not recorded on our balance
sheet.
64
Contractual
Obligations
We do not have any contractual obligations due as of
December 31, 2011. As noted above, we are a co-borrower
with respect to Armstrong Energys Senior Secured Term Loan
and a guarantor with respect to the Senior Secured Revolving
Credit Facility and the Senior Secured Term Loan. The Senior
Secured Credit Facility matures in February 2016. As of
December 31, 2011, the outstanding balance of the Senior
Secured Credit Facility, which is included in the financial
statements of Armstrong Energy, consisted of $100.0 million
under the term loan and $40.0 million under the revolving
credit facility. The following table provides details of the
obligations due under the Senior Secured Term Loan as of
December 31, 2011:
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Payments Due by Period
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|
Less than
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More than
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|
Total
|
|
One Year
|
|
1-3 Years
|
|
3-5 Years
|
|
5 Years
|
|
Senior secured term loan obligations (principal and interest)
|
|
$
|
114,311
|
|
|
$
|
25,404
|
|
|
$
|
47,029
|
|
|
$
|
41,878
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|
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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.
We are an emerging growth company as such term is defined in the
JOBS Act. Section 107 of the JOBS Act provides that an
emerging growth company can take advantage of the extended
transition period provided in Section 7(a)(2)(B) of the
Securities Act for complying with new or revised accounting
standards. In other words, an emerging growth company can delay
the adoption of certain accounting standards until those
standards would otherwise apply to private companies. However,
we are choosing to opt out of such extended transition period,
and as a result, we will comply with new or revised accounting
standards on the relevant dates on which adoption of such
standards is required for non-emerging growth companies.
Section 107 of the JOBS Act provides that our decision to
opt out of the extended transition period for complying with new
or revised accounting standards is irrevocable.
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.
Royalty
Revenue
Royalty revenues are recognized on the basis of tons of coal
sold by Armstrong Energy and the corresponding revenue from
those sales. Generally, Armstrong Energy will make payments to
us based on a percentage of the gross sales price.
Depletion
We deplete our mineral reserves on a
units-of-production
basis by lease, based upon coal mined in relation to the net
cost of the mineral reserves and estimated proven and probable
tonnage in those reserves. We estimate proven and probable
mineral reserves with the assistance of third-party mining
consultants, and we use estimation techniques and recoverability
assumptions. We update our estimates of mineral reserves
periodically and this may result in material adjustments to
mineral reserves and depletion rates that we recognize
prospectively. In addition, we record depletion related to our
percentage ownership of reserves held by Armstrong Energy and us
as joint
tenants-in-common.
This amount is based on the depletion recorded by Armstrong
Energy and subject to the same methods of calculation that we
use to estimate our depletion.
65
Related
Party Other Receivables, Net
Related party other receivables, net primarily represents the
Partnerships cash position. Elk Creek GP manages, on
behalf of the Partnership, substantially all cash, investing and
financing activities of the Partnership. As such, the change in
related party other receivables, net is reflected as an
investing activity or a financing activity in the statements of
cash flows depending on whether it represents a net asset or net
liability for the Partnership.
Unit-Based
Compensation
We account for unit-based compensation in accordance with the
authoritative guidance on stock compensation. Under the fair
value recognition provisions of this guidance, unit-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 unit-based compensation tool used by us is through
awards of restricted units. The fair value of restricted units
is equal to the fair market value of our common units at the
date of grant and is amortized to expense ratably over the
vesting period, net of forfeitures. Because our common units are
not publicly traded, we must estimate the fair market value
based on multiple valuation methods. The valuation of our common
units was 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 units as of
the date of each 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 common
units underlying these restricted units 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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|
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any adjustment necessary to recognize a lack of marketability
for our common units;
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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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To date, our only restricted unit awards were granted in October
2011, totaling 323,199 units. We utilized a third party
specialist to determine the grant date fair value of the common
units awarded. The undiscounted fair value of our common units,
which totaled $18.94 per unit, was 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 is expected to occur within approximately six
months, a non-marketability discount of 5% was applied to
determine an overall fair value per share. Based on this
valuation, the overall fair value per unit was determined to be
$18.02. The total fair value of the grants of $5.8 million
was expensed through the vesting date of March 31, 2012.
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
66
became effective January 1, 2011. The new guidance did not
have an impact on our consolidated financial statements.
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 did not impact our
financial position, results of operations or cash flows.
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 did not 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 risk is related to commodity
prices.
Commodity
Price Risk
All of our coal is sold by Armstrong Energy through multi-year
coal supply agreements. Current conditions in the coal industry
may make it difficult for Armstrong Energy to extend existing
contracts or enter into supply contracts with terms of one year
or more. The failure to negotiate long-term contracts could
adversely affect the stability and profitability of Armstrong
Energys operations and adversely affect our coal royalty
revenues. If more coal is sold on the spot market, royalty
revenues may become more volatile due to fluctuations in spot
coal prices. A hypothetical increase or decrease of $1.00 per
ton to the average sales price of coal sold by Armstrong Energy
will result in a corresponding increase or decrease of $0.07 per
ton of royalty revenue associated with coal leased from our
wholly-owned reserves and will result in a corresponding
increase or decrease of $0.04 per ton of royalty revenue
associated with coal leased from our undivided interest in the
reserves of Armstrong Energy.
Seasonality
Our lessees 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 the
coal mined from our reserves. Adverse weather conditions, such
as floods or blizzards, can impact our lessees ability to
mine and ship our coal and its customers ability to take
delivery of coal. This variability could impact the royalties
paid to us by our lessee.
67
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 260 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 2011, 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 60% 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 2017 from 921 million
tons in 2011, 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. According to the EIA,
U.S. domestic thermal coal market consumption accounts for
approximately 85% of U.S. domestic coal production and
coal-fired electricity generation is expected to continue to be
the largest single fuel source of U.S. electricity (39% 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 lessees mines are located in the Western Kentucky
region of the Illinois Basin and contain 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 lease the mining rights to our coal to
Armstrong Energy, our sole lessee. Armstrong Energy competes
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 2011, 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.
68
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 42% of all
electricity generation in the United States in 2011. On a
long-term basis, 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 coal-fired generation
will continue to remain the largest single source of electricity
generation in 2035. According to the EIA, total electricity
generation in the United States decreased by 0.5% during 2011
compared with 2010, and U.S. electric generation from coal
decreased by 6.1% in 2011 compared with 2010 and is expected to
decreased by a further 10% in 2012. While the EIA projects that
electricity generation will grow at an annual average rate of
0.8% through 2035, it projects that the percentage of
electricity generated from coal will decrease to 39% of total
generation by 2035, compared with 42% during 2011.
|
The EIA projects coal-fueled electric power generation to
decline in 2012, primarily driven by depressed near-term natural
gas prices that are resulting in elevated levels of
coal-to-gas
switching. If
coal-to-gas
switching lasts for a prolonged period during 2012 due to
significantly depressed natural gas prices, there may be more
substantial unfavorable impacts to all coal supply regions. We
expect to continually review, and adjust if necessary, our
production levels in response to changes in market demand.
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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 48% from 2010 through 2015
and by 108% from 2010 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 12%
increase in FGD installed on the coal-fired generation fleet
from 199 gigawatts in 2010 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 new MATS for power
plants. Currently, the EIA estimates that approximately 63% of
all U.S. coal-fired generation capacity has FGD technology
installed or under construction. 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 115 million tons in 2011 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 2011 and is projected
to rise from 921 million tons in 2011 to 1.1 billion
tons by 2017. 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.
|
69
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 2011,
coal-fired power plants produced approximately 42% 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 929 million tons or 93% of total coal
consumption in 2011.
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.
Over the long term, the EIA forecasts in its 2012 reference case
that total coal consumption will grow by approximately 10% from
2010 through 2035, primarily due to increases in coal-fired
electric power generation.
Illinois
Basin Coal Market
Our lessee markets and delivers coal from our reserves to
electricity generating customers both in close proximity to its
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 lessees market area was generated by coal-fired power
plants. The table below compares the total electricity
generation in our lessees 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.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
70
More importantly, the progressive tightening by the EPA of
SO2,
NOx and other 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 also recently finalized
additional rules to further reduce the release of certain
combustion by-product emissions from fossil fuel power plants;
including the MATS rate published in February 2012, which
regulates the emission of mercury and other toxic air pollutants.
To comply with the 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. 199 gigawatts of the current 316
gigawatts of U.S. coal-fired generation is presently
equipped with FGD emissions systems. We believe that with the
implementation of the CSAPR and the MATS rule, 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. Currently the EIA estimates that
approximately 63% of all U.S. coal-fired generation capacity has
FGD technology installed or under construction.
Today, the number of scrubbers being installed at coal-fired
power plants across the United States is growing, and the
operating and economic profile 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
|
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
|
Actual
|
|
Forecast
|
|
Forecast
|
|
Forecast
|
|
Forecast
|
|
|
(In millions)
|
|
MW Scrubbed (U.S. Total)
|
|
|
37,448
|
|
|
|
10,629
|
|
|
|
9,940
|
|
|
|
11,967
|
|
|
|
9,121
|
|
Coal Tons Affected (Million Tons)
|
|
|
120
|
|
|
|
34
|
|
|
|
32
|
|
|
|
38
|
|
|
|
29
|
|
Source: Wood Mackenzie Illinois Basin Market Outlook, September
2011
Wood Mackenzie forecasts that the U.S. domestic electricity
generation coal consumption will grow from a projected
942 million tons in 2012 to 985 million tons by 2015.
More importantly, the Wood Mackenzie forecast projects Illinois
Basin coal production growth from 130 million tons in 2012
to 167 million tons by 2015 (28% growth) and then to over
200 million tons by 2020.
71
Long-Term
U.S. Thermal Coal Outlook Fall 2011: Summary Table
of Key Data
(tons in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
2020
|
|
|
2025
|
|
|
2030
|
|
|
|
|
|
Supply (Mst)
|
|
|
1,109
|
|
|
|
1,113
|
|
|
|
1,108
|
|
|
|
1,145
|
|
|
|
1,139
|
|
|
|
1,179
|
|
|
|
1,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Powder River Basin
|
|
|
487
|
|
|
|
483
|
|
|
|
486
|
|
|
|
508
|
|
|
|
481
|
|
|
|
508
|
|
|
|
552
|
|
|
|
|
|
Central Appalachia
|
|
|
89
|
|
|
|
76
|
|
|
|
64
|
|
|
|
64
|
|
|
|
46
|
|
|
|
56
|
|
|
|
71
|
|
|
|
|
|
Illinois Basin
|
|
|
130
|
|
|
|
144
|
|
|
|
157
|
|
|
|
167
|
|
|
|
204
|
|
|
|
216
|
|
|
|
224
|
|
|
|
|
|
Northern Appalachia
|
|
|
121
|
|
|
|
129
|
|
|
|
134
|
|
|
|
136
|
|
|
|
132
|
|
|
|
125
|
|
|
|
124
|
|
|
|
|
|
Metallurgical (not including Thermal Cross Over)
|
|
|
84
|
|
|
|
82
|
|
|
|
69
|
|
|
|
70
|
|
|
|
81
|
|
|
|
87
|
|
|
|
93
|
|
|
|
|
|
Imports
|
|
|
8
|
|
|
|
5
|
|
|
|
3
|
|
|
|
3
|
|
|
|
5
|
|
|
|
5
|
|
|
|
5
|
|
|
|
|
|
Other (including Refuse or Petcoke)
|
|
|
190
|
|
|
|
195
|
|
|
|
196
|
|
|
|
197
|
|
|
|
|
|
|
|
181
|
|
|
|
171
|
|
|
|
|
|
Stockpile Increase (Decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Demand (Mst)
|
|
|
1,109
|
|
|
|
1,113
|
|
|
|
1,108
|
|
|
|
1,145
|
|
|
|
1,139
|
|
|
|
1,179
|
|
|
|
1,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity Generation
|
|
|
942
|
|
|
|
942
|
|
|
|
967
|
|
|
|
985
|
|
|
|
954
|
|
|
|
837
|
|
|
|
794
|
|
|
|
|
|
Industrial
|
|
|
52
|
|
|
|
51
|
|
|
|
52
|
|
|
|
52
|
|
|
|
53
|
|
|
|
54
|
|
|
|
54
|
|
|
|
|
|
Thermal Export
|
|
|
32
|
|
|
|
38
|
|
|
|
21
|
|
|
|
38
|
|
|
|
52
|
|
|
|
200
|
|
|
|
299
|
|
|
|
|
|
Metallurgical Demand (includes Thermal Cross Over)
|
|
|
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 117 million tons in 2012 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 0.6% over the same period.
Importantly, Illinois Basin coal production is projected to grow
more sharply over the
2012-2020
period (5.8% CAGR) than over the latter part of the
20-year
projection period.
Conversely, Wood Mackenzie estimates that Central Appalachian
thermal coal production has declined from 217 million tons
in 2000 to 115 million tons in 2011, while Northern
Appalachian coal production has had only minor fluctuations.
Global
Thermal Coal Markets
Global coal production accounted for 30% of global primary
energy consumption in 2010, according to BP.
2010
Global Primary Energy Consumption by Fuel
Source: BP Statistical Review of World Energy, June 2011
72
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 2017, with Asia
accounting for more than 812 million tons of import demand,
up from 627 million tons in 2011.
In the Atlantic thermal coal market, European Union and other
European coal imports are projected to rise from
223 million tons in 2011 to 240 million tons by 2017.
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, 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/
73
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
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.
74
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 total 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.
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
75
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. Armstrong Energy currently does not,
and does not 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
76
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.
77
BUSINESS
Overview
Royalty
Business
We are a royalty business. Royalty businesses principally own
and manage mineral reserves. As an owner of mineral reserves, we
typically are not responsible for operating mines, but instead
enter into leases with mine operators granting them the right to
mine and sell reserves from our property in exchange for a
royalty payment. A typical lease has a 5- to
10-year base
term, with the lessee having an option to extend the lease for
additional terms. Leases may include the right to renegotiate
rents and royalties for the extended term. At this time we have
a single lessee, Armstrong Energy, and each of the leases with
it has an initial term of 10 years.
Royalty payments are typically calculated as a percentage of the
gross sales price of the aggregate tons of coal sold by a
lessee. Our royalty revenues are affected by changes in
long-term and spot commodity prices, production volumes, our
lessees supply contracts and the royalty rates in our
lease. The prevailing price for coal depends on a number of
factors, including the supply-demand relationship, the price and
availability of alternative fuels, global economic conditions,
and governmental regulations.
We do not operate any mines, and thus we do not bear ordinary
operating costs and have limited direct exposure to
environmental, permitting, and labor risks because we do not
have any operations that could cause environmental damage, do
not have any permits which are subject to revocation and do not
have any employees or labor force. Instead, our lessee, as
operator, is subject to environmental laws, permitting
requirements, and other regulations adopted by various
governmental authorities. In addition, our lessee generally
bears all labor-related risks, including retiree health care
legacy costs, black lung benefits, and workers
compensation costs associated with operating the mines. However,
our royalty revenues may be negatively affected by any decreases
in our lessees production volumes and revenues due to
these risks. We typically pay property taxes and then are
reimbursed by our lessee for the taxes on its leased property,
pursuant to the terms of the lease.
Our lessees 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 the
coal mined from our reserves. Adverse weather conditions, such
as floods or blizzards, can impact our lessees ability to
mine and ship our coal and its customers ability to take
delivery of coal.
Coal
Leases
We earn our coal royalty revenues under long-term leases that
require our lessee to make royalty payments to us based on a
percentage of the gross sales price of the aggregate tons of
coal it sells.
In addition to the terms described above, our leases impose
obligations on our lessee to diligently mine the leased coal
using modern mining techniques, indemnify us for any damages we
incur in connection with the lessees mining operations,
including any damages we may incur on account of our
lessees failure to fulfill reclamation or other
environmental obligations, conduct mining operations in
compliance with all applicable laws, obtain our written consent
prior to assigning the lease, and maintain commercially
reasonable amounts of general liability and other insurance. The
leases grant us the right to review all lessee mining plans and
maps, enter the leased premises to examine mine workings, and
conduct audits of lessees compliance with lease terms. In
the event of default by our lessee, our leases give us the right
to terminate the lease and take possession of the leased
premises.
About the
Partnership
We are a limited partnership formed in 2008 to engage in the
business of management and leasing of coal properties and
collection of coal production royalties in the Western Kentucky
region of the Illinois Basin. We currently wholly own
approximately 65 million tons of coal reserves and, as of
March 31, 2012, had a 50.81% undivided interest in
approximately 140 million tons of coal reserves owned by
Armstrong Energy, all located in Ohio and Muhlenberg Counties in
Western Kentucky. Our coal is generally low chlorine, high
sulfur coal.
78
Our outstanding limited partnership interests (common
units), representing 99.7% of our equity interests, are
owned by Yorktown. We are not engaged in the permitting,
production or sale of coal, nor in the operation or reclamation
of coal mining activity. We are a fee mineral and surface rights
owning entity. It is our intention to remain a coal leasing
enterprise and not to engage in coal production ourselves.
We currently lease all of our reserves to Armstrong Energy, our
sole lessee, in exchange for royalty payments in the amount of
7% of the revenue received from coal sold from those reserves.
Armstrong Energy is a diversified producer of low chlorine, high
sulfur thermal coal from the Illinois Basin with both surface
and underground mines. We are currently deferring those royalty
payments. Partially as a result of those deferrals, as of
December 31, 2011 we were owed approximately
$5.7 million from Armstrong Energy.
We intend to use the net proceeds from this offering to purchase
an additional estimated 8% to 10% partial undivided interest in
the reserves in which we had, as of March 31, 2012, a
50.81% interest as a joint tenant in common with Armstrong
Energy. See Prospectus Summary Business
Developments and Certain Relationships and Related
Party Transactions Membership Interest Purchase
Agreement. The actual percentage acquired will depend on
the fair value of the reserves at the time of the acquisition
and the net proceeds received in this offering. In addition, our
interest as a joint tenant in common with Armstrong Energy in
the majority of Armstrong Energys coal reserves could be
increased as a result of an additional acquisition through the
offset of unpaid deferred royalties owed to us.
We are a co-borrower under Armstrong Energys
$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 Armstrong Energys assets are pledged to secure
borrowings under the Senior Secured Credit Facility. Under the
terms of the Senior Secured Credit Facility, without the consent
of all lenders (if there are fewer than three lenders at the
time of any dividend or distribution) or the lenders having more
than 50% of the aggregate commitments (if there are three or
more lenders at the time of any dividend or distribution) under
that facility, we are currently prohibited from making dividend
payments or other distributions to our unitholders in excess of
$5.0 million per year and $10.0 million in aggregate,
except for dividends or other distributions in amounts necessary
to enable unitholders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership until
February 9, 2016, the date on which the Senior Secured
Credit Facility matures. We are not permitted to borrow
additional funds under the Senior Secured Credit Facility and as
such, it is not a source of liquidity for us.
We expect Armstrong Energy to continue to defer royalty payments
from Armstrong Energy and not pay distributions to any of our
unitholders, except for amounts necessary to enable unitholders
to pay anticipated income tax liabilities, which will be paid,
if at all, solely at the discretion of Elk Creek, GP, our
general partner, for the foreseeable future. As a result, we
will continue to accrue an increasing percentage undivided
interest in Armstrong Energys coal reserves for the
foreseeable future.
A wholly owned subsidiary of Armstrong Energy, Inc., Elk Creek
GP, is our general partner. Pursuant to our Partnership
Agreement, Elk Creek GP has the exclusive authority to conduct,
direct and manage all of our activities. By virtue of Armstrong
Energys control of Elk Creek, GP, our results are
consolidated in Armstrong Energys historical consolidated
financial statements. Pursuant to our Existing Partnership
Agreement, effective October 1, 2011, Yorktown unilaterally
may remove Elk Creek GP as our general partner in some
circumstances. As a result, Armstrong Energy will no longer
consolidate our results in its financial statements (the
Deconsolidation).
2011 was the first year production occurred under our
leases to Armstrong Energy. Based on its coal production in 2011
and the three months ended March 31, 2012, Armstrong Energy
is obligated to pay us $7.2 million and $2.1 million,
respectively, for production royalties under our leases for such
period. In addition, we earned a credit and collateral support
fee as a result of our financing activities in the amount of
$1.15 million and $0.3 million in the year ended
December 31, 2011 and three months ended March 31,
2012, respectively.
We are headquartered in St. Louis, Missouri.
79
Strategy
Our primary business strategy is to enhance unitholder value by
executing the following strategies:
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Continue to grow our joint interest in our coal reserve
holdings through additional investments in our existing proven
and probable reserves. 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. Pursuant to the terms of a Royalty Deferment and
Option Agreement with our sole lessee, Armstrong Energy, we have
the right to acquire additional undivided interests in coal
reserves controlled by Armstrong Energy in the event that
Armstrong defers cash payment to us for royalties due. We
expect that for the foreseeable future all or a substantial
portion of our royalty revenues will be used by us to acquire
additional coal reserve interests and will not be a source of
cash for the payment of dividends or other distributions to our
unitholders. Except for distributions in amounts necessary to
enable unitholders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership, which
will be paid, if at all, solely at the discretion of Elk Creek
GP, our general partner, we do not anticipate paying any
distributions for the foreseeable future.
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Expand and diversify our coal reserve
holdings. We will consider opportunities to
expand our reserves through acquisitions of additional coal
reserves in the Illinois Basin. We will consider acquisitions of
coal reserves that are high quality, long-lived and that are of
sufficient size to yield significant production or serve as a
platform for complementary acquisitions.
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Pursue additional royalty opportunities. We
intend to pursue opportunities to maximize qualifying income
from royalty based arrangements. We plan to pursue royalty
opportunities that are complementary to our existing asset base.
Additionally, we may also seek opportunities in new royalty or
qualifying income producing business lines to the extent that we
can utilize our existing infrastructure, relationships and
expertise.
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Competitive
Strengths
We believe that the following competitive strengths will enable
us to effectively execute our business strategy:
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Our lessee has a demonstrated track record for successfully
completing reserve acquisitions, securing required permits,
developing new mines and producing coal. Since
Armstrong Energys formation in 2006, it has successfully
acquired coal reserves and opened eight 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 its market
area. We believe this resulted from Armstrong Energys deep
management experience and disciplined approach to the
development of its operations and its focus on providing
competitively priced Illinois Basin coal. We believe this will
enable Armstrong Energy to continue to grow its 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, 2011, we either owned or had an interest in
approximately 205 million tons of clean recoverable (proven
and probable) coal reserves. Our reserves represent underground
mineable coal, which, in combination with our lessees coal
processing facilities, enhance our lessees ability to meet
its customers requirements for blends of coal with
different characteristics. Further, the comparatively low
chlorine content of our coal relative to other Illinois Basin
coal provides our lessee with an additional competitive
advantage in meeting the desired coal fuel profile of its
customers.
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Our reserves are strategically located to allow access to
multiple transportation options for delivery. Our
lessees mines are located adjacent to the Green River and
near its preparation, loading, and transportation facilities,
providing its customers with rail, barge, and truck
transportation options. In addition, our lessee has invested in
the potential construction of a coal export terminal along the
Mississippi Riverfront south of New Orleans. We believe this
will also enable Armstrong Energy to sell our coal in both the
domestic and export markets.
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80
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We are well-positioned to pursue additional reserve
acquisitions. Our management team has
successfully acquired and integrated properties. Since 2008, we
have acquired over 120 million tons of proven and probable
reserves.
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We have a highly experienced management team with a long
history of acquiring, building and operating coal
businesses. We do not have any officers or
directors. We are managed and operated by the board of directors
and executive officers of Armstrong Energy, Inc., the parent
corporation of our general partner, Elk Creek GP. The members of
Armstrong Energys senior management team have a
demonstrated track record of acquiring, building and operating
coal businesses profitably and safely. In addition, members of
Armstrong Energys senior management team have significant
experience managing the financial and organizational growth of
businesses, including public companies.
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The following chart depicts the organization and ownership of
Armstrong Resource Partners, L.P. prior to giving effect to the
offering of common units being made hereby or to the Concurrent
AE Offering, but assuming conversion of our Series A convertible
preferred units and conversion of Armstrong Energys
Series A preferred stock.
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(1) |
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Reserves owned solely by Armstrong Resource Partners. These
include the Kronos and Lewis Creek underground mines. |
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(2) |
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Reserves controlled jointly by Armstrong Resource Partners (with
a 50.81% undivided interest as of March 31, 2012) and
Armstrong Energy (with a 49.19% undivided interest as of
March 31, 2012). If this offering and the Concurrent AE
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 this 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 Energy. |
81
The following chart depicts the organization and ownership of
Armstrong Resource Partners, L.P. after giving effect to the
offering of common units being made hereby and the Concurrent AE
Offering.
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(1) |
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Reserves owned solely by Armstrong Resource Partners. These
include the Kronos and Lewis Creek underground mines. |
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(2) |
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Reserves controlled jointly by Armstrong Resource Partners and
Armstrong Energy. Assuming an offering price of
$ per unit, the midpoint of the
price range set forth on the front cover page of this
prospectus, and an estimated purchase price of $17.5 million for
our additional interest in the partially owned reserves, we
intend to acquire an additional estimated 8% to 10% partial
undivided interest in certain reserves of Armstrong Energy with
the net proceeds from this offering. The actual percentage
acquired will depend on the fair value of the reserves at the
time of the acquisition and the net proceeds received in this
offering. In addition, our interest as a joint tenant in common
with Armstrong Energy in the majority of Armstrong Energys
coal reserves could be increased as a result of an additional
acquisition through the offset of unpaid deferred royalties owed
to us. |
Our Coal
Reserves and Production
As of December 31, 2011, we had the rights to approximately
65 million tons and rights as joint-tenants-in common with
Armstrong Energy to 140 million tons of proven and probable
coal reserves located in Ohio and Muhlenberg Counties in Western
Kentucky. We lease all of our rights to mine these coal reserves
to our
82
sole lessee, Armstrong Energy. The following table summarizes
our coal reserves as of December 31, 2011. All of our
reserves are leased to Armstrong Energy.
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Gross Clean Recoverable Tons
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Net Clean Recoverable Tons
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Quality Specifications
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(Proven and Probable
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(Proven and Probable
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(As Received)(2)
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Reserves)(1)
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Reserves)(1)
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SO2
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Mining
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Proven
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Probable
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Proven
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Probable
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Heat Value
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Content
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Ash
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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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Reserves
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Reserves
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Total
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(Btu/Lb)
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(Lbs/MMBtu)
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(%)
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(In thousands)
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(In thousands)
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Owned Reserves
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Elk Creek(4)
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U
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56,430
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8,985
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65,415
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56,430
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8,985
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65,415
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11,792
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4.5
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7.6
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Partially Owned Reserves
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Reserves in Active Production(5)
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Midway
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S
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19,377
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1,427
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20,805
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7,644
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563
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8,207
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11,315
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4.8
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10.0
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Parkway
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U
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7,535
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5,434
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12,969
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2,973
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2,144
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5,116
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11,931
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4.4
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7.1
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East Fork(6)
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S
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2,287
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550
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2,837
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902
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217
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1,119
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11,136
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7.6
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11.2
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Equality Boot
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S
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21,841
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1,151
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22,992
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(7)
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8,616
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454
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9,070
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11,587
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5.7
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8.8
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Lewis Creek
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S
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6,160
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101
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6,261
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2,430
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40
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2,470
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11,420
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4.0
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9.5
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Maddox
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S
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512
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512
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202
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|
202
|
|
|
|
11,315
|
|
|
|
4.8
|
|
|
|
10.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Partially Owned Reserves in Active Production
|
|
|
|
|
|
|
57,712
|
|
|
|
8,663
|
|
|
|
66,376
|
|
|
|
22,767
|
|
|
|
3,418
|
|
|
|
26,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ken
|
|
|
S
|
|
|
|
17,166
|
|
|
|
3,854
|
|
|
|
21,020
|
|
|
|
6,772
|
|
|
|
1,520
|
|
|
|
8,292
|
|
|
|
11,809
|
|
|
|
5.0
|
|
|
|
7.5
|
|
Other
|
|
|
S/U
|
|
|
|
40,145
|
|
|
|
12,016
|
|
|
|
52,159
|
(8)
|
|
|
15,837
|
|
|
|
4,740
|
|
|
|
20,578
|
|
|
|
11,300
|
|
|
|
4.5
|
|
|
|
8.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Additional Reserves
|
|
|
|
|
|
|
57,311
|
|
|
|
15,870
|
|
|
|
73,179
|
|
|
|
22,609
|
|
|
|
6,261
|
|
|
|
28,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
171,453
|
|
|
|
33,518
|
|
|
|
204,970
|
|
|
|
101,807
|
|
|
|
18,663
|
|
|
|
120,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Determined as of December 31, 2011. Gross amounts reflect
the combined 100% joint ownership interest of Armstrong Resource
Partners and Armstrong Energy in reserves in active production.
Net amounts reflect our 39.45% undivided interest in such
jointly controlled reserves which were acquired on
February 9, 2011. Upon completion of this offering, we
intend to use the net proceeds to us to acquire from Armstrong
Energy an additional undivided interest in certain of Armstrong
Energys coal reserves. See Use of Proceeds.
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. |
|
(2) |
|
Quality specifications displayed on an as received
basis, assuming 11% moisture. If derived from multiple seams,
data represents an average. |
|
(3) |
|
U = Underground; S = Surface |
|
(4) |
|
We commenced production at the Kronos underground mine in
September 2011. |
|
(5) |
|
Reserves that are in active production as of December 31,
2011. |
|
(6) |
|
Warden and Kronos surface pits. Production at the Kronos pit
ceased in August 2011. |
|
(7) |
|
Includes approximately 0.3 million tons related to reserves for
which Armstrong Energy owns or leases from us only a partial
joint interest and royalties on extractions may be payable to
other owners. |
|
(8) |
|
Includes approximately 1.9 million tons related to reserves for
which Armstrong Energy owns or leases from us only a partial
joint interest and royalties on extractions may be payable to
other owners. |
83
The following table summarizes the ownership status of our
reserves by mine and our lessees historical production
from our coal reserves. Our acquisition of our ownership
interest in these reserves became effective February 9,
2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Clean
|
|
|
Net Clean
|
|
|
|
|
|
|
|
|
|
Recoverable Tons
|
|
|
Recoverable Tons
|
|
|
Gross Production(2)
|
|
|
Net Production(2)
|
|
|
|
(Proven and Probable
|
|
|
(Proven and Probable
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
Reserves)(1)
|
|
|
Reserves)(1)
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
Reserve
|
|
Owned
|
|
|
Leased
|
|
|
Total
|
|
|
Owned
|
|
|
Leased
|
|
|
Total
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
(In thousands)
|
|
|
(In thousands)
|
|
|
(Tons in thousands)
|
|
|
(Tons in thousands)
|
|
|
Owned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Elk Creek(3)
|
|
|
61,890
|
|
|
|
3,525
|
|
|
|
65,415
|
|
|
|
61,890
|
|
|
|
3,525
|
|
|
|
65,415
|
|
|
|
|
|
|
|
|
(4)
|
|
|
|
|
|
|
|
|
Partially Owned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midway
|
|
|
20,805
|
|
|
|
|
|
|
|
20,805
|
|
|
|
8,207
|
|
|
|
|
|
|
|
8,207
|
|
|
|
1,614.8
|
|
|
|
1,589.2
|
|
|
|
637.0
|
|
|
|
626.9
|
|
Parkway
|
|
|
2,326
|
|
|
|
10,643
|
|
|
|
12,969
|
|
|
|
918
|
|
|
|
4,199
|
|
|
|
5,116
|
|
|
|
1,485.9
|
|
|
|
1,491.9
|
|
|
|
586.2
|
|
|
|
588.6
|
|
East Fork(5)
|
|
|
2,193
|
|
|
|
645
|
|
|
|
2,837
|
|
|
|
865
|
|
|
|
254
|
|
|
|
1,119
|
|
|
|
1,641.1
|
|
|
|
745.9
|
|
|
|
647.4
|
|
|
|
294.3
|
|
Equality Boot
|
|
|
22,992
|
|
|
|
|
|
|
|
22,992
|
(6)
|
|
|
9,070
|
|
|
|
|
|
|
|
9,070
|
|
|
|
330.8
|
|
|
|
1,916.8
|
|
|
|
130.5
|
|
|
|
756.2
|
|
Lewis Creek
|
|
|
6,261
|
|
|
|
|
|
|
|
6,261
|
|
|
|
2,470
|
|
|
|
|
|
|
|
2,470
|
|
|
|
|
|
|
|
474.9
|
|
|
|
|
|
|
|
187.4
|
|
Maddox
|
|
|
512
|
|
|
|
|
|
|
|
512
|
|
|
|
202
|
|
|
|
|
|
|
|
202
|
|
|
|
|
|
|
|
24.9
|
|
|
|
|
|
|
|
9.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Active
|
|
|
55,089
|
|
|
|
11,288
|
|
|
|
66,376
|
|
|
|
21,732
|
|
|
|
4,453
|
|
|
|
26,185
|
|
|
|
5,072.6
|
|
|
|
6,243.6
|
|
|
|
2,001.1
|
|
|
|
2,463.1
|
|
Additional Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ken
|
|
|
21,020
|
|
|
|
|
|
|
|
21,020
|
|
|
|
8,292
|
|
|
|
|
|
|
|
8,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
35,427
|
|
|
|
16,732
|
|
|
|
52,159
|
(7)
|
|
|
13,977
|
|
|
|
6,601
|
|
|
|
20,578
|
|
|
|
572.1
|
(8)
|
|
|
398.8
|
(8)
|
|
|
225.7
|
|
|
|
157.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Additional
|
|
|
56,447
|
|
|
|
16,732
|
|
|
|
73,179
|
|
|
|
22,269
|
|
|
|
6,601
|
|
|
|
28,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
173,426
|
|
|
|
31,545
|
|
|
|
204,970
|
|
|
|
105,891
|
|
|
|
14,579
|
|
|
|
120,470
|
|
|
|
5,644.7
|
|
|
|
6,642.4
|
|
|
|
2,226.8
|
|
|
|
2,620.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
Proven and probable reserves refers to coal that can
be economically extracted or produced at the time of the reserve
determination. |
|
(2) |
|
Determined as of December 31, 2011. Gross amounts reflect
the combined 100% joint ownership interest of Armstrong Resource
Partners and Armstrong Energy in reserves in active production.
Net production amounts reflect our 39.45% undivided interest in
such jointly controlled reserves as if we had this ownership
since January 1, 2010. Our actual proportion of sales began
in February 2011 and amounted to approximately 2.5 million
tons for the year ended December 31, 2011. Upon completion
of this offering, we intend to use the net proceeds to acquire
from Armstrong Energy an additional undivided interest in
certain of Armstrong Energys coal reserves. See Use
of Proceeds. |
|
(3) |
|
Commenced production at the Kronos mine in September 2011. |
|
(4) |
|
The Kronos underground mine produced approximately
0.2 million tons of coal in 2011, but the production was
capitalized and not included in our results of operations
because the mine was still in the developmental phase. |
|
(5) |
|
Warden and Kronos surface pits. Production at the Kronos pit
ceased in August 2011. |
|
(6) |
|
Includes approximately 0.3 million tons related to reserves
for which Armstrong Energy owns or leases from us only a partial
joint interest and royalties on extractions may be payable to
other owners. |
|
(7) |
|
Includes approximately 1.9 million tons related to reserves
for which Armstrong Energy owns or leases from us only a partial
joint interest and royalties on extractions may be payable to
other owners. |
|
(8) |
|
Includes production from the Big Run mine, which ceased
operation in October 2011. |
On March 30, 2012, Armstrong Energy transferred an 11.36%
undivided interest in certain of its land and mineral reserves
to Armstrong Resource Partners in exchange for aggregate
consideration of $25.7 million. This increased Armstrong
Resource Partners interest in certain properties of
Armstrong Energy to 50.81%. See Business
Developments.
About
Armstrong Energy, Inc.
Armstrong Energy, Inc. was formed in 2006 to acquire and develop
a large coal mining operation. Armstrong Energy holds a 0.3%
equity interest in us through its wholly-owned subsidiary, Elk
Creek GP,
84
which is our general partner. As of March 31, 2012, of
Armstrong Energy, Inc.s total controlled reserves of
326 million tons, 65 million tons (20%) are wholly
owned by us, and 140 million tons (43%) are held by
Armstrong Energy and us as joint
tenants-in-common
with 49.19% and 50.81% interests, respectively, and the balance
of the reserves Armstrong Energy controls are leased by
Armstrong Energy from a third party, but are not included in
Armstrong Resource Partners option to purchase an
additional interest.
Armstrong Energy markets its coal primarily to electric utility
companies as fuel for their steam-powered generators. Based on
2011 production, Armstrong Energy is the sixth largest producer
in the Illinois Basin and the second largest in Western
Kentucky. It commenced production in the second quarter of 2008
and currently operates seven mines, including five surface and
two underground mines. In addition, Armstrong Energy is seeking
permits for three 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. Armstrong
Energy is also in the process of preparing permit applications
relating to Ken surface mine and the Lewis Creek underground
mine. Armstrong Energy intends to submit those permit
applications to the Corps and the State of Kentucky beginning in
the spring of 2012. Since beginning operations in 2007,
Armstrong Energys revenue has grown to $299.3 million
in 2011. During the year ended December 31, 2011, it
produced 6.6 million tons of coal, with seven mines in
operation, and currently expects a significant increase in its
production for 2012 compared to 2011. The majority of the
foregoing production is derived from coal reserves in which we
obtained an undivided interest during 2011 and that Armstrong
Energy now leases from us.
Business
Developments
In 2009 and 2010, Armstrong Energy borrowed an aggregate
principal amount of $44.1 million from us, 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 Armstrong Energys coal
reserves. Under the terms of these borrowings, we had the option
to acquire interests in coal reserves then held by Armstrong
Energy in Muhlenberg and Ohio Counties in satisfaction of the
loans we had made to Armstrong Energy. On February 9, 2011,
we exercised this option. In connection with that exercise, we
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 us, 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, we acquired a 39.45%
undivided interest as a joint tenant in common with Armstrong
Energy in the majority of its coal reserves, excluding its
reserves in Union and Webster Counties. The aggregate amount
paid by us to acquire our interest in these reserves was the
equivalent of approximately $69.5 million, which has been
included as a component of mineral rights, net and land in our
consolidated balance sheet as of March 31, 2012.
We are a co-borrower under Armstrong Energys
$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 Armstrong Energys assets are pledged to secure
borrowings under the Senior Secured Credit Facility. Under the
terms of the Senior Secured Credit Facility, without the consent
of all lenders (if there are fewer than three lenders at the
time of any dividend or distribution) or the lenders having more
than 50% of the aggregate commitments (if there are three or
more lenders at the time of any dividend or distribution) under
that facility, we are currently prohibited from making dividend
payments or other distributions to our unitholders in excess of
$5.0 million per year and $10.0 million in aggregate,
except for dividends or other distributions in amounts necessary
to enable unitholders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership until
February 9, 2016, the date on which the Senior Secured
Credit Facility matures. We are not permitted to borrow
additional funds under the Senior Secured Credit Facility and as
such, it is not a source of liquidity for us.
On February 9, 2011, Armstrong Energy entered into lease
agreements with us pursuant to which we granted Armstrong Energy
leases to our 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
85
notice. Armstrong Energy is obligated to pay us a production
royalty equal to 7% of the sales price of the coal which
Armstrong Energy mines from our properties. Under the terms of
these agreements, we retain 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 us when due and a
default by Armstrong Energy under any agreement, indenture or
other obligation to any creditor that, in our opinion, 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 we can
terminate one or more of the lease agreements. In addition,
Armstrong Energy has agreed to indemnify us 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.
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 by Armstrong Energy,
which represents the fair value of the assets transferred. As
noted above, the Deconsolidation was effective October 1,
2011. Subsequently, the long-term obligation will be reflected
on Armstrong Energys 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.
Effective February 9, 2011, Armstrong Energy entered into
an agreement with us pursuant to which we granted Armstrong
Energy the option to defer payment of the 7% production royalty
described above. In consideration for the granting of the option
to defer these payments, Armstrong Energy granted us 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 Armstrong Energy would satisfy payment of any deferred
fees by selling to us part of its interest in the aforementioned
coal reserves to us at fair market value for such reserves
determined a the time of the exercise of such option.
On February 9, 2011, we also entered into a lease and
sublease agreement with Armstrong Energy relating to the 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
previously paid $12 million of advance royalties to us
which are recoupable against future production royalties,
subject to certain limitations.
Based upon Armstrong Energys current estimates of
production for 2012 and 2013, we anticipate that Armstrong
Energy will owe us royalties under the above-mentioned license
and lease arrangements of approximately $14.8 million and
$20.0 million in 2012 and 2013, respectively, of which
collectively, $11.4 million will be recoupable against the
advance royalty payment referred to above.
In December 2011, we 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 Energy pursuant to which Armstrong Energy agreed to
sell to us, indirectly through contribution of a partial
undivided interest in reserves to a limited liability company
and transfer of its membership interests in such limited
liability company, an additional partial undivided interest in
reserves controlled by Armstrong Energy. In exchange for
Armstrong Energys agreement to sell a partial undivided
interest in those reserves, we paid Armstrong Energy
$20.0 million. In addition to the cash paid, certain
amounts due to us totaling $5.7 million were forgiven by
Armstrong Energy, which resulted in aggregate consideration of
$25.7 million. This transaction, which closed in March
2012, resulted in the transfer by Armstrong Energy of an 11.36%
undivided interest in certain of its land and mineral reserves
to Armstrong Resource Partners. We agreed to lease the newly
transferred mineral reserves to Armstrong Energy on the same
terms as the February 2011 lease.
Our
Lessees Mining Operations
Armstrong Energy currently operates seven active mines, all of
which relate to our coal reserves and are located in the
Illinois Basin coal region in western Kentucky. Its operations
are composed of five surface
86
mines and two underground mines, with three preparation plants
serving these operations. In addition, Armstrong Energy is
seeking permits for three 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.
Armstrong Energy is also in the process of preparing permit
applications relating to Ken surface mine and the Lewis Creek
underground mine. Armstrong Energy intends to submit those
permit applications to the Corps and the State of Kentucky
beginning in the spring of 2012. In 2011, approximately 72% of
the coal that Armstrong Energy produced came from its surface
mining operations.
Armstrong Energys current operating mines are all located
in Muhlenberg and Ohio Counties, Kentucky. The Western Kentucky
Parkway crosses its properties from Southwest to Northeast, and
the Green River separates its properties in Ohio and Muhlenberg
Counties. Armstrong Energys barge loading facility on the
Green River is located near the town of Kirtley, Kentucky. In
addition, it has a network of off-highway truck haul roads,
which connect the majority of its active mines and provide
access to its barge loading and rail loadout facilities.
The following map shows the locations of Armstrong Energys
mining operations and coal reserves:
In general, Armstrong Energy has developed its mines and
preparation plants at strategic locations in close proximity to
rail or barge shipping facilities. Coal is transported from its
mines to customers by means of railroads, trucks, and barge
lines. Armstrong Energy currently owns or leases under long-term
arrangements a substantial portion of the equipment utilized in
its mining operations. Armstrong Energy employs sophisticated
preventative maintenance and rebuild programs and upgrades its
equipment to ensure that it is productive, well-maintained and
cost-competitive. Its maintenance programs also employ
procedures designed to enhance the efficiencies of its
operations.
We currently wholly own approximately 65 million tons of
coal reserves and had, as of March 31, 2012, a 50.81%
undivided interest in approximately 140 million tons of
coal reserves, all located in Ohio and Muhlenberg Counties in
Western Kentucky.
Armstrong Energy has entered into leases with Western Mineral,
our wholly owned subsidiary, and Western Land Company, LLC
(Western Land) and Western Diamond, LLC
(Western Diamond), each of which is a wholly-owned
subsidiary of Armstrong Energy, 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
87
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 Energy to the lessors.
Effective February 9, 2011, Armstrong Energy, 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 Energy
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 Energy 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 in Muhlenberg and Ohio
Counties by engaging in a financing arrangement, under which
Armstrong Energy and its affiliates would satisfy payment of any
deferred fees by selling part of their interest in the
aforementioned coal reserves.
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 this 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 this offering,
shall occur on or before 90 days after Western Mineral
and/or its
parents or affiliates receives the net proceeds of this offering.
We also lease the Elk Creek Reserves to Armstrong Energy, and
the terms of that lease mirror the leases described above. The
Elk Creek Reserves lease also recognizes and permits Armstrong
Energy to recoup $12.0 million in previously paid advance
royalties against production royalties as they come due, subject
to certain limitations.
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 the Big Run mine 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 Big Run mine produced
approximately 0.4 million clean tons of coal in 2011, which
was processed at Armstrong Energys Midway Preparation
Plant.
Midway Mine. The Midway mine 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 averaged
approximately 11-to-1 in 2011. The Midway mine produced
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 the Midway mine has approximately 21 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. The Parkway mine 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. The Parkway mine consists of two working super
sections, and each section is currently equipped with two
continuous miners that operate concurrently. The Parkway mine
produced approximately 1.5 million tons of clean coal in
2011. As a result of a reserve acquisition in December 2011, the
Parkway mine currently has approximately 13.0 million tons of
proven and probable reserves. See Business
Developments. 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.
88
East Fork Mine. The East Fork mine 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. The East Fork mine produced approximately 0.7 million
tons of clean coal in 2011, and there were approximately
2.8 million tons of proven and probable reserves at the
East Fork mine at December 2011. Production at the Kronos
pit ceased in August 2011. 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. The Equality Boot mine 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
produced approximately 1.9 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 averaged
approximately 13.5-to-1 in 2011. The Equality Boot mine has
approximately 23 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.
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
the Lewis Creek mine, and thermal coal is being mined from the
West Kentucky
89
seams #13A and #13. The Lewis Creek mine produced
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
6 million tons of proven and probable reserves at the Lewis
Creek surface mine. Coal mined at the Lewis Creek mine 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
extracted thermal coal from the West Kentucky #9 seam.
While the Kronos mine produced approximately 0.2 million tons of
coal in 2011 that production was capitalized and not included in
our results of operations because the mine was still in the
developmental phase. The mine currently utilizes three
continuous miner super sections, but we expect to increase to
four super sections in mid-2012. At that time, we expect that
the mines annual production will be 2.3 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.
Maddox Mine. The Maddox mine is a surface mine
located two miles southeast of Centertown, Kentucky, in Ohio
County. The Maddox mine commenced production in November 2011
and extracts thermal coal from the West Kentucky #13a, #13
and #11 seams. The Maddox mine produced approximately
25,000 tons of clean coal in 2011 and is currently equipped
with a spread of surface mining equipment. Our reserve studies
have indicated that the Maddox mine has approximately
0.5 million tons of proven and probable reserves. Coal from
the Maddox mine is transported to the Midway Preparation Plant
for processing, where it is then shipped to customers via truck,
rail or barge.
Future Underground Mine. Armstrong Energy
anticipates opening the Lewis Creek underground mine in 2013,
assuming that it receives all necessary permits for operation of
that mine. The Lewis Creek mine will produce coal from the West
Kentucky #9 seam utilizing two continuous miner super
sections operating concurrently. Once fully operational, the
Lewis Creek underground mine is projected to produce
approximately 1.3 million tons of clean coal per year.
There are approximately 22 million tons of proven and
probable reserves at the Lewis Creek reserves.
Future Surface Mines. Armstrong Energy
anticipates opening the Hickory Ridge and Ken 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 and Ken surface mines have approximately
23 million tons in the aggregate of proven and probable
reserves.
Coal
Preparation Facilities
The majority of coal from each of Armstrong Energys mining
operations is processed at a coal preparation plant located near
the mine or connected to the mine by an overland conveyor
system. Currently, Armstrong Energy has three preparation
plants, Midway, Parkway and Armstrong Dock. These coal
preparation plants allow Armstrong Energy to treat the coal it
extracts from our reserves to ensure a consistent quality and to
enhance its suitability for particular end-users. In 2011,
Armstrong Energys preparation plants processed
approximately 99% of the raw coal Armstrong Energy produced. In
addition, depending on coal quality and customer requirements,
Armstrong Energy may blend coal mined from different locations
in order to achieve a more suitable product. At the current
time, our lessees preparation plants do not process coal
from other companies, and Armstrong Energy does not have any
present intention to do so.
90
The following chart provides information regarding Armstrong
Energys preparation plants:
|
|
|
|
|
|
|
|
|
Midway
|
|
Parkway
|
|
Armstrong Dock
|
|
Location:
|
|
Centertown, Kentucky
|
|
Central City, Kentucky
|
|
Centertown, Kentucky
|
Inception:
|
|
July 2008
|
|
April 2009
|
|
March 2010
|
Mines Serviced:
|
|
Midway, Maddox, Lewis Creek
|
|
Parkway
|
|
East Fork, Equality Boot, Kronos
|
Tons Per Hour:
|
|
600 Expandable to 1,200
|
|
400
|
|
1,200
|
Loadout Tons Per Hour:
|
|
2,500 (Rail)
|
|
|
|
2,500 (Barge)
|
Transportation:
|
|
Rail, Truck
|
|
Truck
|
|
Barge
|
The 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 currently being expanded to 1,200 TPH. We
expect the expansion to be completed by summer 2012.
The Parkway Preparation Plant is located adjacent to the Parkway
mine and has a
run-of-mine
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 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 Armstrong Energy employs at its 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, Armstrong Energy crushes raw coal and
classifies it into various sizes. For the largest size
fractions, Armstrong Energy uses dense media vessel separation
techniques in which it floats coal in a tank containing a liquid
of a pre-determined specific gravity. Since coal is lighter than
its impurities, it floats, and can be separated from rock and
shale. Armstrong Energy treats 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, Armstrong Energy processes most coal sizes
through centrifuges. A centrifuge spins coal very quickly,
causing water accompanying the coal to separate. Coarse refuse
from Armstrong Energys preparation plants is back-hauled
and disposed of in its mining pits or other locations in
accordance with applicable regulations and permits.
Our Coal
Leases and Royalty Revenues
We earn our coal royalty revenues under multi-year leases that
generally require our lessee to make payments to us currently
based on 7% of the gross sales price of the aggregate tons of
coal sold. Currently, we lease all of our coal reserves to
Armstrong Energy. Each of our leases with Armstrong Energy is
identical, save for the specific property being leased, except
for the Elk Creek lease. For a description of the terms of our
leases, see Business Overview
Royalty Business and Coal Leases.
In Muhlenberg County, we have four leases with Armstrong Energy,
each dated February 9, 2011, which concern the following
general reserve areas: (a) Jacobs Creek, Sunnyside
(part), Hillside, Cypress Creek and
91
Nelson Creek (part); (b) Nelson Creek (part) and Sunnyside
(part); (c) Parkway (part); and (d) Vogue (part), Game
Preserve and Paradise #9.
In Ohio County, we have eleven leases with Armstrong Energy,
each dated February 9, 2011, which concern the following
general reserve areas: (a) Rockport (part);
(b) Fish & Wildlife; (c) McHenry Spur and
Church Properties; (d) Terteling/Highview;
(e) Rockport (part) and Lewis Creek (part); (f) West
Ford, Midway (part), Bens Lick, Central Grove, McHenry,
Rockport (part) and Ken Wye; (g) Warden (part);
(h) Armstrong Dock; (i) Big Run, East Fork/Kronos,
Lewis Creek, and Midway (part); (j) Centertown;
(k) Elk Creek; and (m) Equality Boot.
2011 was the first year we recognized revenue under our
leases to Armstrong Energy. The following table sets forth
actual coal royalty revenues we have received with respect to
each of our reserves. Revenues in the table set forth below
reflect revenues actually recognized during the year ended
December 31, 2011 and three months ended March 31,
2012.
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|
|
|
|
|
|
|
|
|
Royalty Revenue
|
|
|
Year Ended
|
|
Three Months Ended
|
Reserves
|
|
December 31, 2011
|
|
March 31, 2012
|
|
|
(In thousands)
|
|
Elk Creek Reserves
|
|
$
|
622
|
|
|
$
|
958
|
|
Armstrong Energy Reserves(1)
|
|
|
7,167
|
|
|
|
2,123
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,789
|
|
|
$
|
3,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents royalty revenue earned on Armstrong Resource Partners
39.45% undivided interest in certain reserves owned by Armstrong
Energy. |
Our
Lessee
Our lessee, Armstrong Energy, is a diversified producer of low
chlorine, high sulfur thermal coal from the Illinois Basin with
both surface and underground mines. Armstrong Energy markets its
coal primarily to electric utility companies as fuel for their
steam-powered generators. Based on 2011 production, Armstrong
Energy is the sixth largest producer in the Illinois Basin and
the second largest in Western Kentucky. Armstrong Energy was
formed in 2006 to acquire and develop a large coal reserve
holding. Armstrong Energy commenced production in the second
quarter of 2008 and currently operates seven mines, including
five surface and two underground, and is seeking permits for
three additional mines. Armstrong Energy controls approximately
326 million tons of proven and probable coal reserves,
which includes approximately 121 million tons of coal
reserves that it leases from an unaffiliated third party. Its
reserves and operations are located in the Western Kentucky
counties of Ohio, Muhlenberg, Union and Webster. Armstrong
Energy also owns and operates three coal processing plants which
support its mining operations. The location of our coal reserves
and Armstrong Energys operations, adjacent to the Green
and Ohio Rivers, together with Armstrong Energys river
dock coal handling and rail loadout facilities, allow it to
optimize coal blending and handling, and provide its customers
with rail, barge, and truck transportation options. From
Armstrong Energys reserves, it mines coal from multiple
seams, which, in combination with its coal processing
facilities, enhances its ability to meet customer requirements
for blends of coal with different characteristics.
For the year ended December 31, 2011, Armstrong Energy
produced 6.6 million tons of coal, with seven mines in
operation, and currently expects a significant increase in its
production for 2012 compared to 2011. For the three months ended
March 31, 2012, Armstrong Energy produced 2.2 million
tons of coal, with seven mines in operation. Armstrong Energy is
contractually committed to sell 8.3 million tons of coal in
2012 and 7.1 million tons of coal in 2013, which represents
95% and 71% of its expected total coal sales in 2012 and 2013,
respectively.
Our
Lessees Multi-Year Coal Supply Agreements
As is customary in the coal industry, Armstrong Energy enters
into multi-year coal supply agreements with many of its
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 and our
lessee with greater predictability of sales volume and
92
sales prices. In 2011, Armstrong Energy sold approximately 89%
of its coal under multi-year coal supply agreements. The
majority of its 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 Armstrong
Energys multi-year coal supply agreements may include a
variable pricing system. While most of its 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 March 31, 2012, Armstrong Energy had 10
multi-year coal supply agreements with terms ranging from one to
seven years.
Armstrong Energy typically enters 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. Its
multi-year coal supply agreements typically contain provisions
to adjust the base price due to new laws and regulations that
affect its costs. Additionally, some of Armstrong Energys
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 Armstrong Energys
agreements is subject to fluctuation. For example, some of its
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
re-opener provisions that may allow a party to renegotiate
pricing at a set time. Price re-opener provisions may
automatically set a new price based on then-current market
prices or require our lessee 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 lessees 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 Armstrong Energys agreements fix
annual pricing and volume obligations, though, in certain
instances, the volume obligations may change depending on the
customers needs. Most of its coal supply agreements
contain provisions requiring Armstrong Energy 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.
Armstrong Energys coal supply agreements also typically
contain force majeure provisions allowing temporary suspension
of performance by it or its 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
our lessee or unanticipated plant outages that may affect the
buyer. Armstrong Energys 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.
93
Customers
of Our Lessee
The following map identifies current or planned scrubbed power
plants to which Armstrong Energy presently sells coal or to
which Illinois Basin coal could be sold in the future.
Armstrong Energys primary customers are electric
utilities. It may also sell coal to industrial companies,
brokers and other coal producers. For the year ended
December 31, 2011 and three months ended March 31,
2012, substantially all of Armstrong Energys coal revenues
related to sales to electric utilities. The majority
94
of Armstrong Energys electric utility customers purchase
coal for terms of one to five years, but our lessee also
supplies coal on a spot basis for some of its customers.
In 2011, Armstrong Energy sold coal to 14 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, 2011, Armstrong Energy derived approximately
63% of its total coal revenues from sales to its two largest
customers LGE and TVA. For the fiscal year ended
December 31, 2011, coal sales to LGE and TVA constituted
approximately 35% and 28% of Armstrong Energys total coal
revenues, respectively.
Our lessee currently has 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.
Our lessee also has 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 in 2011 and 2012 and 2.0 million tons
annually from 2013 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
and pursuant thereto TVA has exercised its right to reopen the
agreement. If the parties are unable to reach a mutually
acceptable agreement as to those terms being renegotiated by
July 1, 2012, 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 per ton 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
Armstrong Energy ships its coal to domestic customers by means
of railcars, barges or trucks, or a combination of these means
of transportation. It generally sells coal free on board at the
mine or nearest loading facility. 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 47% of Armstrong Energys
coal shipped in 2011 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 year ended December 31, 2011, 28% and
25% of Armstrong Energys coal sales tonnage also was
shipped by 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 Armstrong Energy competes with many of these
producers. Armstrong Energys 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 Armstrong Energy does. Based on MSHA
data, Armstrong Energy was the sixth largest producer of
Illinois Basin coal in fiscal 2011, producing approximately 6%
of the total Illinois Basin coal. As the price of domestic coal
increases, our lessee also competes with companies that produce
coal from one or more foreign countries, such as Colombia,
Indonesia and Venezuela.
The most important factors on which Armstrong Energy competes
are price, quality and characteristics, transportation costs and
reliability of supply. The demand for Armstrong Energys
coal and the prices that Armstrong Energy will be able to obtain
for its 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.
Employees
We do not have any employees. Pursuant to the Administrative
Services Agreement among the Partnership, Elk Creek GP and
Armstrong Energy, Armstrong Energy provides us with general
administrative and management services. This includes the use of
Armstrong Energys employees in exchange for a monthly fee.
See Certain Relationships and Related Party
Transactions Administrative Services Agreement.
Seasonality
Our lessees 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 the
coal mined from our reserves. Adverse weather conditions, such
as floods or blizzards, can impact our lessees ability to
mine and ship our coal and its customers ability to take
delivery of coal.
Legal
Proceedings
From time to time, we may be involved in litigation and claims
arising out of our business 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 lessees 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 lessees mining operations, cost structure, or
the demand for coal. 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 for our lessee, including revocation or
suspension of mining permits. None of the violations our lessee
has experienced to date has had a material impact on our
operations or financial condition.
Mining
Permits and Approvals
Numerous governmental permits and approvals are required for our
lessees coal mining operations. Applicants, including our
lessee, 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.
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 our
lessee does not engage in mountaintop mining, it is required to
obtain permits from the Corps, and its mining operations under
our leases 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. Our lessee
may experience difficulty or delays in obtaining mining permits
or other necessary approvals in the future, or even face denials
of permits altogether.
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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
lessees 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
lessees 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 our lessee 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
for our lessee to be, and our lessee is not, permit-blocked.
In 1983, the OSM adopted the stream buffer zone rule
(the 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 the 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 may adversely affect our
lessees 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 2011, our lessee
recorded approximately $1.8 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 has 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 lessees current bonds, it is 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 lessees
reclamation obligations. Many of these bonds are renewable on a
yearly basis. We cannot predict our lessees ability to
obtain bonds, or other approved forms of performance security,
or the cost of such security, in the future. As of
March 31, 2012, our lessee had approximately
$18.3 million in surety bonds outstanding to secure the
performance of our lessees 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 requires 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
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directors who knowingly or willfully violate a mandatory health
and safety standard or order. In addition, 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 our lessee operates, 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 lessees 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 U.S. 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 U.S. Congress.
Our lessees compliance with current or future mine health
and safety regulations could increase its 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 its
operating costs, but they will increase these costs and those of
our lessees competitors. Some, but not all, of these
additional costs may be passed on to customers and negatively
impact our royalty revenues.
Our lessee is required to compensate employees for work-related
injuries under various state workers compensation laws.
Our lessees costs will vary based on the number of
accidents that occur at its mines and other facilities, and its
costs of addressing these claims. Our lessee provides benefits
to its employees by being insured through state-sponsored
programs or an insurance carrier where there is no
state-sponsored program.
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
lessees 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 lessees 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.
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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 lessees mining operations
could become subject to further regulation pursuant to existing
laws such as the Clean Air Act. In that event, our lessee might
be required to install additional emissions control equipment or
take other steps to lower emissions associated with its
operations, thereby adversely affecting its operations and
potentially decreasing our royalty revenues.
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 the coal mined from our reserves. In addition to
developments directed at limiting greenhouse gas emissions,
which are discussed separately further below, air emission
control programs that affect our lessees 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
SO2emissions
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 of 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, and 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 lessees
customers current or anticipated future costs of using
coal. In addition, NAAQSs for particulate matter may affect
aspects of our lessees 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
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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 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 February 2012, the EPA published
its final 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 MATS.
Apart from MATS, 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; in May the effective date of these rules for major
sources was delayed for reconsideration of certain aspects of
the rule and in December 2011, the EPA published a
reconsideration proposal for public comment.
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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,
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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 one of the greenhouse gases, the man-made
emissions 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 lessees 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.
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 (the
UNFCCC), 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 was scheduled to expire in
2012, but was extended for five years at the UNFCCC Conference
of Parties in Durban, South Africa in December 2011. 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
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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; in March 2012, the EPA proposed to
continue using the current threshold rather than expand the
permitting requirements at this point. 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.
On March 27, 2012, the EPA proposed new emission standards
seeking to limit the amount of
CO2
emissions from new fossil fuel-fired electric utility generating
power plants. The proposed rule would require new plants greater
than 25 megawatts electric to meet an output based standard of
1000 pounds of
CO2
per megawatt hour, based on the performance of natural gas
combined cycle technology. New coal-fired power plants could
meet the standard either by employing carbon capture and storage
technology at start up or through later application of such
technologies provided that the aforementioned output standard
was met on average over a
30-year
period. Public comments concerning the proposed rule must be
received within 60 days after the date of publication of
such rule, and future public hearings will be scheduled to
discuss the proposal. If adopted, the proposed rules could
negatively impact the price of coal such that it would be less
attractive to utilities and ratepayers. Moreover, there is
currently no large-scale use of carbon capture and storage
technologies in domestic coal-fired power plants, and as a
result, there is a risk that such technology may not be
commercially practical for use in limiting emissions as
otherwise required by the proposed rule.
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
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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 lessees customers in the future, and might
also be asserted against our lessee; accordingly, such claims
could adversely affect us.
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 lessees 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 to 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 lessees 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 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
lessees costs and time spent on CWA compliance.
CWA requirements that may directly or indirectly affect our
lessees 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
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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
lessees NPDES discharge permits could become more
stringent, thereby potentially increasing 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 our lessee to incur
significant additional costs that could adversely affect our
royalty revenues.
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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 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. The Corps
has since reissued NWP 21 in February 2012, but has added a
number of conditions to provide more extensive stream protection
than before.
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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 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 lessees 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.
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 our lessee
follows to mitigate or remedy any such impacts. These procedures
have generally been effective and our lessee work closely with
applicable agencies to implement them. Our lessees
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 its operations and our coal royalty revenues.
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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 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
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 and therefore,
also our royalty revenues. The EPA had been expected to issue a
final decision by the end of 2011, but did not. It was sued in
federal court in April 2012 by environmental and health advocacy
groups to compel agency action.
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 own or lease. 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 our lessees mines are
located are protected under the ESA, and compliance with ESA
requirements could have the effect of prohibiting or delaying
our lessee from
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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, which could adversely affect Armstrong Energys
operations and our coal royalty revenues.
Other
Environmental Laws and Matters
We, our lessee, and its 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 coal
mining and other operations as well as the ability of our
lessees customers to use coal. Federal, state, and local
regulations also require regular monitoring of our lessees
mines and other facilities to ensure 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
Pursuant to the Administrative Services Agreement effective as
of January 1, 2011 among Armstrong Resource Partners, Elk
Creek GP and Armstrong Energy, Armstrong Energy provides
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 pays Armstrong Energy a monthly fee equal to $60,000
per month until December 31, 2011. See Certain
Relationships and Related Party Transactions
Administrative Services Agreement. We believe our
properties are sufficient for our current needs.
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MANAGEMENT
We do not, and will not, have any officers or directors. We will
be managed by the directors of our general partner, Elk Creek
GP, and the officers of Armstrong Energy, Inc., the owner of our
general partner. Unitholders will not directly or indirectly
participate in our management or operation. Our general partner
is not elected by our unitholders and will not be subject to
re-election on a regular basis in the future. Unitholders are
not entitled to elect our general partners directors or
indirectly participate in our management or operations. Our
general partner owes certain fiduciary duties to our
unitholders, but our Partnership Agreement contains various
provisions modifying and restricting such fiduciary duties. Our
general partner is liable, as a general partner, for all of our
debts (to the extent not paid from our assets), except for
indebtedness or other obligations that are made specifically
nonrecourse to it. Our general partner may cause us to incur
indebtedness or other obligations that are nonrecourse to it,
and we expect that it will do so.
We expect that our general partner will have seven directors,
four of whom will be independent as defined under the Nasdaq
independence standards. Three members of the board of directors
of Armstrong Energy serve on a conflicts committee that reviews
specific matters that the board believes may involve conflicts
of interest between us and Armstrong Energy. The conflicts
committee will determine whether the resolution of the conflict
of interest is fair and reasonable to us. The members of the
conflicts committee must meet the independence standards to
serve on an audit committee of a board of directors established
by Nasdaq and certain other requirements. Any matters approved
by the conflicts committee will be conclusively deemed to be
fair and reasonable to us, approved by all of our partners, and
not a breach by Armstrong Energy or our general partner of any
duties they may owe to us or our unitholders.
In addition, we expect that three members of our general
partners board of directors will serve on an audit
committee which will review our external financial reporting,
recommend engagement of our independent auditors, and review
procedures for the adequacy of our internal accounting controls.
The members of our general partners audit committee will
have been appointed prior to the date our common units first
trade on Nasdaq.
Nasdaq does not require a publicly traded limited partnership,
like us, to establish a compensation committee or a nominating
committee. Three members of the Armstrong Energy board of
directors serve on a nominating, corporate governance and risk
management committee, which recommends nominees to serve on our
general partners and Armstrong Energys boards of
directors, and monitors and evaluates corporate governance
issues and trends. Three members of the Armstrong Energy board
of directors also serve on a compensation committee, which
oversees compensation decisions for the officers of Armstrong
Energy and the directors of our general partner and of Armstrong
Energy, including the compensation plans described below.
Some officers of Armstrong Energy may spend a substantial amount
of time managing the business and affairs of Armstrong Energy
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 Energy.
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.
Board of
Directors
We will be managed by the board of directors of our general
partner. We expect that the general partners board of
directors will consist of the seven individuals who serve as
directors of Armstrong Energy. Of these seven directors, the
board has determined that Messrs. Beard, Crain, Ford and
Walker each meet the independence standards as established by
the rules and regulations of Nasdaq and the SEC, including the
heightened independence standards for audit committee members.
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Executive
Officers and Directors
As discussed above, we will be managed by the executive officers
of Armstrong Energy and our general partners board of
directors. Set forth below, as of May 1, 2012, is certain
information relating to the Armstrong Energy executive officers
and the directors of our general partner upon consummation of
this offering. 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. 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.
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Name
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Age
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Position
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J. Hord Armstrong, III
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71
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Chairman (Class II) of Elk Creek GP and Chief Executive Officer
of Armstrong Energy
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Martin D. Wilson
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50
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President of Armstrong Energy and Director (Class I) of Elk
Creek GP
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Kenneth E. Allen
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65
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Executive Vice President of Operations of Armstrong Energy
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David R. Cobb, P.E.
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64
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Executive Vice President of Business Development of Armstrong
Energy
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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 of Armstrong Energy
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Brian G. Landry
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56
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Vice President, Information Technology of Armstrong Energy
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Anson M. Beard, Jr.
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76
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Director (Class I) of Elk Creek GP
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James C. Crain
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63
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Director (Class III) of Elk Creek GP
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Richard F. Ford
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75
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Director (Class III) of Elk Creek GP
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Bryan H. Lawrence
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69
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Director (Class III) of Elk Creek GP
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Greg A. Walker
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56
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Director (Class II) of Elk Creek GP
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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 the Chairman and Chief Executive
Officer of Armstrong Energys predecessor entity (the
Predecessor), and as a member of the
Predecessors board of managers, from its formation in 2006
until the reorganization of Armstrong Energy (the
Reorganization) in October 2011. Since the
Reorganization, Mr. Armstrong has been the Chairman and
Chief Executive Officer of Armstrong Energy. Mr. Armstrong will
be appointed as chairman of our general partner prior to
consummation of this offering. 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 Armstrong Energy. The board believes his
prior experiences afford him unique insights into Armstrong
Energys strategies, challenges and opportunities.
Martin D. Wilson Mr. Wilson served as
the Predecessors President, and as a member of the
Predecessors board of managers, from its formation in 2006
until the Reorganization in October 2011. Since
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the Reorganization, Mr. Wilson has been the President of
Armstrong Energy. Mr. Wilson will be appointed as a member of
our general partners board of directors prior to
consummation of this offering. 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 Armstrong Energy.
Kenneth E. Allen Mr. Allen served as the
Predecessors Vice President of Operations from 2007 until
the Reorganization in October 2011. Since the Reorganization,
Mr. Allen has been Armstrong Energys 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 Armstrong Energy
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
the Predecessors Vice President of Business Development
from its inception in 2006 until the Reorganization in October
2011. Since the Reorganization, Mr. Cobb has been Armstrong
Energys 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 Armstrong Energy 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
the Predecessors Vice President and Controller from 2009
until the Reorganization in October 2011. Since the
Reorganization, Mr. Gist has been Armstrong Energys
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 the
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 Armstrong Energys board in October 2011, and
will be appointed as a member of our general partners
board of directors prior to consummation of this offering. He
joined Morgan Stanley & Co. as a Vice President to
found Private Client Services in 1977. He was
112
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.
James C. Crain Mr. Crain was appointed
to Armstrong Energys board of directors in October 2011,
and will be appointed as a member of our general partners
board of directors prior to consummation of this offering.
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 Armstrong Energys board in October 2011, and will be
appointed as a member of our general partners board of
directors prior to consummation of this offering. 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 the Predecessors board of managers from its
formation in 2006 until the Reorganization. He was appointed to
Armstrong Energys board of directors in October 2011, and
will be appointed as a member of our general partners
board of directors prior to consummation of this offering. 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 Armstrong Energys board of directors because of
his significant knowledge of all aspects of the energy industry.
Greg A. Walker Mr. Walker was appointed
to Armstrong Energys board of directors in October 2011,
and will be appointed as a member of our general partners
board of directors prior to consummation of this offering. 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
113
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.
Board of
Directors and Board Committees
We anticipate that our general partners board will consist
of seven directors and that it will establish an audit
committee. In addition, the following committees of Armstrong
Energys board will manage us, as well as Armstrong Energy:
a compensation committee, a nominating, corporate governance and
risk management 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 the board.
The majority of our general partners board members will be
independent at the time of listing with Nasdaq. We expect that
the board will determine 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 will satisfy the additional conditions for
independence for audit committee members required by Nasdaq.
Audit
Committee
Messrs. Crain, Ford and Walker, each an independent
director, will serve on our general partners audit
committee. Mr. Ford will be the chair of the audit
committee. The committee will assist the 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 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
We do not have, and our general partner does not have, a
compensation committee. Messrs. Beard, Ford and Walker,
each an independent director, serve on Armstrong Energys
compensation committee. Mr. Beard is the chair of the
compensation committee. The committee is responsible for
discharging Armstrong Energys responsibility relating to
compensation of Armstrong Energys executive officers and
directors, evaluating the performance of its executive officers
in light of Armstrong Energys goals and objectives, and
recommending to the board for approval Armstrong Energys
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,
Corporate Governance and Risk Management Committee
We do not have, and our general partner does not have, a
nominating and governance committee. Messrs. Beard, Crain
and Ford, each an independent director, serve on Armstrong
Energys nominating, corporate governance and risk
management committee. Mr. Crain is the chair of this
committee. The committee is responsible for (i) assisting
Armstrong Energys board by indentifying individuals
qualified to become board members, and recommending to the board
nominees for election as director, (ii) leading the
114
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 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 Armstrong Energys 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 Armstrong
Energy is a party, (iii) advising the board on actions to
be taken by Armstrong Energy upon the boards request, and
(iv) carrying out any other duties delegated to the
conflicts committee by Armstrong Energys board of
directors.
Compensation
Committee Interlocks and Insider Participation
We do not, and our general partner does not, have a compensation
committee. Although Armstrong Energys board did not have a
compensation committee during the entire previous fiscal year,
none of the individuals who currently serve on Armstrong
Energys compensation committee has served Armstrong Energy
or any of its subsidiaries as an officer or employee. In
addition, none of Armstrong Energys 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 Armstrong Energys board or
compensation committee.
Code of
Ethics
Armstrong Energy has 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 Armstrong Energys web site at
www.armstrongcoal.com. Any amendments to, or waivers from,
provisions of the code related to certain matters will be
disclosed on that website.
Compensation
of Directors
Our general partners directors will not receive any
additional compensation for serving as directors of our general
partner. Historically, Armstrong Energys directors have
not received compensation for their service. In connection with
its current stock offering, Armstrong Energy adopted a new
director compensation program pursuant to which each of its
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. The nominating,
corporate governance and risk management committee reviews and
makes recommendations to the board regarding compensation of
directors, including equity-based plans. Armstrong Energy
reimburses its non-employee directors for reasonable travel
expenses incurred in attending board and committee meetings.
Armstrong Energy also intends to allow its non-employee
directors to participate in the 2011 Long-Term Incentive Plan
(the LTIP) and any other equity compensation plans
that Armstrong Energy adopts in the future.
Executive
Officer Compensation
Compensation
Discussion and Analysis
This Compensation Discussion and Analysis describes and explains
Armstrong Energys compensation program for the fiscal year
ended December 31, 2011 for its 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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115
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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 Armstrong Energy expects the
compensation of the named executive officers to change following
its current stock offering.
Historical
Compensation Decisions
Armstrong Energys compensation approach has been tied to
its stage of development as a company. Before its current
offering, Armstrong Energy was privately-held and therefore, not
subject to any stock exchange or SEC rules relating to
compensation, board committees and independent board
representation. Armstrong Energy 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
Armstrong Energys financial position.
Although Armstrong Energy did not have a formal compensation
program in place, it believes that its informal program and
compensation methods furthered the following objectives:
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To retain talented individuals to contribute to Armstrong
Energys 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
Armstrong Energy recently formed a compensation committee
composed 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 Armstrong
Energys new compensation philosophy and objectives,
administrate Armstrong Energys executive and director
compensation programs and plans, and review and approve the
compensation of Armstrong Energys named executive
officers. The committee is currently in the process of
evaluating Armstrong Energys historical compensation
practices and customizing a new management compensation program
for Armstrong Energys specific circumstances.
As Armstrong Energy gains experience as a public company, it
expects that the specific director, emphasis and components of
its executive compensation program will continue to evolve.
Accordingly, the compensation paid to its named executive
officers in the past is not necessarily indicative of how it
will compensate them after its current stock 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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116
Elements
of Compensation
Historically, Armstrong Energys executive officers have
received annual salaries as their compensation for services. In
addition, Armstrong Energys board may grant discretionary
cash bonuses and equity to its executive officers. In connection
with Mr. Gists appointment as an executive officer,
effective January 1, 2010, Armstrong Energy granted
Mr. Gist 11,060 restricted 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, Armstrong Energy
granted to each of Messrs. Armstrong, Wilson, Allen and
Cobb 11,060 restricted shares of common stock of Armstrong
Energy, which vest on April 1, 2013. The aggregate grant
date fair value of each award was $257,600.
Also, on October 1, 2011, Armstrong Resource Partners
granted 171,106 and 152,094 restricted units of limited partner
interest to Mr. Armstrong and Mr. Wilson,
respectively. The aggregate grant date fair value of
Mr. Armstrongs award was $3,082,500, and the
aggregate grant date fair value of Mr. Wilsons award
was $2,740,000. Pursuant to the terms of each of the restricted
unit grants, each of Messrs. Armstrong and Wilson was
required to deliver to us that number of restricted units,
valued at the fair market value of such units at the time of
such delivery, to satisfy any federal, state or local taxes due
in connection with the respective grant. Effective
January 25, 2012, Mr. Armstrong entered into an
Assignment of Limited Partnership Units with us, pursuant to
which Mr. Armstrong transferred and assigned
71,522 units to us, in exchange for our agreement to pay
any federal, state or local taxes arising from the grant, the
total amount of which has been determined to be equal to
approximately $1.3 million. Also effective January 25,
2012, Mr. Wilson entered into an Assignment of Limited
Partnership Units with us, pursuant to which Mr. Wilson
transferred and assigned 63,575 units to us, in exchange
for our agreement to pay any federal, state or local taxes
arising from the grant, the total amount of which has been
determined to be equal to approximately $1.1 million.
Armstrong Energy believes that its key executives
compensation is reflective of their leadership roles in a
growing company in relation to its financial performance.
Armstrong Energy believes that its executive compensation is
competitive within its industry and adequate to retain and
incentivize its key executives.
Armstrong Energy recently adopted the LTIP. Going forward,
Armstrong Energy expects that its executive officers
compensation will consist of base salary, annual cash incentive
compensation, and long-term incentive compensation. Armstrong
Energys executive officers are eligible to receive annual
performance-based
and discretionary cash bonuses. Long-term incentive compensation
further aligns the interests of its executive officers with
those of its stockholders over the long-term, encourages the
retention of its 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 Armstrong Energys strategic and long-term
performance objectives and growth. The LTIP is more fully
described below under 2011 Long-Term Incentive
Plan.
Other
Executive Benefits
Armstrong Energys 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, Armstrong Energy provides its 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, Armstrong Energy provides
Mr. Wilson with an allowance for club membership dues.
117
Employment
Agreements
2007
Allen and Cobb Employment Agreements
Effective June 1, 2007, Armstrong Energy entered into an
employment agreement (the 2007 Allen Employment
Agreement) with Mr. Allen. Effective January 1,
2007, Armstrong Energy 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, Armstrong
Energy 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, the base salaries of
Messrs. Allen and Cobb were increased to $275,000 and
$238,000, respectively. Effective January 1, 2012, the base
salaries of Messrs. Allen and Cobb were increased to $300,000
and $260,000, 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 Armstrong Energys 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 Armstrong Energy or the respective
executive gives 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 Armstrong Energy 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 Armstrong
Energy.
In addition, pursuant to each of the 2007 Agreement and the
related overriding royalty agreement, as amended, between
Mr. Allen and Armstrong Energy, and the 2007 Cobb
Employment Agreement and the related overriding royalty
agreement, as amended, between Mr. Cobb and Armstrong
Energy, Messrs. Allen and Cobb each receive an overriding
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, Armstrong Energy entered into
an employment agreement (the 2009 Gist Agreement)
with Mr. Gist. Pursuant to the 2009 Gist Agreement,
Armstrong Energy 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 Armstrong Energys achievement of profitability targets
and Mr. Gists satisfactory achievement of goals and
objectives as determined by Armstrong Energys 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 11,060 restricted shares of Armstrong
Energy. Such units 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
Armstrong Energys shareholders. Awards will be made at the
discretion of the board of directors and Armstrong Energys
President.
118
The 2009 Gist Agreement provides that Armstrong Energy 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, Armstrong Energy 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, Armstrong Energy agreed to
pay Mr. Gist $210,000 for his services as its Senior Vice
President, Finance and Administration and Chief Financial
Officer. Effective January 1, 2012, Mr. Gists base
salary was increased to $235,000. 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 Armstrong Energy and to be
awarded at the discretion of Armstrong Energys President
or board of directors. As of May 1, 2012, Armstrong Energy
has not established any performance criteria pursuant to the
2011 Gist Agreement. However, Armstrong Energys board
granted Mr. Gist a discretionary cash bonus in the amount of
$105,000 for 2011 and may grant Mr. Gist a discretionary cash
bonus for 2012.
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
Armstrong Energys 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 Armstrong Energy 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 Armstrong Energy 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 Armstrong Energy.
Armstrong
and Wilson Employment Agreements
Effective October 1, 2011, Armstrong Energy entered into an
employment agreement with each of Messrs. Armstrong and
Wilson (together, the Armstrong and Wilson
Agreements).
Pursuant to each of the Armstrong and Wilson Agreements,
Armstrong Energy agreed to pay each of Messrs. Armstrong
and Wilson a base salary of $300,000. Effective January 1,
2012, the base salary of each of Messrs. Armstrong and Wilson
was increased to $350,000. In addition, each of
Messrs. Armstrong and Wilson is entitled to an annual bonus
based upon achievement of performance criteria established by
Armstrong Energy and to be awarded by its 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
May 1, 2012, Armstrong Energy has not established any
performance criteria pursuant to the Armstrong and Wilson
Agreements. However, Armstrong Energys board granted each
of Messrs. Armstrong and Wilson a discretionary cash bonus in
the amount of $225,000 for 2011 and may grant Mr. Armstrong
and/or Mr. Wilson a discretionary cash bonus for 2012.
The Armstrong and Wilson Agreements provide that
Messrs. Armstrong and Wilson shall be entitled to
participate in any of Armstrong Energys 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 Armstrong
Energy may terminate the agreement with or without cause, and
the executive may terminate the agreement with or without good
reason. See
119
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 Armstrong Energy. 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, Armstrong Energy entered into an
amended and restated overriding royalty agreement with David R.
Cobb, one of its executive officers, pursuant to which Armstrong
Energy 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 Armstrong Energys
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
Armstrong Energy, its respective assigns and successors, and any
subsequent owner of the subject properties.
On December 3, 2008, Armstrong Energy entered into an
amended and overriding royalty agreement with Kenneth E. Allen,
one of its executive officers, pursuant to which Armstrong
Energy agreed to pay Mr. Allen a royalty of five cents
($0.05) per ton of all coal thereafter mined or extracted and
subsequently sold from certain of Armstrong Energys
reserves. The term of the royalty began on February 9,
2007, and is set to continue until the later of:
(i) February 9, 2027, or (ii) such time as all of
the mineable and saleable coal from the subject properties has
been mined. The agreement also states that the overriding
royalty shall constitute an independent and enforceable
obligation that shall run with the land and shall be binding on
Armstrong Energy, its respective assigns and successors, and any
subsequent owner of the subject properties.
Tax
Considerations
In the past, Armstrong Energy has not taken into consideration
the tax consequences to employees and itself when considering
the types and levels of awards and other compensation granted to
executives and directors. However, Armstrong Energy anticipates
that the compensation committee will consider these tax
implications when determining executive compensation in the
future.
2011
Summary Compensation Table
The following table sets forth all compensation paid to
Armstrong Energys named executive officers for the years
ending December 31, 2011, 2010 and 2009.
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All Other
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Name and Principal Position
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Year
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Salary
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Bonus
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Stock Awards(1)
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Compensation
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Total
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J. Hord Armstrong, III,
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2011
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$
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300,000
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$
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225,000
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$
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3,340,100
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(2)
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$
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21,649
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(3)
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$
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3,886,749
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Chairman and Chief
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2010
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250,000
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187,500
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|
|
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16,606
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454,106
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Executive Officer
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2009
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124,000
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42,000
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6,180
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172,180
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Martin D. Wilson,
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2011
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$
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300,000
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$
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225,000
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$
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2,997,600
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(4)
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$
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13,049
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(5)
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$
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3,535,649
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President
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2010
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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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8,340
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|
|
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445,840
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2009
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206,000
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206,000
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Kenneth E. Allen(6),
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2011
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$
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275,000
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$
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157,500
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$
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257,600
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(7)
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$
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358,919
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(8)
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$
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1,049,019
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Executive Vice President
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2010
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260,000
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130,000
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602,481
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|
|
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992,481
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of Operations
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2009
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|
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247,000
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42,000
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|
|
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12,250
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301,250
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David R. Cobb, P.E.(9),
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2011
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$
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238,000
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$
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139,000
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$
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257,600
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(7)
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$
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356,136
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(10)
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$
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990,736
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Executive Vice President of
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2010
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226,000
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113,000
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299,097
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638,097
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Business Development
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2009
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210,000
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42,000
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|
|
|
|
|
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244,028
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|
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496,028
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J. Richard Gist(11),
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2011
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$
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210,000
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$
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105,000
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$
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|
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$
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1,961
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$
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316,961
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Senior Vice President,
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2010
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195,000
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88,000
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120,000
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649
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403,649
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Finance and Administration
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2009
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|
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48,250
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43,000
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|
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91,250
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and Chief Financial Officer
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120
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|
(1) |
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Amounts disclosed in this column relate to grants of Armstrong
Energy common stock and Armstrong Resource Partners common
units. The amounts reflect the grant date fair value computed in
accordance with FASB ASC Topic 718. |
|
(2) |
|
Represents the grant date fair value of 11,060 restricted shares
of Armstrong Energy common stock granted on June 1, 2011
($257,600), and the grant date fair value of 171,106 restricted
units of limited partner interest granted by Armstrong Resource
Partners on October 1, 2011 ($3,082,500). |
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(3) |
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Includes Armstrong Energys matching contributions paid to
Armstrong Energys 401(k) plan on behalf of
Mr. Armstrong ($12,250). |
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(4) |
|
Represents the grant date fair value of 11,060 restricted shares
of Armstrong Energy common stock granted on June 1, 2011
($257,600), and the grant date fair value of 152,094 restricted
units of limited partner interest granted by Armstrong Resource
Partners on October 1, 2011 ($2,740,000). |
|
(5) |
|
Includes Armstrong Energys matching contributions paid to
Armstrong Energys 401(k) plan on behalf of Mr. Wilson
($12,000). |
|
(6) |
|
Mr. Allen was appointed Executive Vice President of
Operations effective October 1, 2011. Prior to this time,
Mr. Allen was Armstrong Energys Vice President of
Operations. |
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(7) |
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Represents the grant date fair value of 11,060 restricted shares
of Armstrong Energy common stock granted on June 1, 2011. |
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(8) |
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Includes overriding royalties paid to Mr. Allen ($340,875)
(see Overriding Royalty Agreements for a
description of Mr. Allens agreement with Armstrong
Energy regarding the payment of overriding royalties) and
Armstrong Energys matching contributions paid to Armstrong
Energys 401(k) plan on behalf of Mr. Allen ($12,250). |
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(9) |
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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 Armstrong Energys Vice President of
Business Development. |
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(10) |
|
Includes overriding royalties paid to Mr. Cobb ($340,875)
(see Overriding Royalty Agreements for a
description of Mr. Cobbs agreement with Armstrong
Energy regarding the payment of overriding royalties) and
Armstrong Energys matching contributions paid to Armstrong
Energys 401(k) plan on behalf of Mr. Cobb ($12,250). |
|
(11) |
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Mr. Gist became Vice President and Controller on
October 7, 2009, and Senior Vice President, Finance and
Administration and Chief Financial Officer effective
October 1, 2011. |
Outstanding
Equity Awards at 2011 Fiscal Year-End
The following table sets forth information on outstanding option
and stock awards held by the named executive officers on
December 31, 2011.
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Number of Shares or
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Market Value of Shares
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|
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Units of Stock That
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or Units of Stock That
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Name
|
|
Have Not Vested (#)
|
|
|
Have Not Vested ($)(1)
|
|
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J. Hord Armstrong, III
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11,060
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(2)(3)
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$
|
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Martin D. Wilson
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11,060
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(2)(4)
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$
|
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Kenneth E. Allen
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|
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11,060
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(2)
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|
$
|
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David R. Cobb
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|
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11,060
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(2)
|
|
$
|
|
|
|
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|
(1) |
|
The market value for our common stock is based on the assumed
initial public offering price of our common stock of
$ per share, the midpoint of the
price range on the cover page of the prospectus for the
Concurrent AE Offering. |
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(2) |
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Shares vest on April 1, 2013. |
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(3) |
|
In addition, the Partnership granted Mr. Armstrong 171,106
restricted units of limited partner interest that vest on the
earlier of March 31, 2012 or the occurrence of a liquidity
event, which includes, among other things, the public offering
of units issued by the Partnership. The market value of such
units was $3,422,120. |
121
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|
(4) |
|
In addition, the Partnership granted Mr. Wilson 152,094
restricted units of limited partner interest that vest on the
earlier of March 31, 2012 or the occurrence of a liquidity
event, which includes, among other things, the public offering
of units issued by the Partnership. The market value of such
units was $3,041,860. |
Options
Exercised and Stock Vested
The following table sets forth the vesting of restricted stock
during 2011 for the named executive officers. There were no
option exercises by named executive officers during 2011.
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Number of
|
|
|
Value Realized
|
|
|
Shares Acquired
|
|
|
on Vesting
|
Name
|
|
on Vesting (#)
|
|
|
($)(1)
|
|
J. Richard Gist
|
|
|
11,060
|
|
|
$210,900
|
|
|
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(1) |
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The value realized on vesting is the fair value of the
underlying stock on the vesting date. |
Payments
upon Termination or a Change in Control
Each of the named executive officers of Armstrong Energy has
entered into an agreement with Armstrong Energy 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, the Armstrong Energy 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 Armstrong Energy 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 breached any
fiduciary duty to Armstrong Energy that, in either case, results
or was intended to result in personal profit to the executive at
the expense of Armstrong Energy 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.
Armstrong Energy 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
122
addition, Armstrong Energy 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 Armstrong Energys 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 Armstrong Energy, (ii) consummation of a
reorganization, merger, recapitalization, consolidation, or any
other transaction, in each case with respect to which persons
who were Armstrong Energys 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 Armstrong Energys assets in
a transaction approved by the board.
2009
Gist Employment Agreement
Pursuant to the 2009 Gist Agreement, if Armstrong Energy
terminates 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, Armstrong Energy 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 Armstrong Energy 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 Armstrong Energy that, in either case, results
or was intended to result in personal profit to Mr. Gist at
the expense of Armstrong Energy or any of its customers,
(iv) Mr. Gist has been convicted of or pleads guilty
or no 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.
Armstrong Energy 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,
Armstrong Energy will pay, promptly following such termination,
a lump sum payment equal to one times
123
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 Armstrong Energys 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 Armstrong Energy, (ii) consummation
of a reorganization, merger, recapitalization, consolidation, or
any other transaction, in each case with respect to which
persons who were Armstrong Energys 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 Armstrong Energys assets in
a transaction approved by the board.
Armstrong
and Wilson Employment Agreements
Pursuant to the Armstrong and Wilson Agreements, Armstrong
Energy may terminate Mr. Armstrongs and
Mr. Wilsons employment at any time without cause (as
defined below), and Mr. Armstrong or Mr. Wilson may
terminate his employment at any time for good reason (as defined
below). In the event of a termination without cause, failure by
Armstrong Energy to renew the agreement or termination by the
executive for good reason, (i) Armstrong Energy 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) Armstrong
Energy will provide the executive with outplacement services,
and (b) the executive shall be entitled to a contribution
under Armstrong Energys 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 Armstrong Energy 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 hereunder (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) Armstrong Energy delivers a written demand for
substantial performance to the executive that specifies the
manner in which Armstrong Energy believes 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 respective agreement that is
demonstrably and materially injurious to Armstrong Energy 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 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
Mr. Armstrong in good faith and with the reasonable belief
that the action or omission was in the best interest of
Armstrong Energy. If Armstrong Energys board of directors
determines in its sole discretion that a cure of the acts or
omissions described above is possible and appropriate, Armstrong
Energy 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 Armstrong Energys board of directors
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 Armstrong Energy or other substantial
change in the character or scope of Armstrong Energys
operations); (ii) the annual base salary is materially
reduced (except
124
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; (iv) any other
action or inaction that constitutes a material breach by
Armstrong Energy 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. Armstrong Energy 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) Armstrong Energy terminates 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
Armstrong Energy in anticipation of, or within 24 months
after, a change in control; or (iii) Armstrong Energy fails
to renew the agreement in anticipation of, or within
24 months after, a change in control:
(a) Armstrong Energy 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 and
Armstrong Energys health plan pursuant to COBRA or a
similar state law, Armstrong Energy 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 Armstrong Energy and another entity (or
Armstrong Energys securities and such other entity) as a
result of which the holders of all of Armstrong Energys
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 Armstrong Energys common stock
immediately prior to such transaction; (ii) the sale,
transfer, assignment or other disposition by Armstrong Energy 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 Armstrong Energy) of assets which account for an
aggregate of 50% or more of the consolidated revenues of
Armstrong Energy 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 Armstrong Energy
and/or its
subsidiaries of the business conducted by Armstrong Energy
and/or its
subsidiaries prior to such transaction; (iii) Armstrong
Energy is dissolved; or (iv) a majority of Armstrong
Energys 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 Armstrong Energys
shareholders) of each director who was not a member of
125
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 Agreements, 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 the named executive officers assuming that the
termination or change in control took place on the last business
day of Armstrong Energys last completed fiscal year.
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|
|
|
|
|
|
|
|
|
Termination
|
|
|
|
|
|
|
|
|
Termination
|
|
in Connection
|
|
|
Termination
|
|
Termination
|
|
Termination for
|
|
Without
|
|
with a Change
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Name
|
|
for Cause
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|
Without Cause
|
|
Good Reason
|
|
Good Reason
|
|
in Control
|
|
J. Hord Armstrong
|
|
|
|
|
|
$
|
896,498
|
|
|
$
|
896,498
|
|
|
|
|
|
|
$
|
1,075,248
|
|
Martin D. Wilson
|
|
|
|
|
|
$
|
898,058
|
|
|
$
|
898,058
|
|
|
|
|
|
|
$
|
1,088,808
|
|
Kenneth E. Allen
|
|
$
|
28,002
|
|
|
$
|
315,626
|
|
|
$
|
315,626
|
|
|
$
|
28,002
|
|
|
$
|
292,315
|
|
David R. Cobb, P.E
|
|
$
|
28,002
|
|
|
$
|
278,626
|
|
|
$
|
278,626
|
|
|
$
|
28,002
|
|
|
$
|
258,315
|
|
J. Richard Gist
|
|
|
|
|
|
$
|
334,404
|
|
|
$
|
334,404
|
|
|
|
|
|
|
$
|
334,404
|
|
2011
Long-Term Incentive Plan
Armstrong Energys board of directors recently adopted the
2011 LTIP for its employees and directors, as well as for
consultants and independent contractors who perform services for
it. 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 Armstrong Energys
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 Armstrong Energys
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 Armstrong Energy.
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
126
grant. The exercise price of incentive stock options granted to
holders of at least 10% of Armstrong Energys 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, Armstrong
Energys 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.
127
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table shows the amount of our common units
beneficially owned as of May 1, 2012, prior to the offering
and after giving effect to this offering by (i) each person
who is known by us to own beneficially more than 5% of our
common units, (ii) each member of the board of directors of
Armstrong Energy, (iii) each of the named executive
officers of Armstrong Energy, and (iv) all members of the
board of directors and the executive officers of Armstrong
Energy, as a group.
The percentage of common units beneficially owned prior to the
offering shown in the table is based upon 11,461,977 common
units outstanding as of May 1, 2012 (excluding 38,023
general partner units owned by our general partner) after giving
effect to conversion of all of our Series A convertible
preferred units into 1,068,376 common units, which will occur
automatically upon the closing of this offering. For purposes of
the conversion, we assumed that the initial public offering
price in this offering is $ per
unit, the midpoint of the range set forth on the cover page of
this prospectus. The information relating to numbers and
percentages of common units beneficially owned after the
offering gives effect to the issuance of common units in this
offering, assuming the initial public offering price in this
offering is $ per unit, the
midpoint of the range set forth on the cover page of this
prospectus.
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 common units listed. Except as otherwise noted, the
principal address for the unitholders listed below is
c/o Armstrong
Energy, Inc., 7733 Forsyth Boulevard, Suite 1625,
St. Louis, Missouri 63105.
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Common Units Beneficially
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|
Common Units Beneficially Owned Prior to this
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Owned After this
|
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|
Offering(1)
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Offering(2)(3)
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Name
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Number
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|
|
Percent
|
|
|
Number
|
|
|
Percent
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|
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J. Hord Armstrong, III
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|
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99,584
|
|
|
|
*
|
|
|
|
99,584
|
|
|
|
*
|
|
Martin D. Wilson
|
|
|
88,519
|
|
|
|
*
|
|
|
|
88,519
|
|
|
|
*
|
|
Kenneth E. Allen
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David R. Cobb, P.E.
|
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|
|
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|
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|
|
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J. Richard Gist
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|
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Anson M. Beard, Jr.
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|
|
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James C. Crain
|
|
|
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|
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Richard F. Ford
|
|
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|
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Bryan H. Lawrence(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Greg A. Walker
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Directors and Executive Officers as a group (11 persons)
|
|
|
188,103
|
|
|
|
1.64
|
%
|
|
|
188,103
|
|
|
|
1.51
|
%
|
Yorktown VII Associates LLC(4)(5)
|
|
|
1,863,150
|
|
|
|
16.26
|
%
|
|
|
1,863,150
|
|
|
|
14.95
|
%
|
Yorktown VIII Associates LLC(4)(6)
|
|
|
8,342,348
|
|
|
|
72.78
|
%
|
|
|
8,342,348
|
|
|
|
66.94
|
%
|
Yorktown IX Associates LLC(4)(7)
|
|
|
1,068,376
|
|
|
|
9.32
|
%
|
|
|
1,068,376
|
|
|
|
8.57
|
%
|
|
|
|
* |
|
Less than 1%. |
|
(1) |
|
Amounts give effect to an assumed 7.6047-to-1 unit split to
be effected prior to the effectiveness of the registration
statement of which this prospectus forms a part. |
|
(2) |
|
Assumes that the underwriters do not exercise their option to
purchase additional common units. |
|
(3) |
|
Assumes that none of the existing unitholders purchases units in
the directed share program or in the initial public offering. |
|
(4) |
|
The address of this beneficial owner is 410 Park Avenue, 19th
Floor, New York, New York 10022. |
128
|
|
|
(5) |
|
These units 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 common units 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. |
|
(6) |
|
These units 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 common units 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. |
|
(7) |
|
These units are held of record by Yorktown Energy Partners IX,
L.P. Yorktown IX Company LP is the sole general partner of
Yorktown Energy Partners IX, L.P. Yorktown IX Associates LLC is
the sole general partner of Yorktown IX Company LP. As a result,
Yorktown IX Associates LLC may be deemed to have the power to
vote or direct the vote or to dispose or direct the disposition
of the common units owned by Yorktown Energy Partners IX, L.P.
Yorktown IX Company LP and Yorktown IX Associates LLC disclaim
beneficial ownership of the securities owned by Yorktown Energy
Partners IX, L.P. in excess of their pecuniary interests
therein. Includes 1,068,376 common units issuable upon
conversion of 200,000 Series A convertible preferred units.
See Certain Relationships and Related Party
Transactions Sale of series A convertible preferred
units and Description of the common
units Description of Series A convertible preferred
units. Because the number of common units that will be
issued upon conversion of the Series A convertible
preferred units depends on the initial public offering price per
unit in this offering, the actual number of common units
issuable upon such conversion will likely differ from the
numbers set forth above. |
129
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Administrative
Services Agreement
Effective as of January 1, 2011, we and our general
partner, Elk Creek GP, entered into an Administrative Services
Agreement with Armstrong Energy, pursuant to which Armstrong
Energy will provide us 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, we were to 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 annual and monthly fees are subject
to adjustment annually in accordance with the terms of the
Administrative Services Agreement. For 2011, the fees due to
Armstrong Energy were adjusted such that the aggregate amount of
the annual and monthly fees paid to Armstrong Energy pursuant to
the Administrative Services Agreement was $720,000. For 2012,
the parties have agreed that the aggregate amount of the fees
due to Armstrong Energy will be $750,000. We will also be liable
for all taxes that are applicable to the services Armstrong
Energy provides on our behalf.
Sale of
Coal Reserves
We are majority-owned by Yorktown. Effective February 9,
2011, we and several of our affiliates participated in a
transaction with Armstrong Energy, Inc., 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 us. The borrowings were
evidenced by promissory notes in favor of us 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 our making these loans to it, Armstrong Energy
granted us a series of options to acquire interests in the
majority of coal reserves then held by Armstrong Energy in
Muhlenberg and Ohio Counties. On February 9, 2011, we
exercised our options, 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 Ceralvo Resources, LLC 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 Energys subsidiaries in the aforementioned
coal reserves. The aggregate amount paid by us to acquire our
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 us and several of our affiliates,
pursuant to which we joined Armstrong Energy as a co-borrower
under its Senior Secured Term Loan, and our 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 us 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 March 31, 2012 was
$120.0 million. Under the agreement, Armstrong Energy also
granted us a right of first refusal to purchase its remaining
interests in the coal reserves in which we acquired a 50.81%
undivided interest through the exercise of options described
above.
130
Lease
Agreements
On February 9, 2011, Armstrong Energy entered into a number
of coal mining lease agreements with our subsidiary Western
Mineral (our subsidiary) and two of Armstrong Energys
wholly-owned subsidiaries. Pursuant to these agreements, Western
Mineral granted Armstrong Energy 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 Energy 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 Energy also entered into a
lease and sublease agreement with our subsidiary Ceralvo
Holdings, LLC (Ceralvo Holdings). Pursuant to this
agreement, Ceralvo Holdings granted Armstrong Energy 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 Energy 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, subject to certain
limitations.
Royalty
Deferment and Option Agreement
Effective February 9, 2011, Armstrong Energy and its wholly
owned subsidiaries, Western Diamond and Western Land, entered
into a Royalty Deferment and Option Agreement with our wholly
owned subsidiaries, Western Mineral and Ceralvo Holdings.
Pursuant to this agreement, Western Mineral and Ceralvo Holdings
agreed to grant to Armstrong Energy 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 Energy
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 Energy and its affiliates would satisfy payment
of any deferred fees by selling part of their interest in the
aforementioned coal reserves.
Western
Diamond and Western Land Coal Reserves Sale Agreement
On October 11, 2011, two subsidiaries of Armstrong Energy,
Western Diamond and Western Land (together, the
Sellers), entered into an agreement with our
subsidiary, 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
Sale of Coal Reserves and
Concurrent Transactions with Armstrong
Energy), other than any of Sellers real property and
related mining rights associated with the Parkway mine.
Madisonville
Office Lease
Beginning in 2008, pursuant to an oral agreement, Armstrong
Energy leased from David R. Cobb, one of Armstrong Energys
executive officers, and Rebecca K. Cobb, Mr. Cobbs
spouse, certain property to be used by Armstrong Energy as its
office space in Madisonville, Kentucky, equipment, furniture,
supplies and the use of Mr. Cobbs employees.
Armstrong Energy 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 Energy entered into
a written lease agreement with Mr. and Mrs. Cobb regarding
the subject matter of the oral agreement. The terms of the
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.
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Grants of
Units to Directors and Executive Officers
We are managed by the executive officers and board of directors
of Armstrong Energy. Effective October 1, 2011, we entered
into a Restricted Unit Award Agreement with J. Hord
Armstrong, III, Armstrong Energys Chairman and Chief
Executive Officer, pursuant to which we granted
Mr. Armstrong 171,106 restricted limited partnership units.
Also effective October 1, 2011, we entered into a
Restricted Unit Award Agreement with Martin D. Wilson, Armstrong
Energys President and member of its board of directors,
pursuant to which we granted Mr. Wilson 152,094 restricted
limited partnership units. The grant date fair value of the
units awarded to Messrs. Armstrong and Wilson are
$3.1 million and $2.7 million, respectively.
Under the terms of each of the Restricted Unit Award Agreements,
all of the units granted vest on March 31, 2012, provided
that the grantee has continually provided services to Armstrong
Resource Partners through the vesting date. All unvested units
shall be forfeited in the event that the grantee no longer
provides services to Armstrong Resource Partners. Prior to
vesting, the grantee shall not be entitled to any voting rights
with respect to the units, but shall be entitled to receive all
cash dividends or distributions paid with respect to such units.
Notwithstanding the vesting provisions relating to the units,
all outstanding units shall be fully vested upon (i) a
change of control, as defined in the Restricted Unit Award
Agreements; (ii) the closing of this offering;
(iii) the closing of a private placement of our units
pursuant to Rule 144A under the Securities Act; or
(iv) the involuntary cessation of grantees provision
of services to Armstrong Resource Partners for reason other than
cause, as defined in the Restricted Unit Award Agreements.
Pursuant to the terms of each of the Restricted Unit Award
Agreements, the grantee was required to deliver to us that
number of restricted units, valued at the fair market value of
such units at the time of such delivery, to satisfy any federal,
state or local taxes due in connection with the grant. Effective
January 25, 2012, Mr. Armstrong entered into an
Assignment of Limited Partnership Units with us, pursuant to
which Mr. Armstrong transferred and assigned
71,522 units to us, in exchange for our agreement to pay
any federal, state or local taxes arising from the grant, the
total amount of which has been determined to be equal to
approximately $1.3 million. Also effective January 25,
2012, Mr. Wilson entered into an Assignment of Limited
Partnership Units with us, pursuant to which Mr. Wilson
transferred and assigned 63,575 units to us, in exchange
for our agreement to pay any federal, state or local taxes
arising from the grant, the total amount of which has been
determined to be equal to approximately $1.1 million.
Sale of
Series A Convertible Preferred Units
In December 2011, we sold 200,000 Series A convertible
preferred units of limited partner interest to Yorktown Energy
Partners IX, L.P., one of the investment funds managed by
Yorktown Partners LLC, in exchange for $20.0 million. The
holders of Series A convertible preferred units vote
together as a single class with the holders of common units,
with each Series A convertible preferred unit having one
vote per unit, on all matters submitted to a vote of the holders
of common units, except that when the Series A convertible
preferred units and the common units vote together as a single
class, then each holder of Series A convertible preferred
units shall be entitled to the number of votes with respect to
such holders Series A convertible preferred units
equal to the number of whole units into which such Series A
convertible preferred units would have been converted under the
provisions of the designation at the conversion price then in
effect on the record date for determining partners entitled to
vote on such matters or, if no record date is specified, as of
the date of such vote. See Description of the Common
Units Description of Series A Convertible
Preferred Units. Therefore, as a result of the
transaction, Yorktown Energy Partners IX, L.P. became the
beneficial owner of more than 5% of our voting securities.
Membership
Interest Purchase Agreement
In December 2011, we entered into a Membership Interest Purchase
Agreement with Armstrong Energy pursuant to which Armstrong
Energy 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 its membership
interests in such limited liability company, an additional
partial undivided interest in reserves controlled by
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Armstrong Energy. In exchange for the agreement to sell a
partial undivided interest in those reserves, we paid Armstrong
Energy $20.0 million. In addition to the cash paid, certain
amounts due to us totaling $5.7 million were forgiven by
Armstrong Energy, which resulted in aggregate consideration of
$25.7 million. This transaction, which closed in March
2012, resulted in the transfer by Armstrong Energy of an 11.36%
undivided interest in certain of its land and mineral reserves
to Armstrong Resource Partners. We agreed to lease the newly
transferred mineral reserves to Armstrong Energy on the same
terms as the February 2011 lease.
Concurrent
Transactions with Armstrong Energy
Concurrent with this offering of common stock, Armstrong Energy
is offering common stock pursuant to a separate initial public
offering (the Concurrent ARP Offering). Armstrong
Energy indirectly holds a 0.3% equity interest in us. See
Business Our Organizational History.
If the Concurrent AE Offering and the related transactions
between Armstrong Resource Partners and Armstrong Energy are
completed, we expect that Armstrong Energy will use
$40.0 million, assuming an offering price of
$ per share, the midpoint of the
range set forth on the cover of the prospectus for the
Concurrent AE Offering, of the net proceeds from the Concurrent
AE Offering to repay a portion of Armstrong Energys
outstanding borrowings under its Senior Secured Term Loan, and
that it will use the balance to repay a portion of its
outstanding borrowings under the Senior Secured Revolving Credit
Facility and for general corporate purposes, including to fund
capital expenditures relating to Armstrong Energys 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 Armstrong Energys
leverage ratio and the applicable interest option elected. The
interest rate as of March 31, 2012 was 5.25%. The Senior
Secured Term Loan matures on February 9, 2016. See
Description of Indebtedness. Raymond James Bank,
FSB, an affiliate of Raymond James & Associates, Inc.
is a lender under the Senior Secured Term Loan and the Senior
Secured Revolving Credit Facility and may receive a portion of
the net proceeds of this offering.
While we expect that Armstrong Energy will consummate the
Concurrent AE Offering concurrently with this offering of common
units, the completion of this offering is not subject to the
completion of the Concurrent AE Offering and the completion of
the Concurrent AE Offering is not subject to the completion of
this offering.
This description and other information in this prospectus
regarding the Concurrent AE 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 stock of Armstrong
Energy.
Policies
and Procedures for Related Party Transactions
The audit committee of Armstrong Energy must review and approve
all transactions between us 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 audit committee will
take into account any factors it deems relevant.
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CONFLICTS
OF INTEREST AND FIDUCIARY DUTIES
Conflicts
of Interest
Conflicts of interest exist and may arise in the future as a
result of the relationships between Armstrong Energy and its
affiliates (including general partner) on the one hand, and our
Partnership and our unitholders, on the other hand. The
directors and officers of Armstrong Energy have fiduciary duties
to manage its affiliates, including our general partner, in a
manner beneficial to its owners. At the same time, Armstrong
Energy, through control of our general partner, Elk Creek GP,
has a fiduciary duty to manage our Partnership in a manner
beneficial to us and our unitholders.
Whenever a conflict arises between Armstrong Energy and its
affiliates, on the one hand, and our Partnership or any other
partner, on the other, Armstrong Energy will resolve that
conflict. Armstrong Energy may, but is not required to, seek the
approval of the conflicts committee of Armstrong Energys
board of directors of such resolution. The Partnership Agreement
contains provisions that allow Armstrong Energy to take into
account the interests of other parties in addition to our
interests when resolving conflicts of interest. In effect, these
provisions limit Armstrong Energys fiduciary duties to our
unitholders. Delaware case law has not definitively established
the limits on the ability of a partnership agreement to restrict
such fiduciary duties. The Partnership Agreement also restricts
the remedies available to unitholders for actions taken by
Armstrong Energy that might, without those limitations,
constitute breaches of fiduciary duty.
Armstrong Energy will not be in breach of its obligations under
the Partnership Agreement or its duties to us or our unitholders
if the resolution of the conflict is considered to be fair and
reasonable to us. Any resolution is considered to be fair and
reasonable to us if that resolution is:
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approved by the conflicts committee, although Armstrong Energy
is not obligated to seek such approval and Armstrong Energy may
adopt a resolution or course of action that has not received
approval;
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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fair to us, taking into account the totality of the
relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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In resolving a conflict, Armstrong Energy, including its
conflicts committee, may, unless the resolution is specifically
provided for in the Partnership Agreement, consider:
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the relative interests of any party to such conflict and the
benefits and burdens relating to such interest;
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any customary or accepted industry practices or historical
dealings with a particular person or entity;
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generally accepted accounting practices or principles; and
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such additional factors it determines in its sole discretion to
be relevant, reasonable or appropriate under the circumstances.
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Conflicts of interest could arise in the situations described
below, among others.
Actions
taken by Armstrong Energy may affect the amount of cash
available for distribution to unitholders.
The amount of cash that is available for distribution to
unitholders is affected by decisions of Armstrong Energy
regarding such matters as:
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amount and timing of asset purchases and sales;
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cash expenditures;
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borrowings;
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the issuance of additional common units; and
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the creation, reduction or increase of reserves in any quarter.
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In addition, borrowings by us and our affiliates do not
constitute a breach of any duty owed by Armstrong Energy to the
unitholders.
The Partnership Agreement provides that we and our subsidiaries
may borrow funds from Armstrong Energy and its affiliates.
Armstrong Energy and its affiliates may borrow funds from us or
our subsidiaries.
We do
not have any officers or employees and rely solely on officers
and employees of Armstrong Energy, Inc. and its affiliates.
Additionally, officers and employees of Armstrong Energy may
allocate acquisition opportunities to Armstrong Energy that may
have otherwise been pursued by us.
We do not have any officers or employees and rely solely on
officers and employees of Armstrong Energy, Inc. and its
affiliates. Affiliates of Armstrong Energy conduct businesses
and activities of their own in which we have no economic
interest. If these separate activities are significantly greater
than our activities, there could be material competition for the
time and effort of the officers and employees who provide
services to Armstrong Energy. The officers of Armstrong Energy
are not required to work full time on our affairs. These
officers devote significant time to the affairs of Armstrong
Energy and its affiliates and are compensated by these
affiliates for the services rendered to them. Additionally,
officers and employees of Armstrong Energy may allocate
acquisition opportunities to Armstrong Energy that may have
otherwise been pursued by us.
We
reimburse Armstrong Energy and its affiliates for
expenses.
We reimburse Armstrong Energy and its affiliates for costs
incurred in managing and operating us, including costs incurred
in rendering corporate staff and support services to us. The
Partnership Agreement provides that Armstrong Energy determines
the expenses that are allocable to us in any reasonable manner
determined by Armstrong Energy in its sole discretion.
Armstrong
Energy intends to limit its liability regarding our
obligations.
Armstrong Energy intends to limit its liability under
contractual arrangements so that the other party has recourse
only to our assets, and not against Armstrong Energy or its
assets. The Partnership Agreement provides that any action taken
by Armstrong Energy to limit its liability or our liability is
not a breach of Armstrong Energys fiduciary duties, even
if we could have obtained more favorable terms without the
limitation on liability.
Unitholders
have no right to enforce obligations of Armstrong Energy and its
affiliates under agreements with us.
Any agreements between us on the one hand, and Armstrong Energy
and its affiliates, on the other, do not grant to the
unitholders, separate and apart from us, the right to enforce
the obligations of Armstrong Energy and its affiliates in our
favor and Armstrong Energy has the power and authority to
conduct our business without unitholder or conflict committee
approval, on such terms as it determines to be necessary or
appropriate.
Contracts
between us, on the one hand, and Armstrong Energy and its
affiliates, on the other, are not the result of
arms-length negotiations.
The Partnership Agreement allows Armstrong Energy to pay itself
or its affiliates for any services rendered to us, provided
these services are rendered on terms that are fair and
reasonable. Armstrong Energy may also enter into additional
contractual arrangements with any of its affiliates on our
behalf. Neither the Partnership Agreement nor any of the other
agreements, contracts and arrangements between us, on the one
hand, and Armstrong Energy and its affiliates, on the other, are
the result of arms-length negotiations. This may result in
lower leasing revenues than if a lease had been negotiated with
an unaffiliated third party.
We may
not choose to retain separate counsel for ourselves or for the
holders of common units.
The attorneys, independent auditors and others who have
performed services for us in the past were retained by Armstrong
Energy, its affiliates and us and have continued to be retained
by Armstrong Energy, its
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affiliates and us. Attorneys, independent auditors and others
who perform services for us are selected by Armstrong Energy or
the conflicts committee and may also perform services for
Armstrong Energy and its affiliates. We may retain separate
counsel for ourselves or the holders of common units in the
event of a conflict of interest arising between Armstrong Energy
and its affiliates, on the one hand, and us or the holders of
common units, on the other, depending on the nature of the
conflict. We do not intend to do so in most cases. Delaware case
law has not definitively established the limits on the ability
of a Partnership Agreement to restrict such fiduciary duties.
Director
Independence
For a discussion of the independence of the members of the board
of directors of Armstrong Energy under applicable standards,
please read Management.
Review,
Approval or Ratification of Transactions with Related
Persons
If a conflict or potential conflict of interest arises between
Armstrong Energy and its affiliates (including our general
partner) on the one hand, and our Partnership and our limited
partners, on the other hand, the resolution of any such conflict
or potential conflict is addressed as described under
Conflicts of Interest.
For a description of our other relationships with our
affiliates, please read Certain Relationships and Related
Party Transactions.
Fiduciary
Duties
Our general partner is accountable to us and our unitholders as
a fiduciary. Fiduciary duties owed to unitholders by our general
partner are prescribed by law and the Partnership Agreement. The
Delaware Act provides that Delaware limited partnerships may, in
their partnership agreements, modify or eliminate, except for
the contractual covenant of good faith and fair dealing, the
fiduciary duties owed by the general partner to limited partners
and the partnership.
Our Partnership Agreement contains various provisions
restricting the fiduciary duties that might otherwise be owed by
our general partner. We have adopted these provisions to allow
our general partner or its affiliates to engage in transactions
with us that would otherwise be prohibited by state-law
fiduciary standards and to take into account the interests of
other parties in addition to our interests when resolving
conflicts of interest. Without such modifications, such
transactions could result in violations of our general
partners state-law fiduciary duty standards. We believe
this is appropriate and necessary because the board of directors
of our general partners parent corporation has fiduciary
duties to manage itself and our general partner in a manner
beneficial both to its owners, as well as to our unitholders.
Without these modifications, our general partners ability
to make decisions involving conflicts of interest would be
restricted. The modifications to the fiduciary standards enable
our general partner to take into consideration the interests of
all parties involved, so long as the resolution is fair and
reasonable to us. These modifications also enable our general
partners parent corporation to attract and retain
experienced and capable directors. These modifications
disadvantage the unitholders because they restrict the rights
and remedies that would otherwise be available to unitholders
for actions that, without those limitations, might constitute
breaches of fiduciary duty, as described below, and permit our
general partner to take into account the interests of third
parties in addition to our interests when
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resolving conflicts of interest. The following is a summary of
the material restrictions of the fiduciary duties owed by our
general partner to the limited partners:
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State law fiduciary duty standards
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Fiduciary duties are generally considered to include an
obligation to act in good faith and with due care and loyalty.
The duty of care, in the absence of a provision in a partnership
agreement providing otherwise, would generally require a general
partner to act for the partnership in the same manner as a
prudent person would act on his own behalf. The duty of
loyalty, in the absence of a provision in a partnership
agreement providing otherwise, would generally prohibit a
general partner of a Delaware limited partnership from taking
any action or engaging in any transaction where a conflict of
interest is present.
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Partnership Agreement modified standards
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Our Partnership Agreement contains provisions that waive or
consent to conduct by our general partner and its affiliates
that might otherwise raise issues as to compliance with
fiduciary duties or applicable law. For example, our Partnership
Agreement provides that when our general partner is acting in
its individual capacity, as opposed to in its capacity as our
general partner, it may act without any fiduciary obligation to
us or our limited partners whatsoever. Our Partnership Agreement
reduces the obligations to which our general partner would
otherwise be held.
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Our Partnership Agreement generally provides that affiliated
transactions and resolutions of conflicts of interest not
involving a vote of unitholders or that are not approved by the
conflicts committee of our general partners parent
corporation must be:
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on terms no less favorable to us than
those generally being provided to or available from unrelated
third parties; or
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fair and reasonable to us,
taking into account the totality of the relationships between
the parties involved (including other transactions that may be
particularly favorable or advantageous to us).
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If our general partner does not seek approval from Armstrong
Energys conflicts committee and Armstrong Energys
board of directors determines that the resolution or course of
action taken with respect to the conflict of interest satisfies
either of the standards set forth in the bullet points above,
then such conflict of interest and an resolution of such
conflict of such conflict or interest shall be conclusively
deemed fair and reasonable to the partnership. These standards
reduce the obligations to which our general partner would
otherwise be held.
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By accepting a certificate evidencing its purchase and ownership
of our common units, each unitholder automatically agrees to be
bound by the provisions in our Partnership Agreement, including
the provisions discussed above. This is in accordance with the
policy of the Delaware Act favoring the principle of freedom of
contract and the enforceability of partnership agreements. The
failure of a limited partner to sign a partnership agreement
does not render the partnership agreement unenforceable against
that person.
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Under our Partnership Agreement, we must indemnify our general
partner, its parent corporation Armstrong Energy, and the
officers and directors of Armstrong Energy (each, an
Indemnitee) to the fullest extent permitted by law
from and against any and all losses, claims, damages,
liabilities, joint or several, expenses (including legal fees
and expenses), judgments, fines, penalties, interest,
settlements or other amounts arising from any and all claims,
demands, actions, suits or proceedings, whether civil, criminal,
administrative or investigative, in which any such Indemnitee
may be involved, or is threatened to be involved, as a party or
otherwise, by reason of its status as an Indemnitee; provided,
that in each case the Indemnitee acted in good faith and in a
manner that such Indemnitee reasonably believed to be in, or (in
the case of a person other than the general partner or Armstrong
Energy) not opposed to, the best interests of the Partnership
and, with respect to any criminal proceeding, had no reasonable
cause to believe its conduct was unlawful. Thus, our general
partner, Armstrong Energy, and any other qualified Indemnitee
could be indemnified for its negligent act if it met the
requirements set forth above. To the extent that these
provisions purport to include indemnification for liabilities
arising under the Securities Act, in the opinion of the SEC,
such indemnification is contrary to public policy and therefore
unenforceable. See The Partnership Agreement.
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DESCRIPTION
OF THE COMMON UNITS
The
Common Units
The common units represent limited partner interests in us. The
holders of common units are entitled to participate in
Partnership distributions, if any, and are entitled to exercise
the rights and privileges available to limited partners under
our Partnership Agreement. For a description of the rights and
privileges of limited partners under our Partnership Agreement,
including voting rights, please read The Partnership
Agreement. As of May 1, 2012, prior to conversion of
the Series A preferred units, we had 10,393,600 common units
outstanding, held of record by four unitholders and 38,023
general partner units held by our general partner.
Transfer
of Common Units
The transfer of the common units to persons that purchase
directly from the underwriters will be accomplished through the
proper completion, execution and delivery of a transfer
application by the investor. Any later transfers of a common
unit will not be recorded by the transfer agent or recognized by
us unless the transferee executes and delivers a properly
completed transfer application. By executing and delivering a
transfer application, the transferee of common units:
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automatically requests admission as a substituted limited
partner in our Partnership;
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agrees to comply with and be bound and to have executed our
Partnership Agreement;
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represents and warrants that the transferee has the right, power
and authority and, if an individual, the capacity to enter into
our Partnership Agreement;
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grants the powers of attorney set forth in our Partnership
Agreement; and
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gives the consents and approvals and makes the waivers contained
in our Partnership Agreement.
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A transferee that executes and delivers a properly completed
transfer application will become a substituted limited partner
of our Partnership for the transferred common units upon the
recording of the transfer on our books and records. Our general
partner will cause any transfers to be recorded on our books and
records no less frequently than quarterly.
The Partnership shall be entitled to recognize the record holder
of common units as the partner or assignee with respect to such
common units and, accordingly, shall not be bound to recognize
any equitable or other claim to or interest in such common
units, except as otherwise provided by applicable law, rule, or
regulation. When a person such as broker, dealer, bank, trust
company or clearing corporation is acting as nominee, agent or
in some other representative capacity for another person in
acquiring and/or holding common units, such representative
person (a) shall be the partner or assignee of record and
beneficially, (b) must execute and deliver a transfer
application, and (c) shall be bound by the Partnership Agreement.
Common units are securities and any transfers are subject to the
laws governing the transfer of securities. In addition to other
rights acquired upon transfer, the transferor gives the
transferee the right to become a substituted limited partner in
our Partnership for the transferred common units. A purchaser or
transferee of common units who does not execute and deliver a
properly completed transfer application obtains only:
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the right to assign the common unit to a purchaser or other
transferee; and
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the right to transfer the right to seek admission as a
substituted limited partner in our Partnership for the
transferred common units.
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Thus, a purchaser or transferee of common units who does not
execute and deliver a properly completed transfer application:
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will not receive cash distributions;
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will not be allocated any of our income, gain, deduction, losses
or credits for federal income tax or other tax purposes; and
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may not receive some federal income tax information or reports
furnished to record holders of common units;
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unless the common units are held in a nominee or street
name account and the nominee or broker has executed and
delivered a transfer application and certification as to itself
and any beneficial holders.
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The transferor does not have a duty to ensure the execution of
the transfer application by the transferee and has no liability
or responsibility if the transferee neglects or chooses not to
execute and deliver a properly completed transfer application to
the transfer agent. Please read The Partnership
Agreement Status as Limited Partner.
Until a common unit has been transferred on our books, we and
the transfer agent may treat the record holder of the unit as
the absolute owner for all purposes, except as otherwise
required by law or stock exchange regulations.
Description
of Series A Convertible Preferred Units
The designation for the Series A convertible preferred
units authorizes 200,000 units of Series A convertible
preferred units, all of which are outstanding as of May 1,
2012.
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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 any units of partnership interest
of the Partnership or other equity securities of the Partnership
other than the Series A convertible preferred units.
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Liquidation Preference. In the event of any
liquidation, dissolution, or winding up of the Partnership, a
holder of Series A convertible preferred units 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 Series A convertible preferred unit held by such
holder.
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Dividends. Holders of the Series A
convertible preferred units are not entitled to the payment of
any dividends by the Partnership.
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Conversion. Upon the closing of this offering,
all of the outstanding Series A convertible preferred units
will automatically and without further action required by any
person convert into that number of units equal to the quotient
obtained by dividing (i) $100 times the number of
units to be converted, by (ii) the initial public offering
price per unit of the common units sold in this offering, less
any underwriting discount per unit for the common units issued
in this offering, as reflected in the final prospectus filed
with the SEC.
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Voting. The holders of Series A
convertible preferred units shall vote together as a single
class with the holders of common units, with each Series A
convertible preferred unit having one vote per unit, on all
matters submitted to a vote of the holders of common units,
except that when the Series A convertible preferred units
and the common units shall vote together as a single class, then
each holder of Series A convertible preferred units shall
be entitled to the number of votes with respect to such
holders Series A convertible preferred units equal to
the number of whole units into which such Series A
convertible preferred units would have been converted under the
provisions of the designation at the conversion price then in
effect on the record date for determining partners 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
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Series A convertible preferred units remain outstanding,
the holders of a majority of the Series A convertible
preferred units must approve, voting separately as a class:
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Any amendment to the Partnership Agreement that would affect
adversely the rights, preferences, privileges or voting rights
of holders of the Series A convertible preferred units or
the terms of the Series A convertible preferred units;
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Any proposed issuance of class of partnership interests in the
Partnership that ranks pari passu or senior to the
Series A convertible preferred units, or any proposed
issuance of any Junior Securities which are required to be
redeemed by the Partnership at any time that any Series A
convertible preferred units 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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DESCRIPTION
OF INDEBTEDNESS
In February 2011, Armstrong Energy repaid certain promissory
notes that were delivered in connection with the acquisition of
its coal reserves (see Business Our
History) and entered into the Senior Secured Credit
Facility, which is composed of the $100.0 million Senior
Secured Term Loan and the $50.0 million Senior Secured
Revolving Credit Facility. We are a co-borrower with respect to
the Senior Secured Term Loan and guarantor on the Senior Secured
Revolving Credit Facility and the Senior Secured Term Loan, and
substantially all of our assets are pledged to secure borrowings
under the Senior Secured Credit Facility. We are not permitted
to borrow additional funds under the Senior Secured Credit
Facility. Of the proceeds from Armstrong Energys
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 Armstrong
Energys long-term debt obligations as of December 31,
2010. As a result of the repayment of its existing debt
obligations, Armstrong Energy realized a gain on extinguishment
of debt of approximately $7.0 million in the year ended
December 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 Armstrong Energys
leverage ratio and the applicable interest option elected. The
interest rate as of March 31, 2012 was 5.25%. The Senior
Secured Revolving Credit Facility provides for quarterly
interest payments in arrears that fluctuate on the same terms as
Armstrong Energys 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
March 31, 2012, Armstrong Energy had $25.0 million
outstanding, with $25.0 million available for borrowing
under its Senior Secured Revolving Credit Facility. The
obligations under the credit agreement are secured by a first
lien on substantially all of Armstrong Energys assets,
including but not limited to certain of its 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.
Armstrong Energy 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 its 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 0.478% as of March 31, 2012. 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
Revolving Credit 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, Armstrong Energy entered into the First
Amendment to its Senior Secured Credit Facility which, among
other things, amended the provisions of the loan documents so as
to permit an offering of its securities and the completion of
Armstrong Energys reorganization. The amendment also made
certain changes to Armstrong Energys financial covenants,
including its maximum leverage ratio. In addition, Armstrong
Energys interest rate increased to 5.75%, which can be
reduced in future periods to the extent Armstrong Energys
results improve. Armstrong Energy 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. Armstrong Energy entered into the Second Amendment to its
Senior Secured Credit Facility on September 29, 2011,
pursuant to which restrictions to the consummation of the AE
Concurrent Offering were eliminated. Additionally, on
December 29, 2011, Armstrong Energy entered into the Third
Amendment to its 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, Armstrong Energy entered into the Fourth
Amendment to its Senior Secured Credit Facility which, among
other things, amended the provisions of the loan documents so as
to continue a consolidated EBITDA threshold, eliminate the
minimum fixed charge coverage ratio, add a minimum interest
coverage ratio beginning in 2013 and make certain changes to
Armstrong Energys financial covenants, including its
maximum leverage ratio and its minimum consolidated EBITDA. In
connection with entry into the Third and Fourth Amendments to
the Senior Secured Credit Facility, Armstrong Energy paid fees
in the aggregate amount of $1.125 million.
142
THE
PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our
Partnership Agreement as amended and restated, to be in effect
on the date of the closing of this offering.
We summarize the following provisions of our Partnership
Agreement elsewhere in this prospectus:
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with regard to distributions of available cash, please see
Cash Distribution Policy and Restrictions on
Distributions;
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with regard to the transfer of common units, please see
Description of the Common Units Transfer of
Common Units; and
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with regard to allocations of taxable income and taxable loss,
please see Material Tax Consequences.
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Organization
and Duration
Our Partnership was formed on March 25, 2008, and will
remain in existence until dissolved in accordance with our
Partnership Agreement.
Purpose
The purpose and nature of the business to be conducted by the
Partnership under our Partnership Agreement is to
(a) engage in the acquisition and management of coal
producing and other revenue-generating properties,
(b) engage in the leasing or other disposition of coal
producing properties, in exchange for royalty or other payments,
or other qualifying income generating activities,
(c) engage directly in, or enter into or form any
corporation, partnership, joint venture, limited liability
company or other arrangement to engage indirectly in, any
business activity that is approved by our general partner and
which lawfully may be conducted by a limited partnership
organized pursuant to the Delaware Act and, in connection
therewith, to exercise all of the rights and powers conferred
upon the Partnership pursuant to the agreements relating to such
business activity, and (d) do anything necessary or
appropriate to the foregoing.
Notwithstanding the foregoing, our general partner does not have
the authority to cause us to engage, directly or indirectly, in
any business activity that it reasonably determines would cause
us to be treated as an association taxable as a corporation or
otherwise taxable as an entity for federal income tax purposes.
Further, our general partner has no obligation or duty to the
Partnership, the limited partners or assignees to propose or
approve, and in its discretion may decline to propose or
approve, the conduct by the Partnership of any business.
Although our general partner has the ability to cause us to
engage in activities other than the ownership of coal and
mineral reserves and the leasing of those reserves to mine
operators in exchange for royalties from the sale of coal or
other minerals mined from our reserves, our general partner has
no current plans to do so.
Power of
Attorney
Each limited partner and each person who acquires a limited
partner interest from a limited partner and executes and
delivers a transfer application grants to our general partner
(and, if appointed, a liquidator), a power of attorney to, among
other things, execute and file documents required for our
qualification, continuance or dissolution. The power of attorney
also grants our general partner the authority to amend, and to
make consents and waivers under, and in accordance with, our
Partnership Agreement.
Capital
Contributions
Limited partners are not obligated to make additional capital
contributions to the Partnership, except as described below
under Limited Liability.
For a discussion of our general partners right to make
additional capital contributions to maintain its 0.3% general
partner interest if we issue additional limited partner
interests, please read Issuance of Additional
Securities.
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Limited
Liability
Participation in the Control of Our
Partnership. Assuming that a limited partner does
not participate in the control of our business within the
meaning of the Delaware Act and that it otherwise acts in
conformity with the provisions of our Partnership Agreement, its
liability under the Delaware Act will be limited, subject to
possible exceptions, to the amount of capital it is obligated to
contribute to us for its limited partner interests plus its
share of any undistributed profits and assets. If it were
determined, however, that the right or exercise of the right by
the limited partners as a group:
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to approve some amendments to our Partnership Agreement; or
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to take other action under our Partnership Agreement;
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constituted participation in the control of our
business for the purposes of the Delaware Act, then the limited
partners could be held personally liable for our obligations
under Delaware law to the same extent as the general partner.
This liability would extend to persons who transact business
with us and who reasonably believe that the limited partner is a
general partner. Neither our Partnership Agreement nor the
Delaware Act specifically provides for legal recourse against
our general partner if a limited partner were to lose limited
liability through any fault of the general partner. While this
does not mean that a limited partner could not seek legal
recourse, we have found no precedent for this type of a claim in
Delaware case law.
Unlawful
Partnership Distributions
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if, after the distribution, all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of the partnership, would exceed the fair
value of the assets of the limited partnership. For the purpose
of determining the fair value of the assets of a limited
partnership, the Delaware Act provides that the fair value of
property subject to liability for which recourse of creditors is
limited shall be included in the assets of the limited
partnership only to the extent that the fair value of that
property exceeds the nonrecourse liability. The Delaware Act
provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was
in violation of the Delaware Act shall be liable to the limited
partnership for the amount of the distribution for three years.
Under the Delaware Act, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the
obligations of his assignor to make contributions to the
partnership, except the assignee is not obligated for
liabilities unknown to him at the time he became a limited
partner and that could not be ascertained from the partnership
agreement.
Failure
to Comply with the Limited Liability Provisions of Jurisdictions
in Which We Do Business
Maintenance of our limited liability may require compliance with
legal requirements in the jurisdictions in which we or our
subsidiaries conduct business, including qualifying the
applicable entities to do business there. If it were determined
that we were conducting business in any state without compliance
with the applicable limited partnership statute, or that the
right or exercise of the right by the limited partners to
approve certain amendments to our Partnership Agreement, or to
take other action under our Partnership Agreement constituted
participation in the control of our business for
purposes of the statutes of any relevant jurisdiction, then the
limited partners could be held personally liable for our
obligations under the law of that jurisdiction to the same
extent as the general partner under the circumstances. We will
operate in a manner that our general partner considers
reasonable and necessary or appropriate to preserve the limited
liability of the limited partners.
Voting
Rights
The following is a summary of the limited partner vote required
for approval of the matters specified below. Matters that
require the approval of a unit majority require at
least a majority of the Partnerships outstanding units.
Partnership securities, including general partner units, held by
the general partner are generally not considered outstanding for
voting purposes.
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The following matters require the limited partner vote specified
below:
Issuance of additional limited partner
interests No approval right.
Amendment of the Partnership Agreement
Certain amendments may be made by the general partner without
the approval of the limited partners. Other amendments generally
require the approval of a unit majority. Please read
Amendment of the Partnership Agreement.
Merger of the Partnership or the sale of all or substantially
all of the Partnerships assets Unit
majority. Please read Merger, Sale or Other
Disposition of Assets.
Dissolution of the Partnership Unit majority.
Please read Termination and Dissolution.
Reconstitution of the Partnership upon
dissolution Unit majority.
Withdrawal of the general partner No approval
right. Please read Withdrawal or Removal of
the General Partner.
Removal of the general partner No approval
right for limited partners other than Yorktown. Yorktown
unilaterally may remove the general partner in some
circumstances. Please read Withdrawal or
Removal of the General Partner.
Election of a successor general partner Unit
majority.
Transfer of the general partner interest No
approval right. The general partner may transfer any or all of
its general partner interest, provided that (i) the
transferee agrees to assume the rights and duties of the general
partner under the Partnership Agreement and to be bound by the
provisions of the agreement, (ii) the Partnership receives
an opinion of counsel that such transfer would not result in the
loss of limited liability of any limited partner or cause the
Partnership to be treated as an association taxable as a
corporation or otherwise to be taxed as an entity for federal
income tax purposes (to the extent not already so treated or
taxed) and (iii) such transferee also agrees to purchase
all (or the appropriate portion thereof, as applicable) of the
Partnership or membership interest of the general partner as the
general partner or managing member, if any, and of each
affiliate of the general partner. Please read
Transfer of General Partner Interest.
Transfer of ownership interests in the general
partner No approval right.
Change of
Management Provisions
If at any time any person or group other than our general
partner, Yorktown or their respective affiliates acquires
beneficial ownership of 20% or more of any outstanding
Partnership securities of any class then outstanding, all
Partnership securities owned by such person or group shall not
be voted on any matter and shall for most purposes not be
considered to be outstanding. This loss of voting rights does
not apply to any person or group that acquires the Partnership
securities from our general partner, Yorktown or their
respective affiliates and any transferees of that person or
group approved by our general partner or to any person or group
who acquires the Partnership securities with the prior approval
of the board of directors of our general partner.
Issuance
of Additional Securities
Our Partnership Agreement authorizes us to issue an unlimited
number of additional Partnership securities and rights to buy
Partnership securities for the consideration and on the terms
and conditions established by our general partner in its sole
discretion without the approval of any limited partners.
It is possible that we will fund acquisitions through the
issuance of additional limited partner interests or other equity
securities. Holders of any additional limited partner interests
we issue will be entitled to share equally with the
then-existing limited partners in our distributions of available
cash. In addition, the issuance of additional limited partner
interests or other equity securities may dilute the value of the
interests of the then existing holders of limited partner
interests in our net assets.
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In accordance with Delaware law and the provisions of our
Partnership Agreement, we may also issue additional Partnership
securities that, in the sole discretion of our general partner,
may have special voting rights to which the limited partner
interests are not entitled.
Upon issuance of additional limited partner interests, our
general partner may, in order to maintain its percentage
interest, make additional capital contributions in an amount
equal to the product obtained by multiplying (i) the
quotient determined by dividing (A) the general
partners percentage interest by (B) 100 less the
general partners percentage interest times (ii) the
amount contributed to the Partnership by the limited partners in
exchange for such additional limited partner interests.
Amendment
of Partnership Agreement
General. Amendments to our Partnership
Agreement may be proposed only by or with the consent of our
general partner, which consent may be given or withheld in its
sole discretion. In order to adopt a proposed amendment, other
than the amendments discussed below, our general partner is
required to seek written approval of the holders of the number
of outstanding units required to approve the amendment or call a
meeting of the limited partners to consider and vote upon the
proposed amendment. Except as described below, an amendment must
be approved by a unit majority.
Prohibited Amendments. No amendment may be
made that would:
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enlarge the obligations of any limited partner without its
consent, unless approved by at least a majority of the type or
class of limited partner interests so affected;
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enlarge the obligations of, restrict in any way any action by or
rights of, or reduce in any way the amounts distributable,
reimbursable or otherwise payable by us to our general partner
or any of its affiliates without the consent of our general
partner, which may be given or withheld in its sole discretion;
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change the term of the Partnership;
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provide that we are not dissolved upon an election to dissolve
our Partnership by our general partner that is approved by a
unit majority; or
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give any person the right to dissolve our Partnership other than
our general partners right to dissolve our Partnership
with the approval of a unit majority.
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The provision of our Partnership Agreement preventing the
amendments having the effects described in any of the clauses
above can be amended upon the approval of the holders of at
least 90% of the outstanding units, voting together as a single
class (including units owned by the general partner and its
affiliates).
No Unitholder Approval. Our general partner
may generally make amendments to our Partnership Agreement
without the approval of any limited partner or assignee to
reflect:
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a change in our name, the location of our principal place of our
business, our registered agent or our registered office;
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the admission, substitution, withdrawal or removal of partners
in accordance with our Partnership Agreement;
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a change that, in the sole discretion of the general partner, is
necessary or advisable for us to qualify or continue our
qualification as a limited partnership or a partnership in which
the limited partners have limited liability under the laws of
any state or to ensure that neither we nor any of our
subsidiaries will be treated as an association taxable as a
corporation or otherwise taxed as an entity for federal income
tax purposes;
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a change in the fiscal year or taxable year of the Partnership
and any changes that, in the discretion of the general partner,
are necessary or advisable as a result of a change in the fiscal
year or taxable year of the Partnership including, if the
general partner shall so determine, a change in the definition
of quarter and the dates on which distributions are
to be made by the Partnership;
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an amendment that is necessary, in the opinion of counsel, to
prevent us or our general partner or its directors, officers,
agents or trustees from in any manner being subjected to the
provisions of the Investment Company Act of 1940, as amended,
the Investment Advisors Act of 1940, as amended, or plan
asset regulations adopted under the Employee Retirement
Income Security Act of 1974, whether or not substantially
similar to plan asset regulations currently applied or proposed
by the United States Department of Labor;
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an amendment that in the discretion of our general partner is
necessary or advisable in connection with the authorization of
issuance of any class or series of Partnership securities
pursuant to the terms of the Partnership Agreement;
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any amendment expressly permitted in our Partnership Agreement
to be made by our general partner acting alone;
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an amendment effected, necessitated or contemplated by a merger
agreement that has been approved under the terms of our
Partnership Agreement;
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any amendment that, in the discretion of our general partner, is
necessary or advisable to reflect, account for and deal with
appropriately the formation by the Partnership of, or investment
by the Partnership in, any corporation, partnership, joint
venture, limited liability company or other entity, in
connection with the conduct of activities otherwise permitted by
our Partnership Agreement;
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a merger or conveyance effected in accordance with the
Partnership Agreement; and
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any other amendments substantially similar to any of the matters
described in the clauses above.
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In addition, the general partner may make amendments to the
Partnership Agreement without the approval of any limited
partner or assignee if those amendments, in the discretion of
our general partner:
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do not adversely affect the limited partners (including any
particular class of limited partners as compared to other
classes of limited partners) in any material respect;
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are necessary or advisable to satisfy any requirements,
conditions or guidelines contained in any opinion, directive,
order, ruling or regulation of any federal or state agency or
judicial authority or contained in any federal or state statute;
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are necessary or advisable to facilitate the trading of limited
partner interests or to comply with any rule, regulation,
guideline or requirement of any national securities exchange on
which the limited partner interests are or will be listed for
trading, compliance with any of which our general partner deems
to be in the best interests of us and our limited partners;
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are necessary or advisable in connection with action taken by
our general partner relating to splits or combinations of
limited partner interests under the provisions of our
Partnership Agreement; or
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are required to effect the intent expressed in this prospectus
or the intent of the provisions of our Partnership Agreement or
are otherwise contemplated by our Partnership Agreement.
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Opinion of Counsel and Limited Partner
Approval. Our general partner will not be
required to obtain an opinion of counsel that an amendment will
not result in a loss of limited liability to the limited
partners or result in our being treated as an entity for federal
income tax purposes if one of the amendments described above
under No Unitholder Approval should
occur. No other amendments to our Partnership Agreement will
become effective without the approval of holders of at least 90%
of the outstanding units unless we obtain an opinion of counsel
to the effect that the amendment will not affect the limited
liability under applicable law of any limited partner in our
Partnership.
Any amendment that would have a material adverse effect on the
rights or preferences of any type or class of outstanding units
in relation to other classes of units will require the approval
of at least a majority of the type or class of units so
affected. Any amendment that reduces the voting percentage
required to take any action is required to be approved by the
affirmative vote of limited partners whose aggregate outstanding
limited partner units constitute not less than the voting
requirement sought to be reduced.
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Merger,
Sale or Other Disposition of Assets
Our general partner is generally prohibited, without the prior
approval of the holders of a unit majority, from causing us to,
among other things, sell, exchange or otherwise dispose of all
or substantially all of our assets in a single transaction or a
series of related transactions, including by way of merger,
consolidation or other combination, or approving on our behalf
the sale, exchange or other disposition of all or substantially
all of the assets of our subsidiaries; provided that our general
partner may mortgage, pledge, hypothecate or grant a security
interest in all or substantially all of our assets without that
approval. Our general partner may also sell all or substantially
all of our assets under a foreclosure or other realization upon
the encumbrances above without that approval.
If the conditions specified in the Partnership Agreement are
satisfied, our general partner may merge our Partnership or any
of its subsidiaries into, or convey all of the
Partnerships assets to, another limited liability entity
which shall be newly formed and shall have no assets,
liabilities or operations at the time of such merger other than
those it receives from the Partnership or any of its
subsidiaries, if (i) the general partner has received an
opinion of counsel that the conversion, merger or conveyance
would not result in the loss of the limited liability of any
limited partner or Partnership subsidiary or cause the
Partnership or any subsidiary to be treated as an association
taxable as a corporation or otherwise to be taxed as an entity
for federal income tax purposes, (ii) the sole purpose of
such conversion, merger or conveyance is to effect a mere change
in the legal form of the Partnership into another limited
liability entity, and (iii) the governing instruments of
the new entity provide the limited partners and the general
partner with the same rights and obligations as are contained in
the Partnership Agreement. The limited partners are not entitled
to dissenters rights of appraisal under the Partnership
Agreement or applicable Delaware law in the event of a merger or
consolidation, a sale of all or substantially all of our assets
or any other transaction or event.
Termination
and Dissolution
We will continue as a limited partnership until terminated under
our Partnership Agreement. We will dissolve upon:
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the election of our general partner to dissolve us, if approved
by the holders of a unit majority;
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the sale, exchange or other disposition of all or substantially
all of the assets and properties of the Partnership and its
subsidiaries;
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the entry of a decree of judicial dissolution of our Partnership
pursuant to the provisions of the Delaware Act; or
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an event of withdrawal of our general partner, unless a
successor is elected and an opinion of counsel is received as
provided under the Partnership Agreement and such successor is
admitted to the Partnership pursuant to the terms thereof.
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Upon a dissolution under the last clause above, a unit majority
may also elect, within specific time limitations, to
reconstitute our Partnership and continue its business on the
same terms and conditions described in the Partnership Agreement
by forming a new limited partnership on terms identical to those
in the Partnership Agreement and having as general partner an
entity approved by a unit majority, subject to our receipt of an
opinion of counsel to the effect that:
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the action would not result in the loss of limited liability of
any limited partner; and
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neither the Partnership, the reconstituted limited partnership
nor any of our subsidiaries would be treated as an association
taxable as a corporation or otherwise be taxable as an entity
for federal income tax purposes upon the exercise of that right
to continue.
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Liquidation
and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continued
as a new limited partnership, the liquidator authorized to wind
up our affairs will, acting with all of the powers of our
general partner that the
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liquidator deems necessary or desirable in its judgment,
liquidate our assets and apply the proceeds of the liquidation
as provided in Cash Distribution Policy
Distributions of Cash upon Liquidation. The liquidator may
defer liquidation or distribution of our assets for a reasonable
period of time or distribute assets to partners in kind if it
determines that a sale would be impractical or would cause undue
loss to our partners.
Withdrawal
or Removal of the General Partner
The general partner may withdraw without limited partner
approval upon 90 days notice to the limited partners
if at the time notice is given at least 50% of the outstanding
units are owned beneficially or of record or are controlled by
one person and its affiliates (other than the general partner
and its affiliates). In addition, the Partnership Agreement
permits our general partner in some instances to sell or
otherwise transfer all of its general partner interests in our
Partnership without the approval of the limited partners. See
Transfer of General Partner Interest.
Upon notice of withdrawal of our general partner under any
circumstances, other than as a result of a transfer by our
general partner of all or a part of its general partner interest
in us, the holders of a unit majority, prior to the effective
date of such withdrawal, outstanding units may select a
successor to that withdrawing general partner. If a successor is
not elected, or is elected but an opinion of counsel regarding
limited liability and tax matters cannot be obtained, we will be
permanently dissolved, unless within 180 days after
dissolution following withdrawal, the holders of a unit
majority elect to reconstitute the Partnership and to appoint a
successor general partner. See Termination and
Dissolution.
Subject to the terms of the Partnership Agreement, Yorktown
unilaterally may remove our general partner and select a new
general partner to operate and carry on our business. Limited
partners other than Yorktown generally have no right to remove
our general partner under any circumstances. Our general partner
may not be removed unless we receive an opinion of counsel
regarding limited liability and tax matters.
Our Partnership Agreement also provides that if the general
partner withdraws under circumstances where such withdrawal does
not violate the Partnership Agreement or is removed by Yorktown,
the departing partner shall have the option, exercisable prior
to the effective date of the departure of such departing
partner, to require its successor to purchase its general
partner interest (or equivalent interest) in us and any of our
subsidiaries for an amount in cash equal to the fair market
value of such interest(s).
If our general partner withdraws under circumstances where such
withdrawal violates the Partnership Agreement, the successor
general partner, if any, shall have the option, exercisable
prior to the effective date of the departure of the departing
partner, to purchase the general partner interest(s), as
described above, of such departing general partner for a cash
payment equal to the fair market value of those interests.
In addition, we will be required to reimburse the departing
general partner for all amounts due to the departing general
partner, including, without limitation, all employee-related
liabilities, including severance liabilities, incurred for the
termination of any employees employed by the departing general
partner or its affiliates for the benefit of the Partnership or
any of its subsidiaries.
Transfer
of General Partner Interest
The general partner may transfer any or all of its general
partner interest, provided that (i) the transferee agrees
to assume the rights and duties of the general partner under the
Partnership Agreement and to be bound by the provisions of the
agreement, (ii) the Partnership receives an opinion of
counsel that such transfer would not result in the loss of
limited liability of any limited partner or cause the
Partnership to be treated as an association taxable as a
corporation or otherwise to be taxed as an entity for federal
income tax purposes (to the extent not already so treated or
taxed) and (iii) such transferee also agrees to purchase
all (or the appropriate portion thereof, as applicable) of the
Partnership or membership interest of the general partner as the
general partner or managing member, if any, of the Partnership
and any of its subsidiaries. In these circumstances, the
transferee generally will be admitted to the Partnership as the
general partner immediately prior to the transfer of the
Partnership interest.
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Transfer
of Ownership Interests in the General Partner
At any time, the owners of our general partner may sell or
transfer all or part of their ownership interests in our general
partner without the approval of the limited partners.
Limited
Call Right
If at any time our general partner, Yorktown and their
respective affiliates hold more than 80% of the total limited
partner interests of any class then outstanding, our general
partner shall have the right, which it may assign in whole or in
part to any of its affiliates or to the Partnership, to acquire
all, but not less than all, of the remaining limited partner
interests of the class held by persons other than the general
partner, Yorktown and their respective affiliates as of a record
date to be selected by our general partner, on at least 10 but
not more than 60 days notice. The purchase price in
the event of this purchase is the greater of:
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the highest price paid by our general partner or any of its
affiliates for any limited partner interest of the class
purchased during the
90-day
period preceding the date on which our general partner first
mails notice of its election to purchase those limited partner
interests; and
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the current market price as of the date three days before the
date the notice is mailed.
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As a result of our general partners right to purchase
outstanding limited partner interests, a holder of limited
partner interests may have his limited partner interests
purchased at an undesirable time or price. The tax consequences
to a limited partner of the exercise of this call right are the
same as a sale by that limited partner of his limited partner
interests in the market. See Material Tax
Consequences Disposition of Common Units.
Meetings;
Voting
Except as described below regarding a person or group owning 20%
or more of any class of units then outstanding, limited partners
or assignees who are record holders of limited partner interests
on the record date will be entitled to notice of, and to vote
at, meetings of limited partners and to act with respect to
matters as to which the holders of limited partner interests
have the right to vote or to act. Limited partner interests that
are owned by an assignee who is a record holder, but who has not
yet been admitted as a limited partner, shall be voted by our
general partner at the written direction of the record holder.
Absent direction of this kind, the limited partner interests
will not be voted, except that, in the case of limited partner
interests held by our general partner on behalf of non-citizen
assignees, our general partner shall distribute the votes on
those limited partner interests in the same ratios as the votes
of limited partners on other limited partner interests are cast.
If authorized by the general partner, any action that may be
taken at a meeting of the limited partners may be taken without
a meeting if an approval in writing setting forth the action so
taken is signed by limited partners owning not less than the
minimum percentage of the outstanding units (including units
deemed owned by the general partner) that would be necessary to
authorize or take such action at a meeting at which all the
limited partners were present and voted. Meetings of the
limited partners may be called by our general partner or by
limited partners owning at least 20% of the outstanding units of
the class for which a meeting is proposed. Limited partners may
vote either in person or by proxy at meetings. The holders of a
majority of the outstanding units of the class or classes for
which a meeting has been called represented in person or by
proxy shall constitute a quorum unless any action by the limited
partners requires approval by holders of a greater percentage of
the limited partner interests, in which case the quorum shall be
the greater percentage.
Each record holder of a limited partner interest has a vote
according to his percentage interest in the Partnership,
although additional limited partner interests having special
voting rights could be issued. See Issuance of
Additional Securities. If at any time any person or group
other than our general partner, Yorktown and their respective
affiliates acquires beneficial ownership of 20% or more of any
outstanding Partnership securities of any class then
outstanding, all Partnership securities owned by such person or
group shall not be voted on any matter and shall not for most
purposes, including when sending notices of a meeting,
calculating required votes, or determining the presence of a
quorum, be considered to be outstanding.
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Limited partner interests held in nominee or street name
accounts will be voted by the broker or other nominee in
accordance with the instruction of the beneficial owner unless
the arrangement between the beneficial owner and its nominee
provides otherwise.
Any notice, demand, request, report or proxy material required
or permitted to be given or made to record holders of limited
partner interests under our Partnership Agreement will be
delivered to the record holder by the Partnership or by the
transfer agent.
Status as
Limited Partner or Assignee
Except as described above under Limited
Liability, the limited partner interests will be fully
paid, and limited partners will not be required to make
additional contributions.
An assignee of a limited partner interest, after executing and
delivering a transfer application, but pending its admission as
a substituted limited partner, is entitled to an interest
equivalent to that of a limited partner with respect to
allocations and distributions from the Partnership, including
liquidating distributions. The general partner will vote and
exercise other powers attributable to limited partner interests
owned by an assignee who has not become a substituted limited
partner at the written direction of the assignee. See
Meetings; Voting. Transferees who do not
execute and deliver a transfer application will be treated
neither as assignees nor as record holders of limited partner
interests, and will not receive cash distributions, federal
income tax allocations or reports furnished to holders of
limited partner interests. See Description of our Common
Units Transfer of Common Units.
Non-Citizen
Assignees; Redemption
If we or any of our subsidiaries are or become subject to
federal, state or local laws or regulations that, in the
reasonable determination of our general partner, create a
substantial risk of cancellation or forfeiture of any property
in which we have an interest based on the nationality,
citizenship or other related status of any limited partner or
assignee, the general partner may request that the applicable
limited partner or assignee furnish information about his
nationality, citizenship or related status. If such limited
partner or assignee fails to furnish information about his
nationality, citizenship or other related status within
30 days after a request for the information or our general
partner determines after receipt of the information and with the
advice of counsel that the limited partner or assignee is not an
eligible citizen, the limited partner or assignee may be treated
as a non-citizen assignee. In addition to other limitations on
the rights of an assignee who is not a substituted limited
partner, a non-citizen assignee does not have the right to
direct the voting of his limited partner interests and may not
receive distributions in kind upon our liquidation. In the event
of a failure to furnish information or a determination of the
general partner based on furnished information as described
above, the Partnership may redeem, upon 30 days
advance notice, the limited partner interests held by the
limited partner or assignee at their current market price.
Indemnification
Under our Partnership Agreement, in most circumstances, the
Partnership will indemnify the following persons, to the fullest
extent permitted by law, from and against all losses, claims,
damages or similar events:
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our general partner or any person who is or was an affiliate of
our general partner;
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Yorktown and any person who is or was a member, officer
director, employee, agent or trustee of Yorktown Partners LLC;
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any departing general partner or any person who is or was an
affiliate of any departing general partner;
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any person who is or was a member, partner, officer, director,
employee, agent or trustee of any of our subsidiaries, our
general partner or any departing general partner or any
affiliate of the Partnership or any of our subsidiaries, our
general partner, or any departing general partner; or
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any person who is or was serving at the request of our general
partner or any departing general partner or any affiliate of our
general partner or any departing general partner as an officer,
director, employee, member, partner, agent or trustee of another
person.
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Any indemnification under these provisions will only be out of
the Partnerships assets. Unless it otherwise agrees in its
sole discretion, our general partner will not be personally
liable for, or have any obligation to contribute or loan funds
or assets to us to enable the Partnership to effectuate
indemnification. The Partnership may purchase insurance, on
behalf of the general partner, its affiliates and such other
persons as the general partner may determine, against any
liability that may be asserted against or expense that may be
incurred by such person in connection with the
Partnerships activities or such persons activities
on behalf of the Partnership, regardless of whether the
Partnership would have the power to indemnify such person
against such liability under the provisions of the Partnership
Agreement.
Reimbursement
of Expenses
Our Partnership Agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on behalf of the Partnership and all other
necessary appropriate expenses allocable to us or otherwise
reasonably incurred by our general partner in connection with
operating the Partnerships business. These expenses
include salary, bonus, incentive compensation and other amounts
paid to persons who perform services for us or on our behalf and
expenses allocated our general partner by its affiliates. The
general partner is entitled to determine the expenses that are
allocable to us in any reasonable manner determined by our
general partner in its sole discretion.
Books and
Records
Our general partner is required to keep appropriate books with
respect to the Partnerships business at our principal
office. The books of the Partnership shall be maintained, for
financial reporting purposes, on an accrual basis in accordance
with U.S. GAAP. For tax and fiscal reporting purposes, our
fiscal year is the calendar year. As soon as practicable, but in
no event later than 120 days after the close of each fiscal
year of the Partnership, the general partner shall cause to be
mailed or made available to every record holder of a limited
partner interest an annual report containing audited financial
statements and a report on those financial statements by our
independent public accountants. Except for our fourth quarter,
we will also furnish or make available summary financial
information within 90 days after the close of each quarter.
We will furnish each record holder of a limited partner interest
with information reasonably required for tax reporting purposes
within 90 days after the close of each calendar year. The
classification, realization and recognition of income, gain,
losses and deductions and other items shall be on the accrual
method of accounting for federal income tax purposes.
Right to
Inspect Our Books and Records
Our Partnership Agreement provides that a limited partner can,
for a purpose reasonably related to his interest as a limited
partner, upon reasonable written demand and at his own expense,
have furnished to him:
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true and full information regarding the status of the business
and financial condition of the Partnership;
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promptly after they become available, copies of the
Partnerships federal, state and local income tax returns
for each year;
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a current list of the name and last known address of each
partner;
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copies of our Partnership Agreement, the certificate of limited
partnership of the Partnership, related amendments and powers of
attorney under which they have been executed;
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true and full information regarding the amount of cash and a
description and statement of the net agreed value of any other
capital contribution by each partner and which each partner has
agreed to contribute in the future, and the date on which each
became a partner; and
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any other information regarding our affairs as is just and
reasonable.
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Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith
is not in our best interests, could damage us or our
subsidiaries, or which we or our subsidiaries are required by
law or by agreements with third parties to keep confidential.
Registration
Rights
Under our Partnership Agreement, we have agreed to register for
sale under the Securities Act and applicable state securities
laws any Partnership securities proposed to be sold by our
general partner, Yorktown or any of their respective affiliates
if an exemption from the registration requirements is not
otherwise available. These registration rights continue for two
years following any withdrawal or removal of our general
partner. We have also agreed to include any Partnership
securities held by our general partner, Yorktown or their
respective affiliates in any registration statement that we file
to offer Partnership securities for cash, except an offering
relating solely to an employee benefit plan, for the same
period. We are obligated to pay all expenses incidental to the
registration and offering (excluding underwriting discounts and
commissions) without reimbursement by our general partner,
Yorktown or their respective affiliates.
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UNITS
ELIGIBLE FOR FUTURE SALE
Prior to this offering, there has been no public market for our
common units, and we cannot predict what effect, if any, market
sales of our common units or the availability of common units
for sale will have on the market price of our common units.
Future sales of substantial amounts of our common units in the
public market, or the perception that substantial sales may
occur, could materially and adversely affect the prevailing
market price of our common units 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 12,461,977 common
units and 38,023 general partner units outstanding. Of these
units, the common units being sold
in this offering will be freely tradable without restriction
under the Securities Act, except for any such units 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 units will be subject to the volume
limitations and other restrictions of Rule 144 described
below. The remaining 11,461,977 common units held by our
existing unitholders 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 common units will be available for sale in the public
market as follows:
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11,461,977 units 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; and
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Certain common units purchased by our affiliates in this
offering pursuant to the directed share program, if any, will be
available for sale at various times 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
of our common units 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 our
restricted common units for at least six months would be
entitled to sell within any three-month period any number of
such units that does not exceed the greater of:
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1% of the number of common units then outstanding, which will
equal approximately 124,620 units immediately after consummation
of this offering; or
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the average weekly trading volume of our common units 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 common units that are not
restricted securities, such as units 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
restricted common units for at least six months would be
entitled to sell those units 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 restricted
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common units for at least one year will not be subject to any
restrictions under Rule 144 with respect to such units,
regardless of how long we have been a reporting company.
We are unable to estimate the number of units that will be sold
under Rule 144 since this will depend on the market price
for our common units, the personal circumstances of the
unitholder and other factors.
Issuance
of Additional Interests
Our Partnership Agreement provides that we may issue an
unlimited number of limited partner interests of any type
without a vote of the unitholders at any time. Any issuance of
additional common units or other equity securities would result
in a corresponding decrease in the proportionate ownership
interest in us represented by, and could adversely affect the
cash distributions to and market price of, common units then
outstanding. See The Partnership Agreement
Issuance of Additional Interests.
Registration
Rights
Under our Partnership Agreement, we have agreed to register for
sale under the Securities Act and applicable state securities
laws any common units or other Partnership securities proposed
to be sold by our general partner or any of its affiliates if an
exemption from the registration requirements is not otherwise
available. These registration rights continue for two years
following any withdrawal or removal of our general partner. We
have also agreed to include any Partnership securities held by
our general partner or its affiliates in any registration
statement that we file to offer Partnership securities for cash,
except an offering relating solely to an employee benefit plan,
for the same period. We are obligated to pay all expenses
incidental to the registration, excluding underwriting discounts
and commissions.
Lock-Up
Agreements
We, our general partners managers, executive officers and
unitholders, and Armstrong Energys officers and directors
and holders of all of our common units have agreed with the
underwriters not to offer, pledge, sell or contract to sell or
otherwise dispose of or hedge any common units or securities
convertible into or exchangeable for common units, subject to
specified limited exceptions and extensions described elsewhere
in this prospectus, during the period continuing through the
date that is 180 days, or 30 days in the case of
unitholders other than managers, executive officers, Armstrong
Energy, Inc. or affiliates of Yorktown (in each case, subject to
extension) after the date of this prospectus, except with the
prior written consent of Raymond James & Associates, Inc.
and FBR Capital Markets & Co., on behalf of the
underwriters. See Underwriting. Raymond James
& Associates, Inc. and FBR Capital Markets & Co. may
release any of the securities subject to these
lock-up
agreements at any time without notice.
Any participants in the directed share program will be subject
to a 180-day
lock-up with
respect to any common units sold to them pursuant to the
program. This
lock-up will
have similar terms and conditions as described above. Any common
units sold in the directed share program to our directors or
officers shall be subject to the
lock-up
agreement described above.
Immediately following the consummation of this offering,
unitholders subject to
lock-up
agreements will hold 11,461,977 common units, representing about
92.0% of our outstanding common units after giving effect to
this offering.
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MATERIAL
TAX CONSEQUENCES
This section is a summary of the material U.S. federal
income tax consequences that may be relevant to prospective
unitholders who are individual citizens or residents of the
U.S. and, unless otherwise noted in the following
discussion, is the opinion of Armstrong Teasdale LLP, special
counsel to our general partner and us, insofar as it relates to
United States federal income tax matters. This section is based
upon current provisions of the Internal Revenue Code of 1986, as
amended (the Internal Revenue Code), existing and
proposed Treasury regulations promulgated under the Internal
Revenue Code (the Treasury Regulations), and current
administrative rulings and court decisions, all of which are
subject to change. Later changes in these authorities may cause
the tax consequences to vary substantially from the consequences
described below. Unless the context otherwise requires,
references in this section to us or we
are references to Armstrong Resource Partners, L.P. and our
subsidiaries.
The following discussion does not address all United States
federal income tax matters affecting us or our unitholders.
Moreover, the discussion focuses on unitholders who are
individual citizens or residents of the United States, whose
functional currency is the U.S. dollar and who hold common
units as a capital asset (generally, property that is held as an
investment). This discussion has only limited application to
corporations, partnerships (and entities treated as partnerships
for U.S. federal income tax purposes), estates, trusts,
nonresident aliens, or other unitholders subject to specialized
tax treatment, such as tax-exempt institutions, foreign persons,
individual retirement accounts, employee benefit plans, real
estate investment trusts (REITs), or mutual funds.
In addition, the discussion only comments, to a limited extent,
on state, local, and foreign tax consequences. Accordingly, we
encourage each prospective unitholder to consult, and depend on,
its own tax advisor in analyzing the United States federal,
state, local, and foreign tax consequences particular to it of
the ownership or disposition of common units.
No ruling has been or will be requested from the Internal
Revenue Service (IRS) regarding any matter affecting
us or prospective unitholders. Instead, we will rely on opinions
and advice of Armstrong Teasdale LLP. Unlike a ruling, an
opinion of counsel represents only that counsels best
legal judgment and does not bind the IRS or the courts.
Accordingly, the opinions and statements made herein may not be
sustained by a court if contested by the IRS. Any contest of
this sort with the IRS may materially and adversely impact the
market for the common units and the prices at which common units
trade. In addition, the costs of any contest with the IRS,
principally legal, accounting, and related fees, will result in
a reduction in cash available for distribution to our
unitholders and our general partner and thus will be borne
indirectly by our unitholders and our general partner.
Furthermore, the tax treatment of us, or of an investment in us,
may be significantly modified by future legislative or
administrative changes or court decisions. Any modifications may
or may not be retroactively applied.
All statements as to matters of United States federal income tax
law and legal conclusions with respect thereto, but not as to
factual matters, contained in this section, unless otherwise
noted, are the opinion of Armstrong Teasdale LLP and are based
on the accuracy of the representations made by us.
For the reasons described below, Armstrong Teasdale LLP has not
rendered an opinion with respect to the following specific
United States federal income tax issues: (i) the treatment
of a unitholder whose common units are loaned to a short seller
to cover a short sale of common units (see Tax
Consequences of Common Unit Ownership Treatment of
Short Sales); (ii) whether our monthly convention for
allocating taxable income and losses is permitted by existing
Treasury Regulations (see Disposition of Common
Units Allocations Between Transferors and
Transferees); and (iii) whether our method for
depreciating Section 743 adjustments is sustainable in
certain cases (see Tax Consequences of Common Unit
Ownership Section 754 Election and
Disposition of Common
Units Uniformity of Common Units).
Partnership
Status
A partnership is not a taxable entity and incurs no United
States federal income tax liability. Instead, each partner of a
partnership is required to take into account its share of items
of income, gain, loss, and deduction of the partnership in
computing its United States federal income tax liability,
regardless of whether cash distributions are made to it by the
partnership. Distributions by a partnership to a partner are
generally not
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taxable to the partnership or the partner unless the amount of
cash distributed to the partner is in excess of the
partners adjusted basis in its partnership interest.
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, if 90% or more of a partnerships
gross income for every taxable year it is publicly traded
consists of qualifying income, the partnership may
continue to be treated as a partnership for United States
federal income tax purposes (the Qualifying Income
Exception). Qualifying income includes income and gains
derived from the mining, transportation, and marketing of
minerals and natural resources, such as coal and limestone.
Other types of qualifying income include interest (other than
from a financial business), dividends, gains from the sale of
real property, and gains from the sale or other disposition of
capital assets held for the production of income that otherwise
constitutes qualifying income. We estimate that our gross income
which is not qualifying income will be less than 5% of our total
gross income for calendar years 2012 to 2015. Based upon and
subject to this estimate, the factual representations made by us
and our general partner and a review of the applicable legal
authorities, Armstrong Teasdale LLP is of the opinion that at
least 90% of our gross income will constitute qualifying income
beginning in 2012. The portion of our income that is qualifying
income may change from time to time.
Armstrong Teasdale LLP is of the opinion that we will be treated
as a partnership for United States federal income tax purposes
during 2012. In rendering its opinion, Armstrong Teasdale LLP
has relied on factual representations made by us and our general
partner. The representations made by us and our general partner
upon which Armstrong Teasdale LLP has relied include, without
limitation:
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Neither we nor any of our operating companies has elected or
will elect to be treated as a corporation; and
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For each taxable year, more than 90% of our gross income will be
income that Armstrong Teasdale LLP has opined or will opine is
qualifying income within the meaning of
Section 7704(d) of the Internal Revenue Code.
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We believe that these representations are true and will be true
in the future.
If we fail to meet the Qualifying Income Exception, other than a
failure that is determined by the IRS to be inadvertent and that
is cured within a reasonable time after discovery (in which case
the IRS may also require us to make adjustments with respect to
our unitholders or pay other amounts), we will be treated as if
we had transferred all of our assets, subject to liabilities, to
a newly formed corporation, on the first day of the year in
which we fail to meet the Qualifying Income Exception, in return
for stock in that corporation, and then distributed that stock
to the unitholders in liquidation of their interests in us. This
deemed contribution and liquidation should be tax-free to our
unitholders and us so long as we, at that time, do not have
liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for United
States federal income tax purposes.
If we were treated as a corporation in any taxable year, either
as a result of a failure to meet the Qualifying Income Exception
or otherwise, our items of income, gain, loss, and deduction
would be reflected only on our tax return rather than being
passed through to the unitholders, and our net income would be
taxed to us at corporate rates. In addition, any distribution
made to a unitholder would be treated as taxable dividend
income, to the extent of our current or accumulated earnings and
profits, and, in excess of earnings and profits, a nontaxable
return of capital, to the extent of the unitholders tax
basis in its common units, or taxable capital gain, after the
unitholders tax basis in its common units is reduced to
zero. Accordingly, taxation as a corporation would result in a
material reduction in a unitholders cash flow and
after-tax return and thus would likely result in a substantial
reduction of the value of the common units.
The discussion below is based on Armstrong Teasdale LLPs
opinion that we will be classified as a partnership for United
States federal income tax purposes.
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Limited
Partner Status
Unitholders who have become limited partners of Armstrong
Resource Partners, L.P. will be treated as partners of Armstrong
Resource Partners, L.P. for United States federal income tax
purposes. Also:
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assignees who have executed and delivered transfer applications
and are awaiting admission as limited partners; and
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unitholders whose common units are held in street name or by a
nominee and who have the right to direct the nominee in the
exercise of all substantive rights attendant to the ownership of
their common units will be treated as partners of Armstrong
Resource Partners, L.P. for United States federal income tax
purposes.
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As there is no direct or indirect controlling authority
addressing assignees of common units who are entitled to execute
and deliver transfer applications and thereby become entitled to
direct the exercise of attendant rights, but who fail to execute
and deliver transfer applications, Armstrong Teasdales
opinion does not extend to these persons. Furthermore, a
purchaser or other transferee of common units who does not
execute and deliver a transfer application may not receive some
United States federal income tax information or reports
furnished to record unitholders unless the common units are held
in a nominee or street name account and the nominee or broker
has executed and delivered a transfer application for those
common units.
A beneficial owner of common units whose common units have been
transferred to a short seller to complete a short sale would
appear to lose its status as a partner with respect to those
common units for United States federal income tax purposes. See
Tax Consequences of Common Unit Ownership
Treatment of Short Sales.
Income, gain, deductions, or losses would not appear to be
reportable by a unitholder who is not a partner for United
States federal income tax purposes, and any cash distributions
received by a unitholder who is not a partner for United States
federal income tax purposes would therefore appear to be fully
taxable as ordinary income. These holders are urged to consult
their own tax advisors with respect to their tax consequences of
holding our common units.
Tax
Consequences of Common Unit Ownership
Flow-Through
of Taxable Income
Subject to the discussion below under
Entity-Level Collections, we do not pay any
United States federal income tax. Instead, each unitholder will
be required to report on its income tax return its share of our
income, gains, losses, and deductions without regard to whether
we make cash distributions to such unitholder. Consequently, we
may allocate income to a unitholder even if it has not received
a cash distribution. Each unitholder will be required to include
in income its allocable share of our income, gains, losses, and
deductions for our taxable year ending with or within its
taxable year. Our taxable year ends on December 31.
Treatment
of Distributions
Distributions by us to a unitholder generally will not be
taxable to the unitholder for United States federal income tax
purposes unless the amount of such distributions made in cash or
marketable securities exceeds the unitholders tax basis in
its common units immediately before the distribution. Our cash
distributions in excess of a unitholders tax basis
generally will be considered to be gain from the sale or
exchange of the common units, taxable in accordance with the
rules described under Disposition of Common Units
below. Any reduction in a unitholders share of our
liabilities for which no partner, including our general partner,
bears the economic risk of loss, known as nonrecourse
liabilities, will be treated as a distribution of cash to
that unitholder. To the extent our distributions cause a
unitholders at risk amount to be less than
zero at the end of any taxable year, it must recapture any such
losses deducted in previous years. See Limitations on
Deductibility of Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
the unitholders share of our nonrecourse liabilities and
thus will result in a corresponding
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deemed distribution of cash. See Disposition of Common
Units Recognition of Gain or Loss. This deemed
distribution may result in a non-pro rata distribution. A
non-pro rata distribution of money or property may result in
ordinary income to a unitholder, regardless of its tax basis in
its common units, if the distribution reduces the
unitholders share of our unrealized
receivables, which includes depreciation recapture,
depletion recapture,
and/or
substantially appreciated inventory items, both as
defined in Section 751 of the Internal Revenue Code, and
collectively, Section 751 Assets. To the extent
of such reduction, the unitholder will be treated as having been
distributed its proportionate share of the Section 751
Assets and having exchanged those assets with us in return for
the non-pro rata portion of the distribution made to the
unitholder. This latter deemed exchange generally will result in
the unitholders realization of ordinary income in an
amount equal to the excess of (1) the non-pro rata portion
of that distribution over (2) the unitholders tax
basis (generally zero) in the Section 751 Assets deemed
relinquished in the exchange.
Basis
of Common Units
A unitholders initial tax basis for its common units will
be the amount it paid for the common units plus its share of our
nonrecourse liabilities. That basis will be increased by its
share of our income and by any increases in its share of our
nonrecourse liabilities. That basis will be decreased, but not
below zero, by distributions from us, by the unitholders
share of our losses, by any decreases in its share of our
nonrecourse liabilities, and by its share of our expenditures
that are not deductible in computing taxable income and are not
required to be capitalized. A unitholder will have no share of
our debt that is recourse to our general partner, but will have
a share, generally based on its share of profits, of our
nonrecourse liabilities. See Disposition of Common
Units Recognition of Gain or Loss.
Limitations
on Deductibility of Losses
The deduction by a unitholder of its share of our losses will be
limited to the tax basis in its common units and, in the case of
an individual unitholder or a corporate unitholder, if more than
50% of the value of the corporate unitholders stock is
owned directly or indirectly by five or fewer individuals or
some tax-exempt organizations, to the amount for which the
unitholder is considered to be at risk with respect
to our activities, if that is less than the unitholders
tax basis. A unitholder subject to these limitations must
recapture losses deducted in previous years to the extent that
distributions cause its at risk amount to be less than zero at
the end of any taxable year. Losses disallowed to a unitholder
or recaptured as a result of these limitations will carry
forward and will be allowable as a deduction to the extent that
its at risk amount is subsequently increased, so long as such
losses do not exceed such unitholders tax basis in the
unitholders common units. Upon the taxable disposition of
a common unit, any gain recognized by a unitholder can be offset
by losses that were previously suspended by the at risk
limitation but may not be offset by losses suspended by the
basis limitation. Any excess loss above that gain previously
suspended by the at risk or basis limitations is no longer
utilizable.
In general, a unitholder will be at risk to the extent of the
tax basis of its common units, excluding any portion of that
basis attributable to its share of our nonrecourse liabilities,
reduced by (1) any portion of that basis representing
amounts otherwise protected against loss because of a guarantee,
stop loss agreement, or other similar arrangement and
(2) any amount of money the unitholder borrows to acquire
or hold its common units, if the lender of those borrowed funds
owns an interest in us, is related to another unitholder or can
look only to the common units for repayment. A unitholders
at risk amount will increase or decrease as the tax basis of the
unitholders common units increases or decreases, other
than tax basis increases or decreases attributable to increases
or decreases in the unitholders share of our nonrecourse
liabilities.
In addition to the basis and at risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts, and some closely-held
corporations and personal service corporations can deduct losses
from passive activities, which are generally trade or business
activities in which the taxpayer does not materially
participate, only to the extent of the taxpayers income
from those passive activities. The passive loss limitations are
applied separately with respect to each publicly traded
partnership. Consequently, any passive losses we generate will
only be available to offset our passive income generated in the
future and will not be available to offset income from other
passive activities or investments, including our
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investments or investments in other publicly traded
partnerships, or salary or active business income. Passive
losses that are not deductible because they exceed a
unitholders share of passive income we generate may be
deducted in full when the unitholder disposes of its entire
investment in us in a fully taxable transaction with an
unrelated party. The passive activity loss rules are applied
after other applicable limitations on deductions, including the
at risk rules and the basis limitation.
A unitholders share of our net passive income may be
offset by any of our suspended passive losses, but it may not be
offset by any other current or carryover losses from other
passive activities, including those attributable to other
publicly traded partnerships.
Limitations
on Interest Deductions
The deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
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interest on indebtedness properly allocable to property held for
investment;
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our interest expense attributed to portfolio income; and
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the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
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The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a common
unit. Net investment income includes gross income from property
held for investment and amounts treated as portfolio income
under the passive loss rules, less deductible expenses, other
than interest, directly connected with the production of
investment income, but generally does not include gains
attributable to the disposition of property held for investment
or qualified dividend income. The IRS has indicated that net
passive income earned by a publicly traded partnership will be
treated as investment income to its unitholders. In addition,
the unitholders share of our portfolio income will be
treated as investment income.
Entity-Level Collections
If we are required or elect under applicable law to pay any
United States federal, state, local, or foreign income tax on
behalf of any unitholder or our general partner or any former
unitholder, we are authorized to pay those taxes from our funds.
That payment, if made, will be treated as a distribution of cash
to the unitholder on whose behalf the payment was made. If the
payment is made on behalf of a person whose identity cannot be
determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our Partnership Agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of common
units and to adjust later distributions, so that after giving
effect to these distributions, the priority and characterization
of distributions otherwise applicable under our Partnership
Agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
Allocation
of Income, Gain, Loss, and Deduction
In general, if we have a net profit, our items of income, gain,
loss, and deduction will be allocated among our general partner
and the unitholders in accordance with their percentage
interests in us. If we have a net loss for the entire year, that
loss will be allocated first to our general partner and the
unitholders in accordance with their percentage interests in us
to the extent of their positive capital accounts and, second, to
our general partner.
Specified items of our income, gain, loss, and deduction will be
allocated to account for (1) any difference between the tax
basis and fair market value of our assets at the time of an
offering and (2) any difference between the tax basis and
fair market value of any property contributed to us by the
general partner that exists at the time of such contribution,
together, referred to in this discussion as the
Contributed
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Property. The effect of these allocations, referred to as
Section 704(c) Allocations, to a unitholder purchasing
common units from us in this offering will be essentially the
same as if the tax bases of our assets were equal to their fair
market values at the time of this offering. In the event we
issue additional common units or engage in certain other
transactions in the future, reverse Section 704(c)
Allocations, similar to the Section 704(c)
Allocations described above, will be made to the general partner
and our other unitholders immediately prior to such issuance or
other transactions to account for the difference between the
book basis for purposes of maintaining capital
accounts and the fair market value of all property held by us at
the time of such issuance or future transaction. In addition,
items of recapture income will be allocated to the extent
possible to the unitholder who was allocated the deduction
giving rise to the treatment of that gain as recapture income in
order to minimize the recognition of ordinary income by some
unitholders. Finally, although we do not expect that our
operations will result in the creation of negative capital
accounts, if negative capital accounts nevertheless result,
items of our income and gain will be allocated in an amount and
manner sufficient to eliminate the negative balance as quickly
as possible.
An allocation of items of our income, gain, loss, or deduction,
other than an allocation required by the Internal Revenue Code
to eliminate the difference between a partners
book capital account, credited with the fair market
value of Contributed Property, and tax capital
account, credited with the tax basis of Contributed Property,
referred to in this discussion as the Book-Tax
Disparity, will generally be given effect for United
States federal income tax purposes in determining a
partners share of an item of income, gain, loss, or
deduction only if the allocation has substantial economic
effect. In any other case, a partners share of an
item will be determined on the basis of the partners
interest in us, which will be determined by taking into account
all the facts and circumstances, including:
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the partners relative contributions to us;
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the interests of all the partners in profits and losses;
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the interest of all the partners in cash flow; and
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the rights of all the partners to distributions of capital upon
liquidation.
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Armstrong Teasdale LLP is of the opinion that, with the
exception of the issues described in Tax Consequences of
Common Unit Ownership Section 754
Election and Disposition of Common Units
Allocations Between Transferors and Transferees,
allocations under our Partnership Agreement will be given effect
for United States federal income tax purposes in determining a
partners share of an item of income, gain, loss, or
deduction.
Treatment
of Short Sales
A unitholder whose common units are loaned to a short
seller to cover a short sale of common units may be
considered as having disposed of those common units. If so, the
unitholder would no longer be treated for tax purposes as a
partner with respect to those common units during the period of
the loan and may recognize gain or loss from the disposition. As
a result, during this period:
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any of our income, gain, loss, or deduction with respect to
those common units would not be reportable by the unitholder;
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any cash distributions received by the unitholder as to those
common units would be fully taxable; and
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all of these distributions may be subject to tax as ordinary
income.
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Armstrong Teasdale LLP has not rendered an opinion regarding the
treatment of a unitholder where common units are loaned to a
short seller to cover a short sale of common units; therefore,
unitholders desiring to assure their status as partners and
avoid the risk of gain recognition from a loan to a short seller
are urged to modify any applicable brokerage account agreements
to prohibit their brokers from loaning their common units. The
IRS has announced that it is actively studying issues relating
to the tax treatment of short sales of partnership interests.
Please also read Disposition of Common Units
Recognition of Gain or Loss.
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Alternative
Minimum Tax
Each unitholder will be required to take into account its
distributive share of any items of our income, gain, loss, or
deduction for purposes of the alternative minimum tax. The
current minimum tax rate for noncorporate taxpayers is 26% on
the first $175,000 of alternative minimum taxable income in
excess of the exemption amount and 28% on any additional
alternative minimum taxable income. Prospective unitholders are
urged to consult with their tax advisors as to the impact of an
investment in common units on their liability for the
alternative minimum tax.
Tax
Rates
Under current law, the highest marginal United States federal
income tax rate applicable to ordinary income of individuals is
35% and the highest marginal United States federal income tax
rate applicable to long-term capital gains (generally, gains
from the sale or exchange of certain investment assets held for
more than one year) of individuals is 15%. However, absent new
legislation extending the current rates, beginning
January 1, 2013, the highest marginal United States federal
income tax rate applicable to ordinary income and long-term
capital gains of individuals will increase to 39.6% and 20%,
respectively. Moreover, these rates are subject to change by new
legislation at any time.
Recently enacted legislation will impose a 3.8% Medicare tax on
net investment income earned by certain individuals, estates,
and trusts is scheduled to apply for taxable years beginning
after December 31, 2012. For these purposes, net investment
income generally includes a unitholders allocable share of
our income and gain realized by a unitholder from a sale of
common units. In the case of an individual, the tax will be
imposed on the lesser of (1) the unitholders net
investment income or (2) the amount by which the
unitholders modified adjusted gross income exceeds
$250,000 (if the unitholder is married and filing jointly or a
surviving spouse), $125,000 (if the unitholder is married and
filing separately), or $200,000 (in any other case). In the case
of an estate or trust, the tax will be imposed on the lesser of
(1) undistributed net investment income, or (2) the
excess adjusted gross income over the dollar amount at which the
highest income tax bracket applicable to an estate or trust
begins.
Section 754
Election
We will make the election permitted by Section 754 of the
Internal Revenue Code. That election is irrevocable without the
consent of the IRS, unless there is a constructive termination
of the partnership. See Disposition of Common
Units Constructive Termination. The election
will generally permit us to adjust a common unit
purchasers tax basis in our assets (inside
basis) under Section 743(b) of the Internal Revenue
Code to reflect the unitholders purchase price. This
election does not apply to a person who purchases common units
directly from us. The Section 743(b) adjustment belongs to
the purchaser and not to other unitholders. For purposes of this
discussion, a unitholders inside basis in our assets will
be considered to have two components: (1) its share of our
tax basis in our assets (common basis) and
(2) its Section 743(b) adjustment to that basis.
Where the remedial allocation method is adopted (which we have
adopted as to our properties), the Treasury Regulations under
Section 743 of the Internal Revenue Code require a portion
of the Section 743(b) adjustment that is attributable to
recovery property subject to depreciation under Section 168
of the Internal Revenue Code whose book basis is in excess of
its tax basis to be depreciated over the remaining cost recovery
period for the propertys unamortized Book-Tax Disparity.
Under Treasury
Regulation Section 1.167(c)-1(a)(6),
a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Internal
Revenue Code, rather than cost recovery deductions under
Section 168, is generally required to be depreciated using
either the straight-line method or the 150% declining balance
method. Under our Partnership Agreement, our general partner is
authorized to take a position to preserve the uniformity of
common units even if that position is not consistent with these
and any other Treasury Regulations. See Disposition of
Common Units Uniformity of Common Units.
Although Armstrong Teasdale LLP is unable to opine as to the
validity of this approach because there is no direct or indirect
controlling authority on this issue, we intend to depreciate the
portion of a Section 743(b)
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adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as
non-amortizable
to the extent attributable to property which is not amortizable.
This method is consistent with the methods employed by other
publicly traded partnerships but is arguably inconsistent with
Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets, and Treasury
Regulation Section 1.197-2(g)(3).
To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may take a depreciation or amortization position under which
all purchasers acquiring common units in the same month would
receive depreciation or amortization, whether attributable to
common basis or a Section 743(b) adjustment, based upon the
same applicable rate as if they had purchased a direct interest
in our assets. This kind of aggregate approach may result in
lower annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. See
Disposition of Common Units Uniformity of
Common Units. A unitholders tax basis for its common
units is reduced by its share of our deductions (whether or not
such deductions were claimed on an individuals income tax
return) so that any position we take that understates deductions
will overstate the unitholders basis in its common units,
which may cause the unitholder to understate gain or overstate
loss on any sale of such common units. See Disposition of
Common Units Recognition of Gain or Loss. The
IRS may challenge our position with respect to depreciating or
amortizing the Section 743(b) adjustment we take to
preserve the uniformity of the common units. If such a challenge
were sustained, the gain from the sale of common units might be
increased without the benefit of additional deductions.
A Section 754 election is advantageous if the
transferees tax basis in its common units is higher than
the common units share of the aggregate tax basis of our
assets immediately prior to the transfer. In that case, as a
result of the election, the transferee would have, among other
items, a greater amount of depreciation and depletion deductions
and its share of any gain or loss on a sale of our assets would
be less. Conversely, a Section 754 election is
disadvantageous if the transferees tax basis in its common
units is lower than those common units share of the
aggregate tax basis of our assets immediately prior to the
transfer. Thus, the fair market value of the common units may be
affected either favorably or unfavorably by the election. A
basis adjustment is required regardless of whether a
Section 754 election is made in the case of a transfer of
an interest in us if we have a substantial built-in loss
immediately after the transfer or if we distribute property and
have a substantial basis reduction. Generally, a built-in loss
or a basis reduction is substantial if it exceeds $250,000.
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of our assets and other matters. For example, the
allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment allocated by us to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally
non-amortizable
or amortizable over a longer period of time or under a less
accelerated method than our tangible assets. We cannot assure
you that the determinations we make will not be successfully
challenged by the IRS and that the deductions resulting from
them will not be reduced or disallowed altogether. Should the
IRS require a different basis adjustment to be made, and should,
in our opinion, the expense of compliance exceed the benefit of
the election, we may seek permission from the IRS to revoke our
Section 754 election. If permission is granted, a
subsequent purchaser of common units may be allocated more
income than it would have been allocated had the election not
been revoked.
Tax
Treatment of Operations
Accounting
Method and Taxable Year
We use the year ending December 31 as our taxable year and the
accrual method of accounting for United States federal income
tax purposes. Each unitholder will be required to include in
income its share of our income, gain, loss, and deduction for
our taxable year ending within or with its taxable year. In
addition, a
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unitholder who has a taxable year ending on a date other than
December 31 and who disposes of all of its common units
following the close of our taxable year but before the close of
its taxable year must include its share of our income, gain,
loss, and deduction in income for its taxable year, with the
result that it will be required to include in income for its
taxable year its share of more than one year of our income,
gain, loss, and deduction. See Disposition of Common
Units Allocations Between Transferors and
Transferees.
Initial
Tax Basis, Depreciation, and Amortization
The tax basis of our assets will be used for purposes of
computing depreciation and cost recovery deductions and,
ultimately, gain or loss on the disposition of these assets. The
United States federal income tax burden associated with the
difference between the fair market value of our assets and their
tax basis immediately prior to (1) this offering will be
borne by our general partner and our unitholders at such time,
and (2) any other offering will be borne by our general
partner and all of our unitholders as of that time. See
Tax Consequences of Common Unit Ownership
Allocation of Income, Gain, Loss, and Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods that will result in the largest
deductions being taken in the early years after assets are
placed in service. Property we subsequently acquire or construct
may be depreciated using accelerated methods permitted by the
Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure, or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of its interest in us. See Tax
Consequences of Common Unit Ownership Allocation of
Income, Gain, Loss, and Deduction and Disposition of
Common Units Recognition of Gain or Loss.
The costs incurred in selling our common units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably, or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts we incur will be treated as syndication
expenses.
Valuation
and Tax Basis of Our Properties
The United States federal income tax consequences of the
ownership and disposition of common units will depend in part on
our estimates of the relative fair market values, and the
initial tax bases, of our assets. Although we may from time to
time consult with professional appraisers regarding valuation
matters, we will make many of the relative fair market value
estimates ourselves. These estimates and determinations of basis
are subject to challenge and will not be binding on the IRS or
the courts. If the estimates of fair market value or basis are
later found to be incorrect, the character and amount of items
of income, gain, loss, or deduction previously reported by
unitholders might change, and unitholders might be required to
adjust their tax liability for prior years and incur interest
and penalties with respect to those adjustments.
Coal
Income
Section 631 of the Internal Revenue Code provides special
rules by which gains or losses on the sale of coal may be
treated, in whole or in part, as gains or losses from the sale
of property used in a trade or business under Section 1231
of the Internal Revenue Code. Specifically, Section 631(c)
provides that if the owner of coal held for more than one year
disposes of that coal under a contract by virtue of which the
owner retains an economic interest in the coal, the gain or loss
realized will be treated under Section 1231 of the Internal
Revenue Code as gain or loss from property used in a trade or
business. Section 1231 gains and losses may be treated as
capital gains and losses. Please read Sales of
Coal Reserves. In computing such gain or loss, the amount
realized is reduced by the adjusted depletion basis in the coal,
determined as described in Coal
Depletion. For purposes of Section 631(c), the coal
generally is deemed to be disposed of on the
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day on which the coal is mined. Further, Treasury regulations
promulgated under Section 631 provide that advance royalty
payments may also be treated as proceeds from sales of coal to
which Section 631 applies and, therefore, such payment may
be treated as capital gain under Section 1231. However, if
the right to mine the related coal expires or terminates under
the contract that provides for the payment of advance royalty
payments or such right is abandoned before the coal has been
mined, the taxpayer must, pursuant to the Treasury regulations,
recompute its tax liability and file an amended return that
reflects the payments attributable to unmined coal as ordinary
income and not as received from the sale of coal under
Section 631.
Because Armstrong Energy, Inc. and we are related parties, our
royalties from coal leases with Armstrong Energy, Inc. do not
qualify for the Section 631 treatment described above. The
royalties from such leases will be ordinary income. However,
future leases with other parties may not be subject to the
strictures of the related party rules of Section 631,
resulting in Section 631 treatment (if Section 631
otherwise applies). In such latter instances, the difference
between the royalties paid to us by such lessees and the
adjusted depletion basis in the extracted coal generally will be
treated as gain from the sale of property used in a trade or
business, which may be treated as capital gain under
Section 1231. Please read Sale of Coal
Reserves.
Coal
Depletion
In general, we are entitled to depletion deductions with respect
to coal mined from the underlying mineral property. We generally
are entitled to the greater of cost depletion limited to the
basis of the property or percentage depletion. The percentage
depletion rate for coal is 10%.
Depletion deductions we claim generally will reduce the tax
basis of the underlying mineral property. Depletion deductions
can, however, exceed the total tax basis of the mineral
property. The excess of our percentage depletion deductions over
the adjusted tax basis of the property at the end of the taxable
year is subject to tax preference treatment in computing the
alternative minimum tax. See Tax Consequences of Common
Unit Ownership Alternative Minimum Tax. Upon
the disposition of the mineral property, a portion of the gain,
if any, equal to the lesser of the deductions for depletion
which reduce the adjusted tax basis of the mineral property plus
deductible development and mining exploration expenses, or the
amount of gain recognized upon the disposition, will be treated
as ordinary income to us. In addition, a corporate
unitholders allocable share of the amount allowable as a
percentage depletion deduction for any property will be reduced
by 20% of the excess, if any, of that partners allocable
share of the amount of the percentage depletion deductions for
the taxable year over the adjusted tax basis of the mineral
property as of the close of the taxable year.
Mining
Exploration and Development Expenditures
We currently do not expect to incur any mining exploration
expenditures, which are expenditures incurred to determine the
existence, location, extent, or quality of coal deposits prior
to the time the existence of coal in commercially marketable
quantities has been disclosed. If we do incur such expenditures,
however, we will elect to currently deduct such expenditures
that we pay or incur.
Amounts we deduct for mining exploration expenditures must be
recaptured and included in our taxable income at the time a mine
reaches the production stage, unless we elect to reduce future
depletion deductions by the amount of the recapture. A mine
reaches the producing stage when the major part of the coal
production is obtained from working mines other than those
opened for the purpose of development or the principal activity
of the mine is the production of developed coal rather than the
development of additional coal for mining. This recapture is
accomplished through the disallowance of both cost and
percentage depletion deductions on the particular mine reaching
the producing stage. This disallowance of depletion deductions
continues until the amount of adjusted exploration expenditures
with respect to the mine have been fully recaptured. This
recapture is not applied to the full amount of the previously
deducted exploration expenditures. Instead, these expenditures
are reduced by the amount of percentage depletion, if any, that
was lost as a result of deducting these exploration expenditures.
We also do not expect to incur any mine development expenses,
consisting of expenditures incurred in making coal accessible
for extraction, after the exploration process has disclosed the
existence of coal in
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commercially marketable quantities. If we do incur such
expenses, however, we generally will elect to defer such mine
development expenses and deduct them on a ratable basis as the
coal benefited by the expenses is sold.
Mine exploration and development expenditures are subject to
recapture as ordinary income to the extent of any gain upon a
sale or other disposition of our property or of your common
units. See Disposition of Common Units. Corporate
unitholders are subject to an additional rule that requires them
to capitalize a portion of their otherwise deductible mine
exploration and development expenditures. Corporate unitholders,
other than some S corporations, are required to reduce
their otherwise deductible exploration expenditures by 30%.
These capitalized mine exploration and development expenditures
must be amortized over a
60-month
period, beginning in the month paid or incurred, using a
straight-line method, and may not be treated as part of the
basis of the property for purposes of computing depletion.
When computing the alternative minimum tax, mine exploration and
development expenditures are capitalized and deducted over a ten
year period. Unitholders may avoid this alternative minimum tax
adjustment of their mine exploration and development
expenditures by electing to capitalize all or part of the
expenditures and deducting them over ten years for regular
income tax purposes. You may select the specific amount of these
expenditures for which you wish to make this election.
Sales
of Coal Reserves
If any coal reserves are sold or otherwise disposed of in a
taxable transaction, we will recognize gain or loss measured by
the difference between the amount realized (including the amount
of any indebtedness assumed by the purchaser upon such
disposition or to which such property is subject) and the
adjusted tax basis of the property sold. Generally, the
character of any gain or loss recognized upon that disposition
will depend upon whether our coal reserves or the mined coal
sold are held by us:
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for sale to customers in the ordinary course of business
(i.e., we are a dealer with respect to that
property);
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for use in a trade or business within the meaning of
Section 1231 of the Internal Revenue Code; or
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as a capital asset within the meaning of Section 1221 of
the Internal Revenue Code.
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In determining dealer status with respect to coal reserves and
other types of real estate, the courts have identified a number
of factors for distinguishing between a particular property held
for sale in the ordinary course of business and one held for
investment. Any determination must be based on all the facts and
circumstances surrounding the particular property and sale in
question.
We intend to hold our coal reserves for the purposes of
generating cash flow from coal royalties and achieving long-term
capital appreciation. Although our general partner may consider
strategic sales of coal reserves consistent with achieving
long-term capital appreciation, our general partner does not
anticipate frequent sales, marketing, improvement, or
subdivision of coal reserves. Thus, the general partner does not
believe we will be viewed as a dealer. In light of the factual
nature of this question, however, there is no assurance that our
purposes for holding our properties will not change and that our
future activities will not cause us to be a dealer
in coal reserves.
If we are not a dealer with respect to our coal reserves and we
have held the disposed property for more than a one-year period
primarily for use in our trade or business, the character of any
gain or loss realized from a disposition of the property will be
determined under Section 1231 of the Internal Revenue Code.
If we have not held the property for more than one year at the
time of the sale, gain, or loss from the sale will be taxable as
ordinary income.
A unitholders distributive share of any Section 1231
gain or loss generated by us will be aggregated with any other
gains and losses realized by that unitholder from the
disposition of property used in the trade or business, as
defined in Section 1231(b) of the Internal Revenue Code,
and from the involuntary conversion of such properties and of
capital assets held in connection with a trade or business or a
transaction entered into for profit for the requisite holding
period. If a net gain results, all such gains and losses will be
long-term
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capital gains and losses; if a net loss results, all such gains
and losses will be ordinary income and losses. Net
Section 1231 gains will be treated as ordinary income to
the extent of prior net Section 1231 losses of the taxpayer
or predecessor taxpayer for the five most recent prior taxable
years to the extent such losses have not previously been offset
against Section 1231 gains. Losses are deemed recaptured in
the chronological order in which they arose.
If we are not a dealer with respect to our coal reserves and
that property is not used in a trade or business, the property
will be a capital asset within the meaning of
Section 1221 of the Internal Revenue Code. Gain or loss
recognized from the disposition of that property will be taxable
as capital gain or loss, and the character of such capital gain
or loss as long-term or short-term will be based upon our
holding period of such property at the time of its sale. The
requisite holding period for long-term capital gain is more than
one year.
Upon a disposition of coal reserves, a portion of the gain, if
any, equal to the lesser of (1) the depletion deductions
that reduced the tax basis of the disposed mineral property plus
deductible development and mining exploration expenses or
(2) the amount of gain recognized on the disposition, will
be treated as ordinary income to us.
Deduction
for U.S. Production Activities
Subject to the limitations on the deductibility of losses
discussed above and the limitation discussed below, unitholders
will be entitled to a deduction, herein referred to as the
Section 199 deduction, equal to a specified percentage of
our qualified production activities income, if any, that is
allocated to such unitholder. The percentage is currently 9% for
qualified production activities income.
Qualified production activities income is generally equal to
gross receipts from domestic production activities reduced by
cost of goods sold allocable to those receipts, other expenses
directly associated with those receipts, and a share of other
deductions, expenses, and losses that are not directly allocable
to those receipts or another class of income. The products
produced must be manufactured, produced, grown, or extracted in
whole or in significant part by the taxpayer in the United
States. Because we expect that substantially all of our income
will consist of royalty income, we currently do not expect to
generate qualified production activities income.
For a partnership, the Section 199 deduction is determined
at the partner level. To determine its Section 199
deduction, each unitholder will aggregate its share of the
qualified production activities income allocated to it from us
with the unitholders qualified production activities
income from other sources. Each unitholder must take into
account its distributive share of the expenses allocated to it
from our qualified production activities regardless of whether
we otherwise have taxable income. However, our expenses that
otherwise would be taken into account for purposes of computing
the Section 199 deduction are only taken into account if
and to the extent the unitholders share of losses and
deductions from all of our activities is not disallowed by the
basis rules, the at risk rules or the passive activity loss
rules. See Tax Consequences of Common Unit
Ownership Limitations on Deductibility of
Losses.
The amount of a unitholders Section 199 deduction for
each year is limited to 50% of the IRS
Form W-2
wages actually or deemed paid by the unitholder during the
calendar year that are deducted in arriving at qualified
production activities income. Each unitholder is treated as
having been allocated IRS
Form W-2
wages from us equal to the unitholders allocable share of
our wages that are deducted in arriving at qualified production
activities income for that taxable year. Therefore, even if we
do generate qualified production activities income, a
unitholders ability to claim the Section 199
deduction may be limited.
Recent
Legislative Developments
The White House recently released the Budget Proposal. Among the
changes recommended in the Budget Proposal is the elimination of
certain key United States federal income tax preferences
relating to coal exploration and development. 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,
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(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 changes could increase the taxable
income allocable to our unitholders and negatively impact the
value of an investment in our common units.
In addition, the Obama Administration is considering, and, in
2010, the U.S. House of Representatives passed, legislation
that would provide for substantive changes to the definition of
qualifying income and the treatment of certain types of income
earned from profits interests in partnerships. It is possible
that these legislative efforts could result in changes to the
existing federal income tax laws that affect publicly traded
partnerships. As previously proposed, we do not believe any such
legislation would affect our tax treatment as a partnership.
However, the proposed legislation could be modified in a way
that could affect us. We are unable to predict whether any of
these changes, or other proposals, will ultimately be enacted.
Any such changes could negatively impact the value of an
investment in our common units.
Disposition
of Common Units
Recognition
of Gain or Loss
Gain or loss will be recognized on a sale of common units equal
to the difference between the unitholders amount realized
and the unitholders tax basis for the common units sold. A
unitholders amount realized will equal the sum of the cash
or the fair market value of other property received by it plus
the unitholders share of our nonrecourse liabilities.
Because the amount realized includes a unitholders share
of our nonrecourse liabilities, the gain recognized on the sale
of common units could result in a tax liability in excess of any
cash received from the sale.
Prior distributions from us that in the aggregate were in excess
of cumulative net taxable income for a common unit that
decreased a unitholders tax basis in that common unit
will, in effect, become taxable income if the common unit is
sold at a price greater than the unitholders tax basis in
that common unit, even if the price received is less than the
unitholders original cost.
Except as noted below, gain or loss recognized by a unitholder,
other than a dealer in common units, on the sale or
exchange of a common unit will generally be taxable as capital
gain or loss. Capital gain recognized by an individual on the
sale of common units held more than one year will generally be
taxed at a maximum United States federal income tax rate of 15%
through December 31, 2012, and 20% thereafter (absent new
legislation extending or adjusting the current rate). However, a
portion of this gain or loss, which could be substantial will be
separately computed and taxed as ordinary income or loss under
Section 751 of the Internal Revenue Code to the extent
attributable to assets giving rise to depreciation recapture or
other unrealized receivables or to inventory
items we own. The term unrealized receivables
includes potential recapture items, including depreciation and
depletion recapture. Ordinary income attributable to unrealized
receivables, inventory items, and depreciation and depletion
recapture may exceed net taxable gain realized upon the sale of
a common unit and may be recognized even if there is a net
taxable loss realized on the sale of a common unit. Thus, a
unitholder may recognize both ordinary income and a capital loss
upon a sale of common units. Net capital losses may offset
capital gains and no more than $3,000 of ordinary income each
year, in the case of individuals, and may only be used to offset
capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in its entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
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identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling discussed
above, a unitholder will be unable to select high or low basis
common units to sell as would be the case with corporate stock,
but, according to the Treasury Regulations, may designate
specific common units sold for purposes of determining the
holding period of common units transferred. A unitholder
electing to use the actual holding period of common units
transferred must consistently use that identification method for
all subsequent sales or exchanges of common units. A unitholder
considering the purchase of additional common units or a sale of
common units purchased in separate transactions is urged to
consult its tax advisor as to the possible consequences of this
ruling and application of the Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned, or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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a futures or forward contract with respect to the partnership
interest or substantially identical property.
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Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations
Between Transferors and Transferees
In general, our taxable income or loss will be determined
annually, will be prorated on a monthly basis, and will be
subsequently apportioned among the unitholders in proportion to
the number of common units owned by each of them as of the
opening of the applicable exchange on the first business day of
the month, which we refer to in this prospectus as the
Allocation Date. However, gain or loss realized on a
sale or other disposition of our assets other than in the
ordinary course of business will be allocated among the
unitholders on the Allocation Date in the month in which that
gain or loss is recognized. As a result, a unitholder
transferring common units may be allocated income, gain, loss,
and deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code and most publicly traded partnerships use
a similar simplifying convention, the use of this method may not
be permitted under existing Treasury Regulations. Recently,
however, the Department of the Treasury and the IRS issued
proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a
similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders, although such tax
items must be prorated on a daily basis. Nonetheless, the
proposed regulations do not specifically authorize the use of
the proration method we have adopted. Existing publicly traded
partnerships are entitled to rely on these proposed Treasury
Regulations; however, they are not binding on the IRS and are
subject to change until final Treasury Regulations are issued.
Accordingly, Armstrong Teasdale LLP is unable to opine on the
validity of this method of allocating income and deductions
between transferor and transferee unitholders. If this method is
not allowed under the Treasury Regulations, or only applies to
transfers of less than all of the unitholders interest,
our taxable income or losses might be reallocated among the
unitholders. We are authorized to revise our method of
allocation between transferor and transferee unitholders, as
well as unitholders whose interests vary during a taxable year,
to conform to a method permitted under future Treasury
Regulations.
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A unitholder who owns common units at any time and who disposes
of them prior to the record date set for a cash distribution
will be allocated items of our income, gain, loss, and
deductions attributable to the period prior to the disposal of
the common units, but will not be entitled to receive that cash
distribution.
Notification
Requirements
Generally, the general partner will not recognize any transfer
of a unitholders interest until the certificate evidencing
such unitholders interest is surrendered for registration
of transfer and such certificate is accompanied by a transfer
application duly executed by the transferee (or the
transferees attorney-in-fact duly authorized in writing).
Upon receiving such documents, we are required to notify the IRS
of that transaction and to furnish specified information to the
transferor and transferee.
Constructive
Termination
We will be considered to have been terminated for tax purposes
if there are sales or exchanges which, in the aggregate,
constitute 50% or more of the total interests in our capital and
profits within a twelve-month period. For purposes of measuring
whether the 50% threshold is reached, multiple sales of the same
unit within a twelve-month period are counted only once. A
constructive termination results in the closing of our taxable
year for all unitholders. In the case of a unitholder reporting
on a taxable year other than a fiscal year ending
December 31, the closing of our taxable year may result in
more than twelve months of our taxable income or loss being
includable in its taxable income for the year of termination. A
constructive termination occurring on a date other than December
31 will result in us filing two tax returns (and unitholders
receiving two Schedules K-1 if the relief discussed below is not
available) for one fiscal year and the cost of the preparation
of these returns will be borne by all unitholders. We would be
required to make new tax elections after a termination,
including a new election under Section 754 of the Internal
Revenue Code, and a termination would result in a deferral of
our deductions for depreciation. A termination could also result
in penalties if we were unable to determine that the termination
had occurred. Moreover, a termination might either accelerate
the application of, or subject us to, any tax legislation
enacted before the termination. The IRS has recently announced a
relief procedure whereby if a publicly traded partnership that
has technically terminated requests and the IRS grants special
relief, among other things, the partnership will be required to
provide only a single
Schedule K-1
to unitholder for the tax year in which the termination occurs
notwithstanding two partnership tax years.
Uniformity
of Common Units
Because we cannot match transferors and transferees of common
units, we must maintain uniformity of the economic and tax
characteristics of the common units to a purchaser of these
common units. In the absence of uniformity, we may be unable to
completely comply with a number of United States federal income
tax requirements, both statutory and regulatory. A lack of
uniformity can result from a literal application of Treasury
Regulation Section 1.167(c)-1(a)(6).
Any non-uniformity could have a negative impact on the value of
the common units. See Tax Consequences of Common Unit
Ownership Section 754 Election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as nonamortizable, to the
extent attributable to property the common basis of which is not
amortizable, consistent with the regulations under
Section 743 of the Internal Revenue Code, even though that
position may be inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets and Treasury
Regulation Section 1.197-2(g)(3).
See Tax Consequences of Common Unit Ownership
Section 754 Election. To the extent that the
Section 743(b) adjustment is attributable to appreciation
in value in excess of the unamortized Book-Tax Disparity, we
will apply the rules described in the Treasury Regulations and
legislative history. If we determine that this position cannot
reasonably be taken, we may adopt a depreciation and
amortization position under which all purchasers acquiring
common units in the same
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month would receive depreciation and amortization deductions,
whether attributable to a common basis or Section 743(b)
adjustment, based upon the same applicable methods and lives as
if they had purchased a direct interest in our property. If this
position is adopted, it may result in lower annual depreciation
and amortization deductions than would otherwise be allowable to
some unitholders and risk the loss of depreciation and
amortization deductions not taken in the year that these
deductions are otherwise allowable. This position will not be
adopted if we determine that the loss of depreciation and
amortization deductions will have a material adverse effect on
the unitholders. If we choose not to utilize this aggregate
method, we may use any other reasonable depreciation and
amortization method to preserve the uniformity of the intrinsic
tax characteristics of any common units that would not have a
material adverse effect on the unitholders. The IRS may
challenge any method of depreciating the Section 743(b)
adjustment described in this paragraph. If this challenge were
sustained, the uniformity of common units might be affected, and
the gain from the sale of common units might be increased
without the benefit of additional deductions. See
Disposition of Common Units Recognition of
Gain or Loss.
Tax-Exempt
Organizations and Other Investors
Ownership of common units by employee benefit plans, other
tax-exempt organizations, non-resident aliens, foreign
corporations, and other foreign persons raises issues unique to
those investors and, as described below, may have substantially
adverse tax consequences to them. If you are a tax-exempt entity
or a
non-U.S. person,
you should consult your tax advisor before investing in our
common units.
Employee benefit plans and most other organizations exempt from
United States federal income tax, including individual
retirement accounts and other retirement plans, are subject to
United States federal income tax on unrelated business taxable
income (UBTI). Under Section 512(c) of the
Internal Revenue Code, such an organization is required to
include, in computing its UBTI, its share of income of any
partnership of which it is a partner to the extent that such
income would be UBTI if earned directly by such organization.
UBTI is defined for these purposes as gross income from any
unrelated trade or business regularly carried on by the
organization less any deductions attributable thereto and less a
specific de minimis deduction of $1,000. Under Section 513
of the Internal Revenue Code, an unrelated trade or business
consists of any trade or business the conduct of which is not
substantially related to the organizations exempt purpose
or function. UBTI generally does not, however, include
dividends, interest, royalties and gains from the sale, exchange
or other disposition of property other than inventory or
property held primarily for sale to customers in the ordinary
course of a trade or business.
UBTI also includes unrelated debt-financed income as
described in Section 514 of the Internal Revenue Code
(UDFI). UDFI includes a portion of the income
derived from property with respect to which there is acquisition
indebtedness outstanding at any time during the taxable year
(or, if the property was disposed of during the taxable year, at
any time during the
12-month
period ending with the date of disposition). Acquisition
indebtedness includes any indebtedness incurred directly or
indirectly to purchase such property. UBTI thus includes a
portion of any income and gains derived from property with
respect to which there is acquisition indebtedness.
Although royalty income and gains from the sale of property
(other than inventory and property held primarily for sale to
customers in the ordinary course of business) generally are not
UBTI, royalty income and such gains may be UBTI to the extent
such royalty income or gains are derived from property subject
to acquisition indebtedness. Accordingly, to the extent our
royalty interests are considered to be subject to acquisition
indebtedness, all or a portion of our royalty income and gains
from the sale of such royalty interests will be UBTI.
Non-resident aliens and foreign corporations, trusts, or estates
that own common units will be considered to be engaged in
business in the United States because of the ownership of common
units. As a consequence, they will be required to file United
States federal tax returns to report their share of our income,
gain, loss, or deduction and pay United States federal income
tax at regular rates on their share of our net income or gain.
Moreover, under rules applicable to publicly traded
partnerships, our distributions to foreign unitholders will be
withheld upon at the highest applicable effective tax rate. Each
foreign unitholder must obtain a taxpayer
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identification number from the IRS and submit that number to our
transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
In addition, because a foreign corporation that owns common
units will be treated as engaged in a U.S. trade or
business, that corporation may be subject to the
U.S. branch profits tax at a rate of 30%, in addition to
regular United States federal income tax, on its share of our
income and gain, as adjusted for changes in the foreign
corporations U.S. net equity, which is
effectively connected with the conduct of a U.S. trade or
business. That tax may be reduced or eliminated by an income tax
treaty between the United States and the country in which the
foreign corporate unitholder is a qualified
resident. In addition, this type of unitholder is subject
to special information reporting requirements under
Section 6038C of the Internal Revenue Code.
A foreign unitholder who sells or otherwise disposes of a common
unit will be subject to United States federal income tax on gain
realized from the sale or disposition of that common unit to the
extent the gain is effectively connected with a U.S. trade
or business of the foreign unitholder. Under a ruling published
by the IRS, interpreting the scope of effectively
connected income, a foreign unitholder would be considered
to be engaged in a trade or business in the U.S. by virtue
of the U.S. activities of the partnership, and part or all
of that unitholders gain would be effectively connected
with that unitholders indirect U.S. trade or
business. Moreover, under the Foreign Investment in Real
Property Tax Act, a foreign unitholder generally will be subject
to United States federal income tax upon the sale or disposition
of a common unit if (1) it owned (directly or
constructively applying certain attribution rules) more than 5%
of our common units at any time during the five-year period
ending on the date of such disposition and (2) 50% or more
of the fair market value of all of our assets consisted of
U.S. real property interests at any time during the shorter
of the period during which such unitholder held the common units
or the
5-year
period ending on the date of disposition. Currently, more than
50% of our assets consist of U.S. real property interests,
and we do not expect that to change in the foreseeable future.
Therefore, foreign unitholders may be subject to United States
federal income tax on gain from the sale or disposition of their
common units.
Administrative
Matters
Information
Returns and Audit Procedures
We intend to furnish to each unitholder, within 90 days
after the close of each taxable year, specific tax information,
including a
Schedule K-1,
which describes its share of our income, gain, loss, and
deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take
various accounting and reporting positions, some of which have
been mentioned earlier, to determine each unitholders
share of income, gain, loss, and deduction. We cannot assure you
that those positions will yield a result that conforms to the
requirements of the Internal Revenue Code, Treasury Regulations,
or administrative interpretations of the IRS. Neither we nor
Armstrong Teasdale LLP can assure prospective unitholders that
the IRS will not successfully contend in court that those
positions are impermissible. Any challenge by the IRS could
negatively affect the value of the common units.
The IRS may audit our United States federal income tax
information returns. Adjustments resulting from an IRS audit may
require each unitholder to adjust a prior years tax
liability and possibly may result in an audit of its return. Any
audit of a unitholders return could result in adjustments
not related to our returns as well as those related to our
returns.
Partnerships generally are treated as separate entities for
purposes of United States federal tax audits, judicial review of
administrative adjustments by the IRS, and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss, and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. Our Partnership Agreement names Elk Creek GP, our
general partner, as our Tax Matters Partner.
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The Tax Matters Partner will make some elections on our behalf
and on behalf of unitholders. In addition, the Tax Matters
Partner can extend the statute of limitations for assessment of
tax deficiencies against unitholders for items in our returns.
The Tax Matters Partner may bind a unitholder with less than a
1% profits interest in us to a settlement with the IRS unless
that unitholder elects, by filing a statement with the IRS, not
to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review, by which all the
unitholders are bound, of a final partnership administrative
adjustment, and if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate.
A unitholder must file a statement with the IRS identifying the
treatment of any item on its United States federal income tax
return that is not consistent with the treatment of the item on
our return. Intentional or negligent disregard of this
consistency requirement may subject a unitholder to substantial
penalties.
Nominee
Reporting
Persons who hold an interest in us as a nominee for another
person are required to furnish to us:
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the name, address, and taxpayer identification number of the
beneficial owner and the nominee;
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whether the beneficial owner is (i) a person that is not a
U.S. person; (ii) a foreign government, an
international organization, or any wholly owned agency or
instrumentality of either of the foregoing; or (iii) a
tax-exempt entity;
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the amount and description of common units held, acquired, or
transferred for the beneficial owner; and
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specific information including the dates of acquisitions and
transfers, means of acquisitions and transfers, and acquisition
cost for purchases, as well as the amount of net proceeds from
sales.
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Brokers and financial institutions are required to furnish
additional information, including whether they are
U.S. persons and specific information on common units they
acquire, hold, or transfer for their own account. A penalty of
$100 per failure, up to a maximum of $1.5 million per
calendar year, is imposed by the Internal Revenue Code for
failure to report that information to us. The nominee is
required to supply the beneficial owner of the common units with
the information furnished to us.
Accuracy-Related
Penalties
An additional tax equal to 20% of the amount of any portion of
an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax, and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for the underpayment of that portion and that
the taxpayer acted in good faith regarding the underpayment of
that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to
penalty generally is reduced if any portion is attributable to a
position adopted on the return:
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for which there is, or was, substantial
authority; or
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as to which there is a reasonable basis and the pertinent facts
of that position are disclosed on the return.
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If any item of income, gain, loss, or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be
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appropriate to permit unitholders to avoid liability for this
penalty. More stringent rules apply to tax shelters,
which we do not believe includes us or any of our investments,
plans, or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the tax basis of any property, claimed
on a tax return is 150% or more of the amount determined to be
the correct amount of the valuation or tax basis, (b) the
price for any property or services (or for the use of property)
claimed on any such return with respect to any transaction
between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5 million or 10% of the
taxpayers gross receipts. No penalty is imposed unless the
portion of the underpayment attributable to a substantial
valuation misstatement exceeds $5,000 ($10,000 for a corporation
other than an S Corporation or a personal holding company).
The penalty is increased to 40% in the event of a gross
valuation misstatement. We do not anticipate making any
valuation misstatements.
In addition, the 20% accuracy-related penalty also applies to
any portion of an underpayment of tax that is attributable to
transactions lacking economic substance. To the extent that such
transactions are not disclosed, the penalty imposed is increased
to 40%. Additionally, there is no reasonable cause defense to
the imposition of this penalty to such transaction.
Reportable
Transactions
If we were to engage in a reportable transaction, we
(and possibly you and others) would be required to make a
detailed disclosure of the transaction to the IRS. A transaction
may be a reportable transaction based upon any of several
factors, including the fact that it is a type of tax avoidance
transaction publicly identified by the IRS as a listed
transaction or that it produces certain kinds of losses
for partnerships, individuals, S corporations, and trusts
in excess of $2 million in any single year or
$4 million in any combination of six successive tax years.
Our participation in a reportable transaction could increase the
likelihood that our United States federal income tax information
return (and possibly your tax return) would be audited by the
IRS. See Information Returns and Audit
Procedures.
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, you may be subject to the following
provisions of the American Jobs Creation Act of 2004:
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accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-Related Penalties;
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for those persons otherwise entitled to deduct interest on
United States federal tax deficiencies, nondeductibility of
interest on any resulting tax liability; and
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in the case of a listed transaction, an extended statute of
limitations.
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We do not expect to engage in any reportable
transactions.
State,
Local, Foreign, and Other Tax Considerations
In addition to United States federal income taxes, you likely
will be subject to other taxes, such as state, local, and
foreign income taxes, unincorporated business taxes, and estate,
inheritance, or intangible taxes that may be imposed by the
various jurisdictions in which we do business or own property or
in which you are a resident. Although an analysis of those
various taxes is not presented here, each prospective unitholder
should consider their potential impact on its investment in us.
We will initially control property or do business in Kentucky.
We may also control property or do business in other
jurisdictions in the future. Although you may not be required to
file a return and pay taxes in some jurisdictions because your
income from that jurisdiction falls below the filing and payment
requirement, you may be required to file income tax returns and
to pay income taxes in other of these jurisdictions in which we
do business or control property now or in the future and may be
subject to penalties for failure to comply with those
requirements. In some jurisdictions, tax losses may not produce
a tax benefit in the year incurred and may not be available to
offset income in subsequent
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taxable years. Some of the jurisdictions may require us, or we
may elect, to withhold a percentage of income from amounts to be
distributed to a unitholder who is not a resident of the
jurisdiction. Withholding, the amount of which may be greater or
less than a particular unitholders income tax liability to
the jurisdiction, generally does not relieve a nonresident
unitholder from the obligation to file an income tax return.
Amounts withheld will be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. See Tax Consequences of Common Unit
Ownership Entity-Level Collections. Based
on current law and our estimate of our future operations, our
general partner anticipates that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate the
legal and tax consequences, under the laws of pertinent
jurisdictions, of its investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend upon, its
tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
state, local, and foreign, as well as United States federal tax
returns, which may be required of him. Armstrong Teasdale LLP
has not rendered an opinion on the state, local or foreign tax
consequences of an investment in us.
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CERTAIN
ERISA CONSIDERATIONS
An investment in our common units by an employee benefit plan is
subject to certain additional considerations because the
investments of these plans are subject to the fiduciary
responsibility and prohibited transaction provisions of ERISA
and restrictions imposed by Section 4975 of the Internal
Revenue Code and may be subject to provisions under certain
other laws or regulations that are similar to ERISA or the
Internal Revenue Code (collectively, Similar Laws).
As used herein, the term employee benefit plan
includes, but is not limited to, qualified pension,
profit-sharing and stock bonus plans, Keogh plans, simplified
employee pension plans and tax deferred annuities, IRAs and
other arrangements established or maintained by an employer or
employee organization, and entities whose underlying assets are
considered to include plan assets of such plans,
accounts and arrangements.
General
Fiduciary Matters
ERISA and the Internal Revenue Code impose certain duties on
persons who are fiduciaries of an employee benefit plan that is
subject to Title I of ERISA or Section 4975 of the
Internal Revenue Code (an ERISA Plan) and prohibit
certain transactions involving the assets of an ERISA Plan and
its fiduciaries or other interested parties. Under ERISA and the
Internal Revenue Code, any person who exercises any
discretionary authority or control over the administration of
such an ERISA Plan or the management or disposition of the
assets of an ERISA Plan, or who renders investment advice for a
fee or other compensation to an ERISA Plan, is generally
considered to be a fiduciary of the ERISA Plan. In considering
an investment in common units, among other things, consideration
should be given to:
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whether the investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws;
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whether in making the investment, the employee benefit plan will
satisfy the diversification requirements of
Section 404(a)(1)(C) of ERISA and any other applicable
Similar Laws;
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whether the investment is permitted under the terms of the
applicable documents governing the ERISA Plan;
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whether making the investment will comply with the delegation of
control and prohibited transaction provisions of ERISA, the
Internal Revenue Code and any other applicable Similar
Laws; and
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whether the investment will result in recognition of unrelated
business taxable income by the ERISA Plan and, if so, the
potential after-tax investment return. See Material Tax
Consequences Tax-Exempt Organizations and Other
Investors.
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The person with investment discretion with respect to the assets
of an employee benefit plan should determine whether an
investment in our common units is authorized by the appropriate
governing instrument and is a proper investment for the employee
benefit plan or IRA.
Prohibited
Transaction Issues
Section 406 of ERISA and Section 4975 of the Internal
Revenue Code prohibit employee benefit plans, and IRAs that are
not considered part of an employee benefit plan, from engaging
in specified transactions involving plan assets with
parties that are parties in interest under ERISA or
disqualified persons under the Internal Revenue Code
with respect to the employee benefit plan or IRA, unless an
exemption is applicable. A party in interest or disqualified
person who engages in a prohibited transaction may be subject to
excise taxes and other penalties and liabilities under ERISA and
the Internal Revenue Code. In addition, the fiduciary of the
ERISA Plan that engaged in such a prohibited transaction may be
subject to penalties and liabilities under ERISA and the
Internal Revenue Code.
Plan
Asset Issues
In addition to considering whether the purchase of common units
is a prohibited transaction, a fiduciary of an employee benefit
plan should consider whether the plan will, by investing in our
common units, be
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deemed to own an undivided interest in our assets, with the
result that our general partner would also be a fiduciary of the
plan and our operations would be subject to the regulatory
restrictions of ERISA, including its prohibited transaction
rules, as well as the prohibited transaction rules of the
Internal Revenue Code and any other applicable Similar Laws.
The Department of Labor regulations provide guidance with
respect to whether the assets of an entity in which employee
benefit plans acquire equity interests would be deemed
plan assets under certain circumstances. Under these
regulations, an entitys assets would not be considered to
be plan assets if, among other things:
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(a)
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the equity interests acquired by employee benefit plans are
publicly offered securities i.e., the equity
interests are widely held by 100 or more investors independent
of the issuer and each other, freely transferable
(as defined in the Department of Labor regulations) and either
part of a class of securities registered under certain
provisions of the federal securities laws or sold to the plan as
part of a public offering under certain conditions;
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(b)
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the entity is an operating company i.e.,
it is primarily engaged in the production or sale of a product
or service other than the investment of capital either directly
or through a majority-owned subsidiary or subsidiaries; or
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(c)
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there is no significant investment by benefit plan investors,
which is defined to mean that less than 25% of the value of each
class of equity interest, disregarding certain interests held by
our general partner, its affiliates and certain other persons,
is held by employee benefit plans that are subject to
part 4 of Title I of ERISA (which excludes
governmental plans)
and/or
Section 4975 of the Internal Revenue Code and IRAs.
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With respect to an investment in common units, we believe that
our assets should not be considered plan assets
under these regulations because it is expected that the
investment will satisfy the requirements in (a) above and
may also satisfy the requirements in (c) above (although we
do not monitor the level of investment by benefit plan investors
as required for compliance with (c)).
The foregoing discussion of issues arising for employee benefit
plan investments under ERISA, the Internal Revenue Code and
applicable Similar Laws is general in nature and is not intended
to be all inclusive, nor should it be construed as legal advice.
In light of the complexity of these rules and the excise taxes,
penalties and liabilities that may be imposed on persons
involved in non-exempt prohibited transactions or other
violations, plan fiduciaries contemplating a purchase of our
common units should consult with their own counsel regarding the
consequences of such purchases under ERISA, the Internal Revenue
Code and Similar Laws.
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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 common units set
forth opposite their names below:
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Number of
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Name of Underwriter
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Common Units
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Raymond James & Associates, Inc.
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FBR Capital Markets & Co.
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Stifel, Nicolaus & Company, Incorporated
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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 units
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 common units offered by this prospectus, if any
are purchased, other than those covered by the option to
purchase additional common units 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 units 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 unit. Any underwriter may
allow, and such dealers may reallow, a concession not in excess
of $ per unit. If all of the
common units are not sold at the public offering price, the
underwriters may change the public offering price and other
selling terms. The common units 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 common units in whole or in part.
Option to
Purchase Additional Common Units
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 common units 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 common units only to cover over-allotments made in
connection with the sale of common units offered in this
offering.
Discounts
and Expenses
The following table shows the amount per unit and total
underwriting discounts we will pay to the underwriters (dollars
in thousands, except per unit amounts). The amounts are shown
assuming both no exercise and full exercise of the
underwriters option to purchase additional common units.
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Total Without
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Over-
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Total With
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Per Common
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Allotment
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Over-Allotment
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Unit
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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 $1.1 million.
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Indemnification
We have agreed to indemnify the underwriters against certain
liabilities that may arise in connection with the offering,
including liabilities under the Securities Act and liabilities
incurred in connection with the directed share program referred
to below, and to contribute to payments that the underwriters
may be required to make for these liabilities.
Lock-Up
Agreements
Subject to specified exceptions, we, our general partners
managers, executive officers, unitholders and Armstrong Energy,
Inc. have agreed with the underwriters, for a period of
180 days, or 30 days in the case of unitholders other than
managers, executive officers, Armstrong Energy, Inc. or
affiliates of Yorktown (in each case, subject to extension),
after the date of this prospectus (such period, as applicable,
the restricted period), without the prior written
consent of Raymond James & Associates, Inc. and FBR Capital
Markets & Co.:
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not to offer for sale, pledge sell or contract to sell or
otherwise dispose of the common units;
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not to grant or sell any option or contract to purchase any of
the common units;
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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 common units or participate in any such registration,
including under this registration statement; and
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not to enter into any swap or any other agreement or transaction
that transfers, in whole or in part, any of the economic
consequences of ownership of or otherwise transfer or dispose
of, directly or indirectly, any of the common units.
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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 units or with
respect to us, to publicly disclose the intention to do the
foregoing transactions.
Raymond James & Associates, Inc. and FBR Capital Markets
& Co. may, in its discretion and at any time, release all
or any portion of the securities subject to these agreements.
Raymond James & Associates, Inc. and FBR Capital Markets
& Co. do not have any present intent or any understanding
to release all or any portion of the securities subject to these
agreements.
The restricted period described in the preceding paragraphs will
be extended if:
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during the last 17 days of the restricted period, we issue
a release concerning distributable cash or announce material
news or a material event relating to us occurs; or
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prior to the expiration of the restricted period, we announce
that we will release earnings results during the
16-day
period beginning on the last day of the restricted 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 release concerning
distributable cash, the announcement of material news or the
occurrence of the material event.
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Any participants in the directed share program will be subject
to a 180-day
lock-up with
respect to any common units sold to them pursuant to the
program. This
lock-up will
have similar terms and conditions as described above. Any common
units sold in the directed share program to our directors or
officers shall be subject to the
lock-up
agreement described above.
Stabilization
Until this offering is completed, rules of the SEC may limit the
ability of the underwriters to bid for and purchase the common
units. As an exception to these rules, the underwriters may
engage in activities that stabilize, maintain or otherwise
affect the price of the common units, 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 units while this offering is in progress.
Stabilizing transactions may include making short sales of
common units, which involve the sale by the underwriters of a
greater number of common units than they are required to
purchase in this offering and purchasing common units 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 common units 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 common units, in
whole or in part, or by purchasing common units in the open
market. In making this determination, each underwriter will
consider, among other things, the price of common units
available for purchase in the open market compared to the price
at which the underwriter may purchase common units pursuant to
the option to purchase additional common units.
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 units 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 common units in the open market to cover the
position.
As a result of these activities, the price of the common units
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.
Directed
Share Program
At our request, the underwriters have reserved for sale at the
initial public offering price up to 10% of the common units
offered hereby for officers, directors, employees and certain
other persons associated with us and with whom we do business.
The number of common units available for sale to the general
public will be reduced to the extent such persons purchase such
reserved common units. Any reserved common units not so
purchased will be offered by the underwriters to the general
public on the same basis as the other common units offered
hereby. The participants in this program have entered into
lock-up
agreements. See
Lock-Up
Agreements.
Discretionary
Accounts
The underwriters may confirm sales of the common units offered
by this prospectus to accounts over which they exercise
discretionary authority but do not expect those sales to exceed
5% of the total common units offered by this prospectus.
Listing
We have applied to list our common units on Nasdaq under the
symbol ARPS. 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
common units. 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 common units, 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.
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Neither we nor the underwriters can assure investors that an
active market will develop for our common units or that common
units 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 common units 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.
Relationships
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 AE 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
the Senior Secured Term Loan and the Senior Secured Revolving
Credit Facility. See Use of Proceeds.
FINRA
Rules
This offering will conform with the requirements set forth in
Financial Industry Regulatory Authority Rule 2310. In
compliance with such requirements, the total amount of all items
of underwriting compensation from whatever source in connection
with the sale of securities will not exceed 10% of gross
proceeds of this offering. Please read Description of the
Common Units Transfer of Common Units and
The Partnership Agreement Non-Citizens
Assignees; Redemption.
Notice to
Prospective Investors in the EEA
In relation to each Member State of the European Economic Area
which has implemented the Prospectus Directive (each, a
Relevant Member State), from and including the date
on which the European Union Prospectus Directive (the EU
Prospectus Directive) was implemented in that Relevant
Member State (the Relevant Implementation Date) an
offer of securities described in this prospectus may not be made
to the public in that Relevant Member State prior to the
publication of a prospectus in relation to the shares which has
been approved by the competent authority in that Relevant Member
State or, where appropriate, approved in another Relevant Member
State and notified to the competent authority in that Relevant
Member State, all in accordance with the EU Prospectus
Directive, except that, with effect from and including the
Relevant Implementation Date, an offer of securities described
in this prospectus may be made to the public in that Relevant
Member State at any time:
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to any legal entity which is a qualified investor as defined
under the EU Prospectus Directive;
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to fewer than 100 or, if the Relevant Member State has
implemented the relevant provision of the 2010 PD Amending
Directive, 150 natural or legal persons (other than qualified
investors as defined in the EU Prospectus Directive); or
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in any other circumstances falling within Article 3(2) of
the EU Prospectus Directive, provided that no such offer of
securities described in this prospectus shall result in a
requirement for the publication by us of a prospectus pursuant
to Article 3 of the EU Prospectus Directive.
|
For the purposes of this provision, the expression an
offer of securities to the public in relation to any
securities in any Relevant Member State means the communication
in any form and by any means of sufficient information on the
terms of the offer and the securities to be offered so as to
enable an investor to decide to purchase or subscribe for the
securities, as the same may be varied in that Member State by
any measure implementing the EU Prospectus Directive in that
Member State. The expression EU Prospectus Directive
means Directive 2003/71/EC (and any amendments thereto,
including the 2010 PD Amending Directive, to the extent
implemented in the Relevant Member State) and includes any
relevant implementing measure in each Relevant Member State, and
the expression 2010 PD Amending Directive means
Directive 2010/73/EU.
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:
|
|
|
|
(a)
|
you confirm and warrant that you are either:
|
|
|
|
|
(i)
|
a sophisticated investor under
section 708(8)(a) or (b) of the Corporations Act 2001
(Cth) of Australia (Corporations Act);
|
|
|
|
|
(ii)
|
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
|
|
|
|
|
(iii)
|
a professional investor within the meaning of
section 708(11)(a) or (b) of the Corporations Act,
|
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.
|
|
|
|
(b)
|
you warrant and agree that you will not offer any of the common
units issued to you pursuant to this document for resale in
Australia within 12 months of those common units being
issued unless any such resale offer is exempt from the
requirement to issue a disclosure document under
section 708 of the Corporations Act.
|
Notice to
Prospective Investors in Switzerland
This document, as well as any other material relating to the
common units 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 common units will not be
listed on the SIX Swiss Exchange and, therefore, the documents
relating to the common units, 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 common units 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 common units 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 common
units, 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
182
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 common
units 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 common units in, from or otherwise
involving the United Kingdom.
183
LEGAL
MATTERS
The validity of the common units 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
common units 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, 2011 were prepared by Weir
International, Inc., an independent mining and geological
consultant.
INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
The consolidated financial statements of Armstrong Resource
Partners, L.P. and subsidiaries as of December 31, 2011 and
2010 and for each of the years in the three-year period ended
December 31, 2011 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.
CHANGE IN
AUDITOR
Prior to engaging Ernst & Young as our independent
registered public accounting firm, KPMG LLP was engaged as our
independent registered public accounting firm to audit our
financial statements for the fiscal year ended December 31,
2008. In February 2010, our board of managers dismissed KPMG LLP
as our independent registered public accounting firm.
KPMG LLPs report on our 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 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 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 us of the material weakness
described herein. KPMG LLP identified several audit adjustments.
As a result of these adjustments and KPMG LLPs interaction
with our former controller, KPMG LLP believed that we 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. We terminated the former
controller and hired a new controller in 2009.
On March 4, 2010, our board of managers appointed
Ernst & Young LLP as our new independent registered
public accounting firm. Ernst & Young LLP audited our
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.
Notwithstanding the 2010 appointment of Ernst & Young
LLP as our new independent registered public accounting firm, on
June 4, 2010, our board of managers engaged Grant Thornton
LLP solely to re-audit our financial statements for the fiscal
year ended December 31, 2008. We were unable to engage
Ernst & Young LLP to re-audit the 2008 financial
statements due to the fact that Ernst & Young LLP
performed certain
184
consulting services for us 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, our board of managers dismissed
Grant Thornton LLP. Grant Thornton LLPs report on our
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 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 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 Partnerships 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 Resource Partners, L.P., 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.
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 with or
furnish to the SEC periodic reports and other information. Such
annual, quarterly and current reports 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 unitholders 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.
185
Report of
Independent Registered Public Accounting Firm
The Partners of
Armstrong Resource Partners, L.P. and Subsidiaries (formerly Elk
Creek, L.P. and Subsidiaries)
We have audited the accompanying consolidated balance sheets of
Armstrong Resource Partners, L.P. and Subsidiaries (formerly Elk
Creek, L.P. and Subsidiaries) (the Partnership) as of
December 31, 2011 and 2010, and the related consolidated
statements of operations, partners capital, and cash flows
for each of the three years the years in the period ended
December 31, 2011. These financial statements are the
responsibility of the Partnerships 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 Partnerships 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 Partnerships 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 Partnership at December 31, 2011
and 2010, and the consolidated results of its operations and its
cash flows for each of the three years in the period ended
December 31, 2011, in conformity with U.S. generally
accepted accounting principles.
St. Louis, Missouri
March 7, 2012
F-2
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
155
|
|
|
$
|
155
|
|
Other assets
|
|
|
464
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
619
|
|
|
|
155
|
|
Mineral rights, net and land
|
|
|
141,240
|
|
|
|
75,591
|
|
Related-party notes receivable
|
|
|
|
|
|
|
48,470
|
|
Related-party other receivables, net
|
|
|
25,700
|
|
|
|
13,713
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
167,559
|
|
|
$
|
137,929
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Non-current liabilities:
|
|
|
|
|
|
|
|
|
Other non-current liabilities
|
|
$
|
11,378
|
|
|
$
|
12,000
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
11,378
|
|
|
|
12,000
|
|
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
Series A Preferred Units (200,000 and zero units issued and
outstanding as of December 31, 2011 and 2010, respectively)
|
|
|
20,000
|
|
|
|
|
|
Limited partners interest (1,342,000 and
1,292,000 units issued and outstanding as of
December 31, 2011 and 2010, respectively)
|
|
|
135,775
|
|
|
|
125,532
|
|
General partners interest
|
|
|
406
|
|
|
|
397
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
156,181
|
|
|
|
125,929
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
167,559
|
|
|
$
|
137,929
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
F-3
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
|
(Amounts in thousands,
|
|
|
|
except per unit amounts)
|
|
|
Revenue
|
|
$
|
7,789
|
|
|
$
|
|
|
|
$
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
3,841
|
|
|
|
|
|
|
|
|
|
Related-party service expense
|
|
|
720
|
|
|
|
700
|
|
|
|
36
|
|
Other operating, general, and administrative costs
|
|
|
133
|
|
|
|
117
|
|
|
|
294
|
|
Unit-based compensation expense
|
|
|
2,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
184
|
|
|
|
(817
|
)
|
|
|
(330
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
1,009
|
|
|
|
4,209
|
|
|
|
161
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
(1,723
|
)
|
Other income (expense), net
|
|
|
1,148
|
|
|
|
(60
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2,341
|
|
|
$
|
3,332
|
|
|
$
|
(1,894
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to:
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner
|
|
$
|
9
|
|
|
$
|
15
|
|
|
$
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners
|
|
$
|
2,332
|
|
|
$
|
3,317
|
|
|
$
|
(1,878
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.74
|
|
|
$
|
2.96
|
|
|
$
|
(2.62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.73
|
|
|
$
|
2.96
|
|
|
$
|
(2.62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
F-4
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
CONSOLIDATED
STATEMENTS OF PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Series A
|
|
|
|
|
|
Limited
|
|
|
Limited
|
|
|
General
|
|
|
|
|
|
|
Preferred
|
|
|
|
|
|
Partners
|
|
|
Partners
|
|
|
Partners
|
|
|
|
|
|
|
Units
|
|
|
Common Units
|
|
|
Interest
|
|
|
Interest
|
|
|
Interest
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Balance at December 31, 2008
|
|
|
|
|
|
|
545,000
|
|
|
$
|
|
|
|
$
|
49,393
|
|
|
$
|
398
|
|
|
$
|
49,791
|
|
Partner contributions
|
|
|
|
|
|
|
416,000
|
|
|
|
|
|
|
|
41,600
|
|
|
|
|
|
|
|
41,600
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,878
|
)
|
|
|
(16
|
)
|
|
|
(1,894
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
|
|
|
|
961,000
|
|
|
|
|
|
|
|
89,115
|
|
|
|
382
|
|
|
|
89,497
|
|
Partner contributions
|
|
|
|
|
|
|
331,000
|
|
|
|
|
|
|
|
33,100
|
|
|
|
|
|
|
|
33,100
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,317
|
|
|
|
15
|
|
|
|
3,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
|
|
|
|
|
1,292,000
|
|
|
|
|
|
|
|
125,532
|
|
|
|
397
|
|
|
|
125,929
|
|
Partner contributions
|
|
|
|
|
|
|
50,000
|
|
|
|
|
|
|
|
5,000
|
|
|
|
|
|
|
|
5,000
|
|
Proceeds from the issuance of Series A Preferred Units
|
|
|
200,000
|
|
|
|
|
|
|
|
20,000
|
|
|
|
|
|
|
|
|
|
|
|
20,000
|
|
Unit compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,911
|
|
|
|
|
|
|
|
2,911
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,332
|
|
|
|
9
|
|
|
|
2,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2011
|
|
|
200,000
|
|
|
|
1,342,000
|
|
|
$
|
20,000
|
|
|
$
|
135,775
|
|
|
$
|
406
|
|
|
$
|
156,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
F-5
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
|
(Dollars in thousands)
|
|
|
Operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2,341
|
|
|
$
|
3,332
|
|
|
$
|
(1,894
|
)
|
Adjustments to reconcile net loss to net cash used in operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
3,841
|
|
|
|
|
|
|
|
|
|
Non-cash unit compensation expense
|
|
|
2,911
|
|
|
|
|
|
|
|
|
|
Change in working capital accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in inventory
|
|
|
|
|
|
|
60
|
|
|
|
|
|
Increase in other current assets
|
|
|
(464
|
)
|
|
|
|
|
|
|
|
|
Decrease in accounts payable
|
|
|
|
|
|
|
|
|
|
|
(14
|
)
|
Increase (decrease) in other non-current liabilities
|
|
|
(622
|
)
|
|
|
10,400
|
|
|
|
1,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
8,007
|
|
|
|
13,792
|
|
|
|
(308
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activity
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in related-party notes receivable
|
|
|
48,470
|
|
|
|
(37,309
|
)
|
|
|
(11,161
|
)
|
Change in related-party other receivables, net
|
|
|
(11,986
|
)
|
|
|
(9,583
|
)
|
|
|
(1,263
|
)
|
Investment in mineral rights and land
|
|
|
(69,491
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activity
|
|
|
(33,007
|
)
|
|
|
(46,892
|
)
|
|
|
(12,424
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners capital contributions
|
|
|
5,000
|
|
|
|
33,100
|
|
|
|
41,600
|
|
Proceeds from the issuance of Series A Preferred Units
|
|
|
20,000
|
|
|
|
|
|
|
|
|
|
Payment of debt
|
|
|
|
|
|
|
|
|
|
|
(28,878
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
25,000
|
|
|
|
33,100
|
|
|
|
12,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash
|
|
|
|
|
|
|
|
|
|
|
(10
|
)
|
Cash, at the beginning of the year
|
|
|
155
|
|
|
|
155
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, at the end of the year
|
|
$
|
155
|
|
|
$
|
155
|
|
|
$
|
155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid interest
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,636
|
|
See accompanying notes.
F-6
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
|
|
1.
|
DESCRIPTION
OF BUSINESS AND ENTITY STRUCTURE
|
In September 2011, Elk Creek, L.P. changed its name to Armstrong
Resource Partners, L.P. (ARP or the Partnership). The majority
of ARPs outstanding limited partnership interests are
owned by investment funds managed by Yorktown Partners LLC
(Yorktown). ARP is a Delaware limited partnership managed by the
general partner, Elk Creek GP, LLC (ECGP or the General
Partner), which is a wholly owned subsidiary of Armstrong
Energy, Inc. (formerly Armstrong Land Company) (AE or the
ultimate parent corporation); 92% of AEs equity is held by
Yorktown.
ARP is headquartered in St. Louis, Missouri, with reserve
interests in Western Kentucky. As of December 31, 2011,
2010, and 2009, ARP had no employees and paid AE for shared
services related to accounting, finance, and management.
ARP and subsidiaries (the Partnership, which includes all
subsidiaries) commenced business on March 31, 2008
(inception), for the purpose of owning coal production assets.
At inception, the General Partner held a 2% interest in ARP,
which has been reduced to approximately 0.4% at
December 31, 2011, with additional capital contributions by
the limited partners.
The Partnership owns certain mineral reserves outright, as well
as, has an undivided interest as a joint tenant in common in
certain coal reserves of AE. The Partnership does not currently
intend to operate its coal assets and has subleased the mining
rights to Armstrong Coal Company (ACC), a subsidiary of AE, in
return for royalty payments discussed further in Note 6.
The Partnership, therefore, will produce income in the form of
royalties from production/sale of coal mined from its properties
and incur expenses in the form of depletion, mining related
taxes, administrative expenses, and royalties due to landowners.
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Principles
of Consolidation
The consolidated financial statements include the accounts of
ARP and its wholly owned subsidiaries. All significant
intercompany balances and transactions of the Partnership were
eliminated.
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.
Revenue
Revenues consist of royalties earned and are recognized on the
basis of tons of coal sold by the Partnerships lessee, AE,
and the corresponding revenue from those sales. Royalties owed
to the Partnership are based on a percentage of the gross sales
price of coal sold by the lessee.
Cash
and Cash Equivalents
The Partnership considers all cash and temporary investments
having an original maturity of less than three months to be cash
equivalents.
F-7
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
December 31, 2011
Other
Assets
Other assets consists of deferred expenses incurred associated
with a potential liquidity event. Once the transaction is
completed, these expenses will be offset against the net
proceeds. If the transaction is not completed, these expenses
will be recognized in the results of operations in the period
that determination is made.
Financial
Instruments
The Partnerships financial instruments consist of cash and
cash equivalents, related-party notes receivable, and
related-party other receivables, net. The carrying amount of the
Partnerships financial instruments approximates their fair
value either due to the short maturity or the financial nature
of the balances.
Minerals
Rights and Land
Coal reserves, mineral rights, and land are recorded at cost as
mineral rights and land. Coal and other mineral rights are
depleted on the
units-of-production
method, based upon minerals mined in relation to the net cost of
the mineral properties and estimated proven and probable tonnage
therein.
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.
Related
Party Other Receivables, Net
Related party other receivables, net primarily represents the
Partnerships cash position. Elk Creek GP manages, on
behalf of the Partnership, substantially all cash, investing and
financing activities of the Partnership. As such, the change in
related party other receivables, net is reflected as an
investing activity or a financing activity in the statements of
cash flows depending on whether it represents a net asset or net
liability for the Partnership.
Income
Taxes
ARP and all its subsidiaries were established as a limited
partnership
and/or
limited liability companies (LP/LLCs); thus, for federal and, if
applicable, state and local income tax purposes, the LP/LLCs are
not subject to entity level income tax. All taxable income is
passed through to the individual members. In the event of an
examination of the tax return, the tax liability of the members
could be changed if an adjustment in the Partnerships
income is ultimately sustained by the taxing authorities.
Unit-Based
Compensation
The Partnership accounts for unit-based compensation at the
grant date fair value of awards and recognizes the related
expense over the vesting period of the award. See Note 10
for information related to unit-based compensation.
Accounting
Pronouncements Adopted
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
F-8
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
December 31, 2011
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
Partnerships consolidated financial statements.
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 Partnership. The adoption of this guidance will not
impact the Partnerships 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 Partnership. Early adoption is not
permitted. The adoption of this amendment is not expected to
materially affect the Partnerships consolidated financial
statements.
|
|
3.
|
AMENDMENT
TO THE PARTNERSHIP AGREEMENT
|
The partners of ARP entered into the Amended and Restated
Agreement of Limited Partnership of Armstrong Resource Partners,
L.P. dated October 1, 2011 (the ARP LPA), which, among
other things, allows Yorktown, the Partnerships largest
unit holder, to remove ECGP as general partner of ARP or
otherwise cause a change of control of ARP without the consent
of ECGP or the consent of the holders of ARPs equity
units. The ARP LPA is effective as of October 1, 2011.
In addition, the ARP LPA resulted in the reclassification of
each partners percentage interest in ARP into common
units. The number of common units outstanding was determined by
dividing the aggregate of each partners capital
contributions by 100. In accordance with SEC Staff Accounting
Bulletin Topic 4.C., Changes in Capital Structure,
all common unit information has been retroactively adjusted
to reflect the reclassification. As a result, the Partnership
had 1,342,000 and 1,292,000 common units issued and outstanding
to limited partners as of December 31, 2011 and 2010,
respectively.
|
|
4.
|
MINERAL
RIGHTS AND LAND
|
The Partnership acquired mineral rights and other assets on
March 31, 2008 (the Elk Creek Reserves) in Western Kentucky
from an unrelated third party for $21,591 in cash and a $54,000
promissory note, which was paid in full as of December 31,
2009. On February 9, 2011, the Partnership acquired a
39.45% undivided interest in certain land and mineral reserves
of AE for the equivalent of $69,491 (see Note 6).
Coal reserves are estimated at 120,470 and 65,591 proven and
probable tons as of December 31, 2011 and 2010,
respectively. Mining by the lessee, AE, of the
Partnerships reserves commenced in 2011.
F-9
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
December 31, 2011
Mineral rights and land consist of the following as of
December 31,
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
Land
|
|
$
|
13,261
|
|
|
$
|
871
|
|
Mineral rights
|
|
|
131,820
|
|
|
|
74,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
145,081
|
|
|
|
75,591
|
|
Less: accumulated depletion
|
|
|
3,841
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
141,240
|
|
|
$
|
75,591
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
RISK
MANAGEMENT AND CONCENTRATIONS
|
The Partnerships operations are concentrated in Western
Kentucky, and a disruption within that geographic region could
adversely impact the Partnerships performance.
All of the Partnerships revenues are attributable to coal
royalty revenues earned from AE. AEs lack of a diverse
customer base may impact the Partnerships overall credit
risk, either positively or negatively, in that it may be
adversely affected by changes in economic or other conditions.
|
|
6.
|
RELATED
PARTY TRANSACTIONS
|
At December 31, 2011 and 2010, $52,827 and $15,017,
respectively, of related party other receivables remained net of
payables of $27,127 and $1,304, respectively, to AE and ACC for
expenses paid on behalf of the Partnership. Also, AE charged the
Partnership $720, $700, and $36 representing an allocated cost
for shared accounting and administrative services provided
during the years ended December 31, 2011, 2010, and 2009,
respectively. These amounts do not contain formal payment terms
and are not expected to be paid within the next year; therefore,
they are classified as long-term receivables.
On November 30, 2009, the Partnership advanced $11,000 and
in 2010 an additional $33,100 to AE under certain promissory
notes (the Notes) to enable AE to make scheduled payments due on
its debt and interest obligations related to its purchase of
land and mineral rights. This amount has been recorded within
related- party notes receivable. The Notes accrue interest at
the greater of 3% per annum or 7% of the sales price for coal
sold from certain properties specified in the Notes. The
interest income for the years ended December 31, 2011,
2010, and 2009, was $1,009, $4,209, and $161, respectively. In
connection with the notes receivable, AE granted the Partnership
the option to acquire an undivided interest in certain of the
land and mineral reserve then held by AE in satisfaction of the
loans the Partnership had made to AE. This option vests upon AE
repaying its notes payable to third parties in full.
On February 9, 2011, AE entered into a new credit agreement
and used the proceeds to repay its outstanding notes payable to
a third party. As a result of the repayment, the Partnership
exercised its option to acquire an undivided interest in certain
of AEs land and mineral reserves. In connection with that
exercise, the Partnership paid AE an additional $5,000 and
agreed to offset $12,000 in accrued advance royalty payments
owed by AE to the Partnership. Through these transactions, the
Partnership acquired a 39.45% undivided interest as a joint
tenant in common with AE in certain of its land and coal
reserves. The aggregate amount paid to acquire the interest in
these reserves was the equivalent of approximately $69,491. In
addition, AE entered into lease agreements with the Partnership
pursuant to which the Partnership granted AE leases to its
39.45% undivided interest in the mining properties described
above and licenses to mine and sell coal from 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,
F-10
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
December 31, 2011
unless either party elects not to renew or such agreement is
terminated. Under the terms of these agreements, AE is obligated
to pay the Partnership a production royalty equal to 7% of the
sales price of the coal which AE mines from the
Partnerships properties. In addition, AE has agreed to
indemnify the Partnership from and against any and all claims,
damages, demands, expenses, fines, liabilities, taxes and any
other losses related in any way to AEs mining operations
on such premises, and to reclaim the surface lands on such
premises in accordance with applicable federal, state and local
laws.
On October 11, 2011, AE and its wholly owned subsidiaries,
Western Diamond and Western Land, entered into a Royalty
Deferment and Option Agreement with the Partnerships
wholly owned subsidiaries, Western Mineral Holdings, LLC (WMD)
and Ceralvo Holdings, LLC (CVH). Pursuant to this agreement, WMD
and CVH agreed to grant to AE and its affiliates the option to
defer payment of their pro rata share of the 7% production
royalty earned on the 39.45% undivided interest in mineral
reserves acquired. In consideration for the granting of the
option to defer these payments, AE and its affiliates granted to
WMD the option to acquire an additional partial undivided
interest in certain of the mineral reserves held by AE in
Muhlenberg and Ohio Counties by engaging in a financing
arrangement, under which AE and its affiliates would satisfy
payment of any deferred fees by selling part of their interest
in the aforementioned coal reserves. The Royalty Deferment and
Option Agreement is effective as of February 9, 2011. As of
December 31, 2011, deferred royalties from AE totaled
$7,167, which were included as a component of related-party
other receivables, net in the consolidated balance sheet.
On February 9, 2011, the Partnership also entered into a
lease and sublease agreement with AE relating to the Elk Creek
Reserves and granted AE a license to mine coal on those
properties. The terms of this agreement mirror those of the
lease agreements described above. Under a previous coal mining
sublease agreement between the Partnership and AE, the
Partnership received minimum advanced royalties of $1,600 in
2009 and an additional $10,400 in December 2010, which was
initially recorded as a non-current related-party other
receivable and deferred income. The advance royalty was recorded
as a liability on the consolidated balance sheet and is being
recognized as income as the royalties are earned. Under the
agreement, production royalties from coal mined on the Elk Creek
Reserves owed by AE shall be applied and recoupable against the
previously paid advance royalty payments. As discussed above,
the Partnership exercised an option to acquire an undivided
interest in a portion of certain reserves of AE. As part of this
transaction, the advance minimum royalty owed to the Partnership
was forgiven and included as additional proceeds in the purchase
of land and mineral reserves. As mining of the Elk Creek
Reserves commenced in 2011, total production royalties earned in
2011 totaled $622 resulting in unearned advanced royalties to be
recouped as of December 31, 2011 of $11,378.
On December 29, 2011, the Partnership entered into a
Membership Interest Purchase Agreement with AE pursuant to which
AE agreed to sell to the Partnership, indirectly through
contribution of a partial undivided interest in certain land and
mineral reserves to a limited liability company and transfer of
AEs membership interests in such limited liability
company, an additional partial undivided interest in reserves
controlled by AE. In exchange for AEs agreement to sell a
partial undivided interest in those reserves, the Partnership
paid AE $20,000. In addition to the cash paid, certain amounts
due the Partnership totaling $5,700 were forgiven, which
resulted in aggregate consideration of $25,700. This transaction
is expected to close in March 2012, whereby AE will transfer an
11.4% undivided interest in certain of its land and mineral
reserves to the Partnership. The newly transferred mineral
reserves will be leased back to AE under the agreement entered
into in February 2011 at the same terms.
In connection with the new credit agreement entered into by AE,
which consists of a $100,000 term loan (the Senior Secured Term
Loan) and a $50,000 revolving credit facility (the Senior
Secured Revolving Credit
F-11
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
December 31, 2011
Facility), the Partnership has agreed to be a co-borrower under
the Senior Secured Term Loan and a guarantor under both the
Senior Secured Term Loan and Senior Secured Revolving Credit
Facility, and substantially all of its assets are pledged as
collateral. Under the terms of the new credit agreement, without
the consent of all lenders (if there are fewer than three
lenders at the time of any dividend or distribution) or the
lenders having more than 50% of the aggregate commitments (if
there are three or more lenders at the time of any dividend or
distribution) under that facility, ARP is currently prohibited
from making dividend payments or other distributions to its unit
holders in excess of $5,000 per year and $10,000 in aggregate,
except for dividends or other distributions in amounts necessary
to enable unit holders to pay anticipated income tax liabilities
arising from their ownership interests in the Partnership until
February 9, 2016, the date on which the credit agreement
matures. In exchange, AE has agreed to pay the Partnership a
credit support fee equal to 1% of the weighted average
outstanding balance under the credit agreement, which can be as
much as $150,000. As of December 31, 2011, the principal
amount outstanding under the credit agreement was $140,000 and
the credit support fee earned by the Partnership for the year
ended December 31, 2011 was $1,150.
The Partnership currently has no equipment or facility leases as
of December 31, 2011 and 2010.
No distributions have been made to any of the members of ARP or
any of its subsidiaries. On January 17, 2011, additional
capital of $5,000 was contributed by the limited partners of ARP
in exchange for 50,000 common units. The cash contribution was
used to acquire an undivided interest in the land and mineral
reserves of AE. See Note 6 for further discussion.
On December 28, 2011, the Partnership sold 200,000
newly-created Series A Convertible Preferred Units of
limited partner interest (the Preferred Units) to certain
investment funds managed by Yorktown pursuant to a certificate
of designation for cash consideration totaling $20,000. The
preferred unitholders are not entitled to dividends. In
addition, the Preferred Units convert into common units of the
Partnership upon the consummation of an initial public offering
(IPO). Upon the completion of an IPO, the Preferred Units
convert to common units equal to $20,000 divided by the IPO
Price, as defined. Proceeds from the issuance of the Preferred
Units were used to acquire an additional undivided interest in
certain land and mineral reserves of AE (see Note 6).
|
|
9.
|
COMMITMENTS
AND CONTINGENCIES
|
The Partnership 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. No violations with monetary penalties have been
assessed upon the Partnership.
Periodically, there may be various claims against the
Partnership arising from the normal course of business. In the
opinion of management, the resolution of these matters will not
have a material adverse effect on the Partnerships
consolidated financial statements.
|
|
10.
|
UNIT-BASED
COMPENSATION
|
On October 1, 2011, the Partnership granted 42,500
restricted units to certain executives officers of AE who manage
the operations of the Partnership. The restricted units vest on
the earlier of March 31, 2012 or
F-12
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
December 31, 2011
the occurrence of a liquidity event, which includes, among other
things, the public offering of units issued by the Partnership.
In addition, pursuant to Section 83(b) of the Internal
Revenue Code, the grantees are required to realize income for
federal income tax purposes equal to the fair market value of
the restricted units on the grant date. Once such election is
made, the award allows for the immediate vesting and redemption
of a portion of restricted units, valued at the fair market
value of such restricted units at the date of redemption, to
satisfy any tax obligation of the grantee. The fair value of
restricted units is equal to the fair market value of the
Partnerships common units at the date of grant and is
amortized to expense ratably over the vesting period, net of
forfeitures. Because ARPs common units are not publicly
traded, the Partnership estimated the fair market value based on
multiple valuation methods through the use of a third party
specialist. The total fair value of the grants, which equaled
$5,823, will be expensed ratably through March 31, 2012, as
this is the most probable vesting date. As of December 31,
2011, unearned compensation of $2,912 will be recognized over
the remaining vesting period of the outstanding restricted units.
Information regarding restricted unit activity and
weighted-average grant date fair value follows for
the year ended December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
Restricted Units
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant Date
|
|
|
|
Units
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
Outstanding at January 1
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
42.5
|
|
|
|
137.00
|
|
Vested
|
|
|
|
|
|
|
|
|
Canceled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31
|
|
|
42.5
|
|
|
|
137.00
|
|
|
|
|
|
|
|
|
|
|
F-13
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
December 31, 2011
The computation of basic and diluted earnings per common unit is
as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
Net income (loss)
|
|
$
|
2,341
|
|
|
$
|
3,332
|
|
|
$
|
(1,894
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest in net income (loss)
|
|
|
9
|
|
|
|
15
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocable to limited partners
|
|
$
|
2,332
|
|
|
$
|
3,317
|
|
|
$
|
(1,878
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average number of limited partner units
outstanding
|
|
|
1,339
|
|
|
|
1,121
|
|
|
|
716
|
|
Effect of dilutive securities
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average number of limited partner units
outstanding
|
|
|
1,345
|
|
|
|
1,121
|
|
|
|
716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.74
|
|
|
$
|
2.96
|
|
|
$
|
(2.62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.73
|
|
|
$
|
2.96
|
|
|
$
|
(2.62
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The preferred units have been excluded from the calculation of
the diluted weighted average number of limited partner units
outstanding for the year ended December 31, 2011 as they
are contingently convertible upon the closing of an initial
public offering. As of December 31, 2010 and 2009, there
were no unvested restricted stock awards or convertible
preferred units outstanding.
F-14
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2012
|
|
|
2011
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
155
|
|
|
$
|
155
|
|
Other current assets
|
|
|
496
|
|
|
|
464
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
651
|
|
|
|
619
|
|
Mineral rights, net and land
|
|
|
165,386
|
|
|
|
141,240
|
|
Related party other receivables, net
|
|
|
|
|
|
|
25,700
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
166,037
|
|
|
$
|
167,559
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Other non-current liabilities
|
|
$
|
10,420
|
|
|
$
|
11,378
|
|
Related party other payables, net
|
|
|
339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
10,759
|
|
|
|
11,378
|
|
Partners equity:
|
|
|
|
|
|
|
|
|
Series A Convertible Preferred Units (200,000 units
issued and outstanding as of March 31, 2012 and
December 31, 2011, respectively)
|
|
|
20,000
|
|
|
|
20,000
|
|
Limited partners interest (1,366,735 and
1,342,000 units issued and outstanding as of March 31,
2012 and December 31, 2011, respectively
|
|
|
134,877
|
|
|
|
135,775
|
|
General partners interest
|
|
|
401
|
|
|
|
406
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
155,278
|
|
|
|
156,181
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
166,037
|
|
|
$
|
167,559
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-15
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2012
|
|
|
2011
|
|
|
|
(Amounts in thousands, except per unit amounts)
|
|
|
Revenue
|
|
$
|
3,081
|
|
|
$
|
1,238
|
|
Costs and Expenses:
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
1,555
|
|
|
|
614
|
|
Related-party service expense
|
|
|
188
|
|
|
|
180
|
|
Other operating, general, and administrative costs
|
|
|
63
|
|
|
|
8
|
|
Unit-based compensation expense
|
|
|
2,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(1,636
|
)
|
|
|
436
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
|
|
|
|
1,009
|
|
Other income, net
|
|
|
256
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(1,380
|
)
|
|
$
|
1,607
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to:
|
|
|
|
|
|
|
|
|
General Partner
|
|
$
|
(5
|
)
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
Limited Partner
|
|
$
|
(1,375
|
)
|
|
$
|
1,601
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income (loss) per limited partner unit
|
|
$
|
(1.02
|
)
|
|
$
|
1.20
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-16
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2012
|
|
|
2011
|
|
|
|
(Amounts in thousands, except per unit amounts)
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(1,380
|
)
|
|
$
|
1,607
|
|
Adjustments to reconcile net income to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depletion
|
|
|
1,555
|
|
|
|
614
|
|
Unit compensation expense
|
|
|
2,911
|
|
|
|
|
|
Change in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Other current assets
|
|
|
(33
|
)
|
|
|
|
|
Other non-current liabilities
|
|
|
(958
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities:
|
|
|
2,095
|
|
|
|
2,221
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
Related-party notes receivable
|
|
|
|
|
|
|
48,470
|
|
Related-party other receivables
|
|
|
26,039
|
|
|
|
13,800
|
|
Investment in mineral reserves and land
|
|
|
(25,700
|
)
|
|
|
(69,491
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
|
339
|
|
|
|
(7,221
|
)
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
Partners capital contributions
|
|
|
|
|
|
|
5,000
|
|
Repurchase of common units relinquished for tax withholding
|
|
|
(2,434
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
(2,434
|
)
|
|
|
5,000
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
|
|
|
|
|
|
Cash, at the beginning of the period
|
|
|
155
|
|
|
|
155
|
|
|
|
|
|
|
|
|
|
|
Cash, at the end of the period
|
|
$
|
155
|
|
|
$
|
155
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2012
|
|
|
|
|
|
|
|
|
|
Series A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Series A
|
|
|
|
|
|
Limited
|
|
|
Limited
|
|
|
General
|
|
|
|
|
|
|
Preferred
|
|
|
|
|
|
Partners
|
|
|
Partners
|
|
|
Partners
|
|
|
|
|
|
|
Units
|
|
|
Common Units
|
|
|
Interest
|
|
|
Interest
|
|
|
Interest
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
Balance at December 31, 2011
|
|
|
200,000
|
|
|
|
1,342,000
|
|
|
$
|
20,000
|
|
|
$
|
135,775
|
|
|
$
|
406
|
|
|
$
|
156,181
|
|
Unit compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,911
|
|
|
|
|
|
|
|
2,911
|
|
Units issued under incentive plan
|
|
|
|
|
|
|
42,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of common units relinquished for tax withholding
|
|
|
|
|
|
|
(17,765
|
)
|
|
|
|
|
|
|
(2,434
|
)
|
|
|
|
|
|
|
(2,434
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,375
|
)
|
|
|
(5
|
)
|
|
|
(1,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at March 31, 2012
|
|
|
200,000
|
|
|
|
1,366,735
|
|
|
$
|
20,000
|
|
|
$
|
134,877
|
|
|
$
|
401
|
|
|
$
|
155,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited condensed consolidated
financial statements.
F-18
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per ton amounts)
March 31, 2012
|
|
1.
|
DESCRIPTION
OF BUSINESS AND ENTITY STRUCTURE
|
In September 2011, Elk Creek, L.P. changed its name to Armstrong
Resource Partners, L.P. (ARP or the Partnership). The majority
of ARPs outstanding limited partnership interests are
owned by investment funds managed by Yorktown Partners LLC
(Yorktown). ARP is a Delaware limited partnership managed by the
general partner, Elk Creek GP, LLC (ECGP or the General
Partner), which is a wholly owned subsidiary of Armstrong
Energy, Inc. (formerly Armstrong Land Company) (AE or the
ultimate parent corporation).
ARP is headquartered in St. Louis, Missouri, with reserve
interests in Western Kentucky. As of March 31, 2012 and
2011, ARP had no employees and paid AE for shared services
related to accounting, finance, and management.
ARP and subsidiaries (the Partnership, which includes all
subsidiaries) commenced business on March 31, 2008
(inception), for the purpose of owning coal production assets.
At inception, the General Partner held a 2% interest in ARP,
which has been reduced to approximately 0.4% at March 31,
2012, with additional capital contributions by the limited
partners.
The Partnership owns certain mineral reserves outright, as well
as, has an undivided interest as a joint tenant in common in
certain coal reserves of AE. The Partnership does not currently
intend to operate its coal assets and has subleased the mining
rights to Armstrong Coal Company (ACC), a subsidiary of AE, in
return for royalty payments discussed further in Note 6.
The Partnership, therefore, generates income in the form of
royalties from production/sale of coal mined from its properties
and incurs expenses in the form of depletion, mining related
taxes, administrative expenses, and royalties due to landowners.
|
|
2.
|
NEWLY
ADOPTED ACCOUNTING STANDARDS AND 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 Partnership. The adoption of this guidance did not
impact the Partnerships 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 Partnership. Early adoption is not
permitted. The adoption of this amendment did not materially
affect the Partnerships consolidated financial statements.
|
|
3.
|
AMENDMENT
TO THE PARTNERSHIP AGREEMENT
|
The partners of ARP entered into the Amended and Restated
Agreement of Limited Partnership of Armstrong Resource Partners,
L.P. dated October 1, 2011 (the ARP LPA), which, among
other things, allows Yorktown, the Partnerships largest
unit holder, to remove ECGP as general partner of ARP or
otherwise cause a change of control of ARP without the consent
of ECGP or the consent of the holders of ARPs equity
units. The ARP LPA is effective as of October 1, 2011.
F-19
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
March 31, 2012
|
|
4.
|
MINERAL
RIGHTS AND LAND
|
On February 9, 2011 and March 30, 2012, the
Partnership acquired a 39.45% and 11.36% undivided interest in
certain land and mineral reserves of AE for the equivalent of
$69,491 and $25,700, respectively (see Note 6).
Mineral rights and land consist of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2012
|
|
|
December 31, 2011
|
|
|
Land
|
|
$
|
17,969
|
|
|
$
|
13,261
|
|
Mineral rights
|
|
|
152,813
|
|
|
|
131,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170,782
|
|
|
|
145,081
|
|
Less: accumulated depletion
|
|
|
5,396
|
|
|
|
3,841
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
165,386
|
|
|
$
|
141,240
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
RISK
MANAGEMENT AND CONCENTRATIONS
|
The Partnerships operations are concentrated in Western
Kentucky, and a disruption within that geographic region could
adversely impact the Partnerships performance.
All of the Partnerships revenues are attributable to coal
royalty revenues earned from AE. AEs lack of a diverse
customer base may impact the Partnerships overall credit
risk, either positively or negatively, in that it may be
adversely affected by changes in economic or other conditions.
|
|
6.
|
RELATED
PARTY TRANSACTIONS
|
At March 31, 2012 and December 31, 2011, $2,405 and
$52,827, respectively, of related party other receivables
remained net of payables of $2,744 and $27,127, respectively, to
AE and ACC for expenses paid on behalf of the Partnership. Also,
AE charged the Partnership $188 and $180 representing an
allocated cost for shared accounting and administrative services
provided during the three months ended March 31, 2012 and
2011, respectively. These amounts do not contain formal payment
terms and are not expected to be paid within the next year;
therefore, they are classified as non-current.
On November 30, 2009, the Partnership advanced $11,000 and
in 2010 an additional $33,100 to AE under certain promissory
notes (the Notes) to enable AE to make scheduled payments due on
its debt and interest obligations related to its purchase of
land and mineral rights. The Notes accrued interest at the
greater of 3% per annum or 7% of the sales price for coal sold
from certain properties specified in the Notes. The interest
income for the three months ended March 31, 2011 was
$1,009. In connection with the notes receivable, AE granted the
Partnership the option to acquire an undivided interest in
certain of the land and mineral reserve then held by AE in
satisfaction of the loans the Partnership had made to AE. This
option vested upon AE repaying its notes payable to third
parties in full.
On February 9, 2011, AE entered into a new credit agreement
and used the proceeds to repay its outstanding notes payable to
a third party. As a result of the repayment, the Partnership
exercised its option to acquire an undivided interest in certain
of AEs land and mineral reserves. In connection with that
exercise, the Partnership paid AE an additional $5,000 and
agreed to offset $12,000 in accrued advance royalty payments
owed by AE to the Partnership. Through these transactions, the
Partnership acquired a 39.45% undivided interest as a joint
tenant in common with AE in certain of its land and coal
reserves. The aggregate amount paid to acquire the interest in
these reserves was the equivalent of approximately $69,491. In
addition,
F-20
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
March 31, 2012
AE entered into lease agreements with the Partnership pursuant
to which the Partnership granted AE leases to its 39.45%
undivided interest in the mining properties described above and
licenses to mine and sell coal from 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. Under the terms of these agreements, AE
is obligated to pay the Partnership a production royalty equal
to 7% of the sales price of the coal which AE mines from the
Partnerships properties. In addition, AE has agreed to
indemnify the Partnership from and against any and all claims,
damages, demands, expenses, fines, liabilities, taxes and any
other losses related in any way to AEs mining operations
on such premises, and to reclaim the surface lands on such
premises in accordance with applicable federal, state and local
laws.
On October 11, 2011, AE and its wholly owned subsidiaries,
Western Diamond and Western Land, entered into a Royalty
Deferment and Option Agreement with the Partnerships
wholly owned subsidiaries, Western Mineral Holdings, LLC (WMD)
and Ceralvo Holdings, LLC (CVH). Pursuant to this agreement, WMD
and CVH agreed to grant to AE and its affiliates the option to
defer payment of their pro rata share of the 7% production
royalty earned on the 39.45% undivided interest in mineral
reserves acquired. In consideration for the granting of the
option to defer these payments, AE and its affiliates granted to
WMD the option to acquire an additional partial undivided
interest in certain of the mineral reserves held by AE in
Muhlenberg and Ohio Counties by engaging in a financing
arrangement, under which AE and its affiliates would satisfy
payment of any deferred fees by selling part of their interest
in the aforementioned coal reserves. The Royalty Deferment and
Option Agreement is effective as of February 9, 2011. For
the three months ended March 31, 2012, deferred royalties
from AE totaled $2,123, which were included as a component of
related-party other payables, net in the consolidated balance
sheet.
On February 9, 2011, the Partnership also entered into a
lease and sublease agreement with AE relating to the Elk Creek
Reserves and granted AE a license to mine coal on those
properties. The terms of this agreement mirror those of the
lease agreements described above. Under a previous coal mining
sublease agreement between the Partnership and AE, the
Partnership received minimum advanced royalties of $1,600 in
2009 and an additional $10,400 in December 2010, which was
initially recorded as a non-current related-party other
receivable and deferred income. The advance royalty was recorded
as a liability on the consolidated balance sheet and is being
recognized as income as the royalties are earned. Under the
agreement, production royalties from coal mined on the Elk Creek
Reserves owed by AE shall be applied and recoupable against the
previously paid advance royalty payments. As discussed above,
the Partnership exercised an option to acquire an undivided
interest in a portion of certain reserves of AE. As part of this
transaction, the advance minimum royalty owed to the Partnership
was forgiven and included as additional proceeds in the purchase
of land and mineral reserves. As mining of the Elk Creek
Reserves commenced in 2011, total production royalties earned in
the three months ended March 31, 2012 and 2011 totaled $958
and zero, respectively, resulting in unearned advanced royalties
to be recouped as of March 31, 2012 of $10,420.
On December 29, 2011, the Partnership entered into a
Membership Interest Purchase Agreement with AE pursuant to which
AE agreed to sell to the Partnership, indirectly through
contribution of a partial undivided interest in certain land and
mineral reserves to a limited liability company and transfer of
AEs membership interests in such limited liability
company, an additional partial undivided interest in reserves
controlled by AE. In exchange for AEs agreement to sell a
partial undivided interest in those reserves, the Partnership
paid AE $20,000. In addition to the cash paid, certain amounts
due the Partnership totaling $5,700 were forgiven, which
resulted in aggregate consideration of $25,700. This transaction
closed on March 30, 2012, whereby AE transferred an 11.36%
undivided interest in certain of its land and mineral reserves
to the Partnership. The newly transferred mineral reserves were
leased back to AE under the agreement entered into in February
2011
F-21
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
March 31, 2012
at the same terms. In addition, production royalties earned from
the newly acquired mineral reserves will be deferred under the
Royalty Deferment and Option Agreement.
In connection with the new credit agreement entered into by AE,
which consists 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 Partnership has agreed
to be a co-borrower under the Senior Secured Term Loan and a
guarantor under both the Senior Secured Term Loan and Senior
Secured Revolving Credit Facility, and substantially all of its
assets are pledged as collateral. Under the terms of the new
credit agreement, without the consent of all lenders (if there
are fewer than three lenders at the time of any dividend or
distribution) or the lenders having more than 50% of the
aggregate commitments (if there are three or more lenders at the
time of any dividend or distribution) under that facility, ARP
is currently prohibited from making dividend payments or other
distributions to its unit holders in excess of $5,000 per year
and $10,000 in aggregate, except for dividends or other
distributions in amounts necessary to enable unit holders to pay
anticipated income tax liabilities arising from their ownership
interests in the Partnership until February 9, 2016, the
date on which the credit agreement matures. In exchange, AE has
agreed to pay the Partnership a credit support fee equal to 1%
of the weighted average outstanding balance under the credit
agreement, which can be as much as $150,000. As of
March 31, 2012, the principal amount outstanding under the
credit agreement was $120,000 and the credit support fee earned
by the Partnership for the three months ended March 31,
2012 and 2011 was $258 and $137, respectively.
No distributions have been made to any of the members of ARP or
any of its subsidiaries. On January 17, 2011, additional
capital of $5,000 was contributed by the limited partners of ARP
in exchange for 50,000 common units. The cash contribution was
used to acquire an undivided interest in the land and mineral
reserves of AE. See Note 6 for further discussion.
|
|
8.
|
FAIR
VALUE OF FINANCIAL INSTRUMENTS
|
The Partnership 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 Partnership 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 Partnerships financial instruments consist of cash and
cash equivalents, other non-current receivables, and other
non-current liabilities. The carrying amounts of these financial
instruments approximate fair value due to the short maturity or
financial nature of the balances.
|
|
9.
|
COMMITMENTS
AND CONTINGENCIES
|
The Partnership 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. No violations with monetary penalties have been
assessed upon the Partnership.
F-22
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
March 31, 2012
Periodically, there may be various claims against the
Partnership arising from the normal course of business. In the
opinion of management, the resolution of these matters will not
have a material adverse effect on the Partnerships
consolidated financial statements.
|
|
10.
|
UNIT-BASED
COMPENSATION
|
On October 1, 2011, the Partnership granted 42,500
restricted units to certain executives officers of AE who manage
the operations of the Partnership. The restricted units vested
on March 31, 2012. In addition, pursuant to
Section 83(b) of the Internal Revenue Code, the grantees
are required to realize income for federal income tax purposes
equal to the fair market value of the restricted units on the
grant date. Once such election is made, the award allows for the
immediate vesting and redemption of a portion of restricted
units, valued at the fair market value of such restricted units
at the date of redemption, to satisfy any tax obligation of the
grantee. During the three months ended March 31, 2012, the
Partnership repurchased 17,765 common units that were
relinquished by the grantees for tax withholdings for $2,434.
The Partnership recognized unit compensation expense of $2,911
during the three months ended March 31, 2012.
Information regarding restricted unit activity and
weighted-average grant date fair value follows for
the three months ended March 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
Restricted Units
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant Date
|
|
|
|
Units
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
Outstanding at January 1
|
|
|
42.5
|
|
|
$
|
137.00
|
|
Granted
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(42.5
|
)
|
|
|
137.00
|
|
Canceled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-23
Armstrong
Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(Dollars in thousands, except per ton amounts)
March 31, 2012
The computation of basic and diluted earnings per common unit is
as follows (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2012
|
|
|
2011
|
|
|
Net income (loss)
|
|
$
|
(1,380
|
)
|
|
$
|
1,607
|
|
Less:
|
|
|
|
|
|
|
|
|
General partner interest in net income (loss)
|
|
|
(5
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocable to limited partners
|
|
$
|
(1,375
|
)
|
|
$
|
1,601
|
|
|
|
|
|
|
|
|
|
|
Basic weighted average number of limited partner units
outstanding
|
|
|
1,342
|
|
|
|
1,331
|
|
Effect of dilutive securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average number of limited partner units
outstanding
|
|
|
1,342
|
|
|
|
1,331
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per limited partner unit:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.02
|
)
|
|
$
|
1.20
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
(1.02
|
)
|
|
$
|
1.20
|
|
|
|
|
|
|
|
|
|
|
The preferred units have been excluded from the calculation of
the diluted weighted average number of limited partner units
outstanding for the three months ended March 31, 2012 as
they are contingently convertible upon the closing of an initial
public offering. As of March 31, 2012 and 2011, there were
no unvested restricted stock awards outstanding.
F-24
ARMSTRONG RESOURCE PARTNERS,
L.P.
Common
Units
of
Limited Partnership
Interest
PROSPECTUS
Raymond
James
FBR
Stifel
Nicolaus Weisel
,
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 Resource Partners, L.P. (the Partnership)
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
|
|
$
|
2,521.20
|
|
FINRA filing fee
|
|
|
2,700.00
|
|
Blue sky fees and expenses
|
|
|
5,000.00
|
|
Nasdaq listing fee
|
|
|
125,000.00
|
|
Printing and engraving expenses
|
|
|
135,000.00
|
|
Legal fees and expenses
|
|
|
650,000.00
|
|
Accounting fees and expenses
|
|
|
135,000.00
|
|
Transfer agent fees
|
|
|
1,500.00
|
|
Miscellaneous
|
|
|
43,278.80
|
|
|
|
|
|
|
Total
|
|
$
|
1,100,000.00
|
|
|
|
|
|
|
|
|
Item 14.
|
Indemnification
of Directors and Officers
|
The section of the prospectus entitled The Partnership
Agreement Indemnification discloses that we
will generally indemnify officers, managers and affiliates of
our general partner to the fullest extent permitted by the law
against all losses, claims, damages or similar events and is
incorporated herein by this reference. Reference is also made to
the underwriting agreement filed as an exhibit to this
registration statement, which provides for the indemnification
of the registrant and its general partner and their officers and
directors or managers, as the case may be, and any person who
controls the registrant and its general partner, including
indemnification for liabilities under the Securities Act.
Subject to any terms, conditions or restrictions set forth in
the partnership agreement,
Section 17-108
of the Delaware Revised Uniform Limited Partnership Act empowers
a Delaware limited partnership to indemnify and hold harmless
any partner or other person from and against all claims and
demands whatsoever. The general partner of the registrant
maintains directors and officers liability insurance
for the benefit of its managers and officers.
|
|
Item 15.
|
Recent
Sales of Unregistered Securities
|
In the three years preceding the filing of this registration
statement, the Partnership (f/k/a Elk Creek, L.P.) issued the
following securities that were not registered under the
Securities Act (unit amounts give effect to an assumed
7.6047-to-1 unit split to be effected prior to the effectiveness
of the registration statement of which this prospectus forms a
part.):
On December 19, 2008, the Partnership issued a 54.54%
limited partnership interest to Yorktown Energy Partners VIII,
L.P. in consideration of $30,000,000, which interest was later
reclassified into 2,281,408 units of partnership interest
for no additional consideration. This partnership interest was
issued in a transaction exempt from the registration
requirements of the Securities Act under Section 4(2) of
the Securities Act.
On June 26, 2009, the Partnership issued an additional
16.26% limited partnership interest to Yorktown Energy Partners
VIII, L.P. in consideration of $30,600,000, which interest was
later reclassified into 2,327,036 units of partnership
interest for no additional consideration. This partnership
interest was issued in a transaction exempt from the
registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
II-1
On November 2, 2009, the Partnership issued an additional
3.32% limited partnership interest to Yorktown Energy Partners
VIII, L.P. in consideration of $11,000,000, which interest was
later reclassified into 836,516 units of partnership
interest for no additional consideration. This partnership
interest was issued in a transaction exempt from the
registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
On March 31, 2010, the Partnership issued an additional
2.32% limited partnership interest to Yorktown Energy Partners
VIII, L.P. in consideration of $9,500,000, which interest was
later reclassified into 722,446 units of partnership
interest for no additional consideration. This partnership
interest was issued in a transaction exempt from the
registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
On May 26, 2010, the Partnership issued an additional 2.5%
limited partnership interest to Yorktown Energy Partners VIII,
L.P. in consideration of $12,600,000, which interest was later
reclassified into 958,191 units of partnership interest for
no additional consideration. This partnership interest was
issued in a transaction exempt from the registration
requirements of the Securities Act under Section 4(2) of
the Securities Act.
On November 9, 2010, the Partnership issued an additional
1.78% limited partnership interest to Yorktown Energy Partners
VIII, L.P. in consideration of $11,000,000, which interest was
later reclassified into 836,516 units of partnership
interest for no additional consideration. This partnership
interest was issued in a transaction exempt from the
registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
On January 9, 2011, the Partnership issued an additional
0.72% limited partnership interest to Yorktown Energy Partners
VIII, L.P. in consideration of $5,000,000, which interest was
later reclassified into 380,235 units of partnership
interest for no additional consideration. This partnership
interest was issued in a transaction exempt from the
registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
On October 1, 2011, the Partnership issued 323,199
restricted units of limited partnership interest to certain of
its employees. These units were issued in a transaction exempt
from the registration requirements of the Securities Act
pursuant to Rule 701, promulgated under the Securities Act.
On December 22, 2011, the Partnership issued 200,000
Series A convertible preferred units of limited partner
interest to Yorktown Energy Partners IX, L.P. in consideration
of $20,000,000. These units 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.
Not applicable.
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
II-2
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.
The registrant undertakes to send to each Limited Partner at
least on an annual basis a detailed statement of any
transactions with the General Partner or its affiliates, and of
fees, commissions, compensation and other benefits paid, or
accrued to the General Partner or its affiliates for the fiscal
year completed, showing the amount paid or accrued to each
recipient and the services performed.
II-3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, Armstrong Resource Partners, L.P. 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 May 30, 2012.
ARMSTRONG RESOURCE PARTNERS, L.P.
|
|
|
|
By:
|
Elk Creek GP, LLC,
its General Partner
|
|
|
By:
|
/s/ Martin
D. Wilson
|
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 May 30, 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 Limited Partnership of Elk Creek, L.P.
|
|
3
|
.2**
|
|
Certificate of Amendment to Certificate of Limited Partnership
of Elk Creek, L.P.
|
|
3
|
.3**
|
|
Amended and Restated Agreement of Limited Partnership, dated
October 1, 2011.
|
|
3
|
.4**
|
|
Amendment No. 1 to Amended and Restated Agreement of
Limited Partnership of Armstrong Resource Partners, L.P.
effective as of January 1, 2012.
|
|
3
|
.5**
|
|
Form of Second Amended and Restated Agreement of Limited
Partnership.
|
|
3
|
.6**
|
|
Amended and Restated Designation of Series A Convertible
Preferred Units of Armstrong Resource Partners, L.P.
|
|
5
|
.1**
|
|
Form of Opinion of Armstrong Teasdale LLP.
|
|
8
|
.1**
|
|
Form of Opinion of Armstrong Teasdale LLP relating to tax
matters.
|
|
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.
|
|
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.
|
II-5
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
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**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 10, dated as of September 20, 2011.
|
|
10
|
.18**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 11, dated as of November 1, 2011.
|
|
10
|
.19**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 12, dated as of November 28, 2011.
|
|
10
|
.20**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 13, dated as of December 1, 2011.
|
|
10
|
.21**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 14, dated as of December 8, 2011.
|
|
10
|
.22**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 15, dated as of December 28, 2011.
|
|
10
|
.23**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 16, dated as of February 21, 2012.
|
|
10
|
.24**
|
|
Contract for Purchase and Sale of Coal by and between Tennessee
Valley Authority and Armstrong Coal Company, Inc., dated as of
September 10, 2008.
|
|
10
|
.25**
|
|
Tennessee Valley Coal Acquisition and Supply Contract Supplement
No. 1, dated as of March 30, 2009.
|
|
10
|
.26**
|
|
Tennessee Valley Coal Acquisition and Supply Contract Supplement
No. 2, dated as of October 9, 2009.
|
|
10
|
.27**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 3, dated as of October 15, 2010.
|
|
10
|
.28**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 4, dated as of July 8, 2011.
|
|
10
|
.29**
|
|
Tennessee Valley Coal Supply & Origination Contract
Supplement No. 5, dated as
of ,
201 .
|
|
10
|
.30**
|
|
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
|
.31**
|
|
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
|
.32**
|
|
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
|
.33**
|
|
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
|
.34**
|
|
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
|
.35**
|
|
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
|
.36**
|
|
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.
|
II-6
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.37**
|
|
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
|
.38**
|
|
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
|
.39**
|
|
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
|
.40**
|
|
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
|
.41**
|
|
Letter Agreement between Armstrong Land Company, LLC and J.
Richard Gist, dated as of September 14, 2009.
|
|
10
|
.42**
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
J. Richard Gist, dated as of October 1, 2011.
|
|
10
|
.43**
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
J. Hord Armstrong, III, dated as of October 1, 2011.
|
|
10
|
.44**
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
Martin D. Wilson, dated as of October 1, 2011.
|
|
10
|
.45**
|
|
Employment Agreement by and between Armstrong Coal Co. and
Kenneth E. Allen, dated as of June 1, 2007.
|
|
10
|
.46**
|
|
Employment Agreement by and between Armstrong Coal Co. and David
R. Cobb, dated as of January 19, 2007.
|
|
10
|
.47**
|
|
Employment Agreement by and between Armstrong Energy, Inc. and
Brian G. Landry, dated as of December 1, 2011.
|
|
10
|
.48**
|
|
Restricted Unit Award Agreement between Armstrong Resource
Partners, L.P. and J. Hord Armstrong, III, dated
as of October 1, 2011.
|
|
10
|
.49**
|
|
Assignment of Limited Partnership Units dated as of
January 25, 2012 by and between J. Hord Armstrong, III and
Armstrong Resource Partners, L.P.
|
|
10
|
.50**
|
|
Restricted Unit Award Agreement between Armstrong Resource
Partners, L.P. and Martin D. Wilson, dated as of October 1, 2011.
|
|
10
|
.51**
|
|
Assignment of Limited Partnership Units dated as of
January 25, 2012 by and between Martin D. Wilson and
Armstrong Resource Partners, L.P.
|
|
10
|
.52**
|
|
Form of Armstrong Energy, Inc. Director Indemnification
Agreement.
|
|
10
|
.53**
|
|
Armstrong Energy, Inc. 2011 Long-Term Incentive Plan.
|
|
10
|
.54**
|
|
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
|
.55**
|
|
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
|
.56**
|
|
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
|
.57**
|
|
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
|
.58**
|
|
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
|
.59**
|
|
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
|
.60**
|
|
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.
|
II-7
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.61**
|
|
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
|
.62
|
|
Lease and Sublease Agreement between Armstrong Coal Company,
Inc. and Ceralvo Holdings, LLC, dated February 9, 2011.
|
|
10
|
.63**
|
|
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.
|
|
10
|
.64**
|
|
Lease Agreement by and between Armstrong Coal Company, Inc. and
David and Rebecca Cobb, dated August 1, 2009.
|
|
10
|
.65**
|
|
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
|
.66**
|
|
Coal Mining Lease and Sublease by and between Ceralvo Holdings,
LLC and Armstrong Coal Company, Inc., dated as of
February 9, 2011.
|
|
10
|
.67**
|
|
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.
|
|
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 Weir International, Inc.
|
|
24
|
.1**
|
|
Power of Attorney (included on signature page).
|
|
|
|
* |
|
To be filed by amendment. |
|
** |
|
Previously filed. |
|
|
|
Indicates a management contract or compensatory plan or
arrangement. |
II-8