Attached files

file filename
EX-10.9 - EX-10.9 - Armstrong Resource Partners, L.P.c65698a3exv10w9.htm
EX-23.3 - EX-23.3 - Armstrong Resource Partners, L.P.c65698a3exv23w3.htm
EX-23.2 - EX-23.2 - Armstrong Resource Partners, L.P.c65698a3exv23w2.htm
EX-10.8 - EX-10.8 - Armstrong Resource Partners, L.P.c65698a3exv10w8.htm
EX-10.10 - EX-10.10 - Armstrong Resource Partners, L.P.c65698a3exv10w10.htm
EX-10.11 - EX-10.11 - Armstrong Resource Partners, L.P.c65698a3exv10w11.htm
EX-10.14 - EX-10.14 - Armstrong Resource Partners, L.P.c65698a3exv10w14.htm
EX-10.15 - EX-10.15 - Armstrong Resource Partners, L.P.c65698a3exv10w15.htm
EX-10.13 - EX-10.13 - Armstrong Resource Partners, L.P.c65698a3exv10w13.htm
EX-10.12 - EX-10.12 - Armstrong Resource Partners, L.P.c65698a3exv10w12.htm
EX-10.16 - EX-10.16 - Armstrong Resource Partners, L.P.c65698a3exv10w16.htm
EX-10.39 - EX-10.39 - Armstrong Resource Partners, L.P.c65698a3exv10w39.htm
EX-10.51 - EX-10.51 - Armstrong Resource Partners, L.P.c65698a3exv10w51.htm
EX-10.34 - EX-10.34 - Armstrong Resource Partners, L.P.c65698a3exv10w34.htm
EX-10.27 - EX-10.27 - Armstrong Resource Partners, L.P.c65698a3exv10w27.htm
Table of Contents

As filed with the Securities and Exchange Commission on February 10, 2012
Registration Statement No. 333-177260
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Amendment No. 3
to
Form S-1
 
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
 
 
 
ARMSTRONG RESOURCE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
 
         
Delaware   1221   20-5609027
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (IRS Employer
Identification No.)
 
7733 Forsyth Boulevard, Suite 1625
St. Louis, Missouri 63105
(314) 721-8202
(Address, including zip code, and telephone number, including area code, of registrant’s 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:
 
     
David W. Braswell, Esq.
Armstrong Teasdale LLP
7700 Forsyth Boulevard, Suite 1800
St. Louis, Missouri 63105
(314) 552-6631
  D. Rhett Brandon, Esq.
Simpson Thacher & Bartlett LLP
425 Lexington Avenue
New York, New York 10017
(212) 455-2000
 
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):
 
Large accelerated filer o Accelerated filer o Non-accelerated filer þ Smaller reporting company o
(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.
 


Table of Contents

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.
 
PRELIMINARY PROSPECTUS      SUBJECT TO COMPLETION, DATED FEBRUARY 10, 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 intend to apply to list our common units on the Nasdaq Global Market (“Nasdaq”) under the symbol ‘‘ARPS.” There is no assurance that this application will be approved.
 
 
 
 
Investing in our common units involves risks. You should read the section entitled “Risk Factors” beginning on page 21 for a discussion of certain risk factors that you should consider before investing in our common units.
 
 
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.
 
 
 
 
                 
    Per Common
   
    Unit   Total
 
Public offering price
  $           $        
Underwriting discount
  $       $    
Offering proceeds to Armstrong Resource Partners, L.P. before expenses
  $       $  
 
 
To the extent the underwriters sell more than           common units, 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.
 
 
 
 
Raymond James FBR
 
Prospectus, dated          , 2012


Table of Contents

(MAP)


 

 
TABLE OF CONTENTS
 
         
    Page
 
    ii  
    1  
    22  
    49  
    51  
    52  
    53  
    54  
    56  
    60  
    62  
    70  
    80  
    112  
    129  
    130  
    133  
    138  
    141  
    142  
    153  
    155  
    175  
    177  
    182  
    182  
    182  
    182  
    183  
    F-1  
 EX-10.8
 EX-10.9
 EX-10.10
 EX-10.11
 EX-10.12
 EX-10.13
 EX-10.14
 EX-10.15
 EX-10.16
 EX-10.27
 EX-10.34
 EX-10.39
 EX-10.51
 EX-23.2
 EX-23.3
 
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


Table of Contents

 
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, 2010. In addition, we pay a subscription fee to Wood Mackenzie to obtain access to pre-prepared reports. Except with respect to payment for Weir International, Inc.’s services in this regard and the subscription fee paid to Wood Mackenzie, we did not fund and are not otherwise affiliated with any of the sources cited in this prospectus. Forward-looking information obtained from these sources is subject to the same qualifications and additional uncertainties regarding the other forward-looking statements in this prospectus.
 
Unless the context otherwise requires, the information in the prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their over-allotment option.
 
For investors outside the United States: We have not, and the underwriters have not, done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus must inform themselves, and observe any restrictions relating to, the offering of the common units of limited partnership interest and the distribution of this prospectus outside the United States.


ii


Table of Contents

 
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    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.
 
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 66 million tons of coal reserves and have a 39.45% undivided interest in approximately 138 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 99.6% 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, 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 September 30, 2011 we were owed approximately $4.1 million from Armstrong Energy.
 
We intend to use the net proceeds from this offering, plus any amount owed to us at the time of the Concurrent AE Offering (see “— Concurrent Offering”) for deferred royalty payments, to purchase an additional partial interest in the reserves in which we currently have a 39.45% interest. As a result, upon the closing of this offering, we expect to have an approximate     % undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves, which 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 Energy’s 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 Energy’s $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 Energy’s 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


1


Table of Contents

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, dated          , 2011 (the “Partnership Agreement”), Elk Creek GP has the exclusive authority to conduct, direct and manage all of our activities. By virtue of Armstrong Energy’s control of Elk Creek, GP, our results are consolidated in Armstrong Energy’s 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 the first nine months of 2011, Armstrong Energy is obligated to pay us $5.4 million 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 $0.8 million in the first nine months of 2011.
 
On October 11, 2011, we entered into an agreement with Armstrong Energy to purchase an additional partial undivided interest in substantially all of the coal reserves and real property owned by Armstrong Energy previously subject to the options exercised by Armstrong Resource Partners on February 9, 2011. We intend to use the net proceeds from this offering to purchase an additional interest in the reserves in which we currently have a 39.45% interest. As a result, upon the closing of that transaction, we expect to have a           undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves. See “Certain Relationships and Related Party Transactions — Western Diamond and Western Land Coal Reserves Sale Agreement.”


2


Table of Contents

The following table summarizes our coal reserves. All of our reserves are leased to Armstrong Energy.
 
                                                                                 
          Gross Clean Recoverable
                         
          Tons
    Net Clean Recoverable Tons
    Quality Specifications (As
 
          (Proven and Probable
    (Proven and Probable
    Received)(2)  
          Reserves)(1)     Reserves)(1)     Heat
    SO2
       
    Mining
    Proven
    Probable
          Proven
    Probable
          Value
    Content
    Ash
 
    Method(3)     Reserves     Reserves     Total     Reserves     Reserves     Total     (Btu/Lb)     (Lbs/MMBtu)     (%)  
          (In thousands)     (In thousands)                    
 
Owned Reserves
                                                                               
Elk Creek(4)
    U       56,586       9,055       65,591       56,586       9,005       65,591       11,792       4.5       7.6  
Partially Owned Reserves
                                                                               
Reserves in Active Production(5)
                                                                               
Big Run(6)
    U       2,849       242       3,091       1,124       95       1,219       11,822       4.3       7.4  
Midway
    S       24,806       3,507       28,313       9,785       1,384       11,169       11,315       4.8       10.0  
Parkway
    U       1,952       58       2,010       770       23       793       11,931       4.4       7.1  
East Fork(7)
    S       2,633       553       3,186       1,039       218       1,257       11,136       7.6       11.2  
Equality Boot
    S       23,687       1,148       24,835       9,344       454       9,798       11,587       5.7       8.8  
Lewis Creek
    S       6,650       70       6,720       2,623       28       2,651       11,420       4.0       9.5  
                                                                                 
Total Partially Owned Reserves in Active Production
            62,577       5,578       68,155       24,685       2,202       26,887                          
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       37,233 (8)     11,648       48,881 (9)     14,689       4,596       19,285       11,300       4.5       8.0  
                                                                                 
Total Additional Reserves
            54,399       15,502       69,901       21,461       6,116       27,577                          
                                                                                 
Total
            173,562       30,085       203,647       102,732       17,323       120,055                          
                                                                                 
 
 
(1) Determined as of December 31, 2010. 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 Energy’s 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) Of the approximately 65.6 million Elk Creek gross clean recoverable tons and net clean recoverable tons, approximately 62.1 million tons are owned and approximately 3.5 million tons are leased. We commenced production at the Kronos mine in September 2011.
 
(5) Reserves that are in active production as of October 1, 2011.
 
(6) Big Run ceased production in October 2011.
 
(7) Warden and Kronos pits.
 
(8) Includes 167,000 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.
 
(9) Includes 972,000 tons related to reserves for which Armstrong Energy owns or leases from us a 50% or more partial joint interest and royalties on extractions may be payable to other owners.


3


Table of Contents

 
The following table summarizes the ownership status of our reserves by mine and our lessee’s 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
          Nine Months
          Nine Months
 
    (Proven and Probable
    (Proven and Probable
    Year Ended
    Ended
    Year Ended
    Ended
 
    Reserves)(1)     Reserves)(1)     December 31,
    September 30,
    December 31,
    September 30,
 
Reserve
  Owned     Leased     Total     Owned     Leased     Total     2010     2011     2010     2011  
    (In thousands)     (In thousands)     (Tons in thousands)     Pro forma
 
                      (Tons in thousands)  
 
Owned
                                                                               
Elk Creek(3)
    62,066       3,525       65,591       62,066       3,525       65,591             9.6             9.6  
Partially Owned
                                                                               
Big Run(4)
    3,091             3,091       1,219             1,219       572.1       361.5       225.7       142.6  
Midway
    28,313             28,313       11,169             11,169       1,614.8       1,290.4       637.0       509.1  
Parkway
    312       1,698       2,010       123       670       793       1,485.9       1,165.6       586.2       459.8  
East Fork
    2,302       884       3,186       908       349       1,257       1,641.1       608.6       647.4       240.1  
Equality Boot(5)
    24,835             24,835 (6)     9,798             9,798       330.8       1,493.3       130.5       589.1  
Lewis Creek (surface)(7)
    6,720             6,720       2,651             2,651             197.0             77.1  
Total
    65,574       2,582       68,155       25,869       1,018       26,887       5,644.7       5,126.0       2,226.8       2,027.4  
 
 
(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. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.
 
(2) Determined as of December 31, 2010. 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 net production began in February 2011 and amounted to approximately 1,810,000 tons for the nine months ended September 30, 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 Energy’s coal reserves. See “Use of Proceeds.”
 
(3) Commenced production in September 2011.
 
(4) Big Run ceased production in October 2011.
 
(5) Commenced production in September 2010.
 
(6) Includes 167,000 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) Commenced production in June 2011.
 
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 lessee’s 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.


4


Table of Contents

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 lessee’s 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 lessee’s 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 lessee’s 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 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 lessee’s mining operations, including any damages we may incur on account of our lessee’s 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 0.4% equity interest in us through its wholly-owned subsidiary, Elk Creek GP, which is our general partner. Of Armstrong Energy, Inc.’s total controlled reserves of 319 million tons, 66 million tons (21%) are wholly owned by us, and 138 million tons (43%) are held by Armstrong Energy and us as joint tenants-in-common with 60.55% and 39.45% 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 2010 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 six mines, including four surface and two underground, and is seeking permits for four additional mines. Armstrong Energy’s revenue increased from zero in 2007 to $220.6 million in 2010. For the year ended December 31, 2010, Armstrong Energy produced 5.6 million tons of coal from three surface and two underground mines. During the nine months ended September 30, 2011, it produced 5.1 million tons of coal, with seven mines in operation, and currently expects a significant increase in its production for 2011 compared to 2010. 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.


5


Table of Contents

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 Energy’s 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 September 30, 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 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 Energy’s 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 Energy’s 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 Energy’s 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 Energy’s 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.


6


Table of Contents

 
Based upon Armstrong Energy’s current estimates of production for 2011 and 2012, we anticipate that Armstrong Energy will owe us royalties under the above-mentioned license and lease arrangements of approximately $7.8 million and $16.6 million in 2011 and 2012, respectively, of which collectively, $7.2 million will be recoupable against the advance royalty payment referred to above.
 
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 Energy’s agreement to sell a partial undivided interest in those reserves, we paid Armstrong Energy $20.0 million. The partial undivided interest in additional reserves must be transferred to us within 90 days after delivery of the purchase price. Following receipt of the proceeds of this sale, Armstrong Energy acquired, in December 2011, additional property near its existing and planned mines containing an estimated total of 7.7 million clean recoverable tons of coal and entered into leases for an estimated 14 million clean recoverable tons. In addition, Armstrong Energy entered into a joint venture with an affiliate of Peabody Energy Corporation (“Peabody”) relating to coal reserves near its Parkway mine. In connection with the joint venture, Peabody has agreed to contribute an aggregate of approximately 25 million clean recoverable tons of coal and Armstrong Energy has agreed to contribute mining assets to the joint venture.
 
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 0.4% 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 $      million of the net proceeds from the Concurrent AE Offering to repay a portion of Armstrong Energy’s 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 Energy’s 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 Energy’s Energy Information Administration (“EIA”), the U.S. coal industry produced approximately 1.1 billion tons of coal in 2010, a substantial majority of which was sold by U.S. coal producers to operators of electricity generation plants. Coal-fired electricity generation is the largest component of total world electricity generation. The following market dynamics and trends currently impact thermal coal consumption and production in the United States and are reshaping competitive advantages for coal producers.
 
  •  Stable long-term outlook for U.S. thermal coal market.  According to the EIA, coal-fired electricity generation accounted for approximately 45% of all electricity generation in the United States in 2010. Coal continues to be the lowest cost fossil fuel source of energy for electric power generation. Despite recent increases in generation from natural gas, as well as federal and state subsidies for the construction and operation of renewable energy, the EIA projects that generation from coal will increase by 25% from 2009 to 2035 and coal-fired generation will remain the largest single source of electricity generation in 2035.


7


Table of Contents

 
  •  Increasing demand for coal produced in the Illinois Basin.  According to Wood Mackenzie, a leading commodities consultancy, demand for coal produced from the Illinois Basin is expected to grow by 69% from 2009 through 2015 and by 126% from 2009 through 2030. We believe this is due to a combination of factors including:
 
  •  Significant expansion of scrubbed coal-fired electricity generating capacity.  The EIA forecasts a 32% increase in flue gas desulfurization (“FGD”) installed on the coal-fired generation fleet from 168 gigawatts in 2009 to 222 gigawatts, or 70% of all U.S. coal-fired capacity in the electric sector by 2035, as electricity generation operators invest in retrofit emissions reduction technology to comply with new U.S. Environmental Protection Agency (“EPA”) regulations under the Cross-State Air Pollution Rule and the proposed Utility Boiler Maximum Achievable Control Technology (“MACT”) regulations. Illinois Basin coal generally has a higher sulfur content per ton than coal produced in other regions. However, we believe that FGD utilization will enable operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.
 
  •  Declines in Central Appalachian thermal coal production.  Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 128 million tons in 2010 to 64 million tons in 2015, due to reserve depletion, regulatory-driven decreases in Central Appalachian surface thermal coal production, and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.
 
  •  Growing demand for seaborne thermal coal.  Global trade in thermal coal accounted for nearly 70% of all global coal exports in 2010 and is projected to rise from 850 million tons in 2010 to 1.1 billion tons by 2016. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality, and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.
 
Strategy
 
Our primary business strategy is to establish and grow our proven and probable reserves so that we will be able to generate royalties to make cash available for distribution to our unitholders by executing the following:
 
  •  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. We initially intend to defer the royalties earned under our leases in order to acquire an increasing percentage interest in those reserves that currently generate our income.
 
  •  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.
 
  •  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.


8


Table of Contents

 
Competitive Strengths
 
We believe that the following competitive strengths will enable us to effectively execute our business strategy:
 
  •  Our lessee has a demonstrated track record for successfully completing reserve acquisitions, securing required permits, developing new mines and producing coal.  Since Armstrong Energy’s formation in 2006, it has successfully acquired coal reserves and opened seven separate mines, obtained the necessary regulatory permits for the commencement of mining operations at those mines, and developed significant multi-year contractual relationships with large customers in its market area. We believe this resulted from Armstrong Energy’s 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.
 
  •  Our proven and probable reserves have a long reserve life and attractive characteristics.  As of September 30, 2011, we either owned or had an interest in approximately 204 million tons of clean recoverable (proven and probable) coal reserves. Our reserves represent underground mineable coal, which, in combination with our lessee’s coal processing facilities, enhance our lessee’s 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.
 
  •  Our reserves are strategically located to allow access to multiple transportation options for delivery.  Our lessee’s 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.
 
  •  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.
 
  •  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 Energy’s senior management team have a demonstrated track record of acquiring, building and operating coal businesses profitably and safely. In addition, members of Armstrong Energy’s senior management team have significant experience managing the financial and organizational growth of businesses, including public companies.
 
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.


9


Table of Contents

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:
 
(FLOW CHART)
 
 
(1) Reserves owned solely by Armstrong Resource Partners. These include the Kronos, Lewis Creek and Ceralvo underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a 39.45% undivided interest) and Armstrong Energy (with a 60.55% undivided interest). If 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.”


10


Table of Contents

 
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.
 
(FLOW CHART)
 
 
(1) Reserves owned solely by Armstrong Resource Partners. These include the Kronos, Lewis Creek and Ceralvo underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a     % undivided interest) and Armstrong Energy (with a     % undivided interest), assuming an offering price of $      per unit, the midpoint of the price range set forth on the front cover page of this prospectus and an estimated purchase price of $      for our additional interest in the partially owned reserves.
 
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 (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.


11


Table of Contents

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. Yorktown’s 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 Energy’s board, the adoption or amendment of provisions in Armstrong Energy’s charter and bylaws, the approval of mergers, and other significant corporate transactions that may affect us because we are managed by Armstrong Energy’s 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 Energy’s 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.
 
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.”


12


Table of Contents

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:
 
  •  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;
 
  •  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  •  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.
 
In resolving a conflict, Armstrong Energy, including its conflicts committee, may, unless the resolution is specifically provided for in the Partnership Agreement, consider:
 
  •  the relative interests of any party to such conflict and the benefits and burdens relating to such interest;
 
  •  any customary or accepted industry practices or historical dealings with a particular person or entity;
 
  •  generally accepted accounting practices or principles; and
 
  •  such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
 
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:
 
  •  the volume of coal production and the royalties generated from our reserves;
 
  •  the prices at which coal sales are made, and thereby the royalty revenues generated by the leased coal reserves;
 
  •  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”);
 
  •  Armstrong Energy’s agreement with coal customers to defer or reschedule contractually committed coal sales;
 
  •  decisions by Armstrong Energy to idle or close any operation due to market conditions, force majeure, or for other operating reasons;
 
  •  amount and timing of asset purchases and sales;
 
  •  cash expenditures;
 
  •  borrowings; and
 
  •  the issuance of additional common units.
 
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.
 
We do not have any officers or employees and rely solely on officers and employees of Armstrong Energy, Inc. and its affiliates.


13


Table of Contents

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:
 
  •  incur additional debt;
 
  •  make distributions on or redeem or repurchase common units;
 
  •  make certain investments and acquisitions;
 
  •  incur certain liens or permit them to exist;
 
  •  enter into certain types of transactions with affiliates;
 
  •  merge or consolidate with another company; and
 
  •  transfer or otherwise dispose of assets.
 
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.
 
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


14


Table of Contents

provides that any action taken by Armstrong Energy to limit its liability or our liability is not a breach of Armstrong Energy’s 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 arm’s-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 arm’s-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.”


15


Table of Contents

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.
 
Common Units to be Outstanding Immediately After this Offering
          common units (or          common units if the underwriters exercise in full their over-allotment option).
 
Common Units Held by Our Existing Unitholders Immediately After this Offering
          common units (or          common units if the underwriters exercise in full their over-allotment option).
 
Use of Proceeds We expect to receive net proceeds from this offering of approximately $      million (or approximately $      million if the underwriters exercise in full their option to purchase additional units) after deducting estimated underwriting discounts and commissions, and after our offering expenses estimated at $      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 $      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.”
 
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.
 
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


16


Table of Contents

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.
 
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”
 
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 deciding whether to invest in our common units. The following risks are discussed in more detail in “Risk Factors” beginning on page 21:
 
  •  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.
 
  •  We may not have sufficient cash to enable us to pay any distributions.
 
  •  Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.
 
  •  Unitholders other than Yorktown may not remove our general partner even if they wish to do so.
 
  •  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.


17


Table of Contents

 
  •  Our partnership agreement limits our general partner’s 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.
 
  •  Armstrong Energy’s board of directors may change the management and allocation policies relating to Armstrong Resource Partners without the approval of our unitholders.
 
  •  Holders of our common units may not have any remedies if any action by Armstrong Energy’s directors or officers in relation to Armstrong Energy has an adverse effect on only Armstrong Resource Partners common units.
 
  •  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.
 
  •  Conflicts of interest could arise among our general partner and us or the unitholders.
 
  •  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.
 
  •  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.
 
  •  Our lessee could satisfy obligations to its customers with coal from properties other than ours, depriving us of the ability to receive royalty payments.


18


Table of Contents

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, 2008, 2009 and 2010 and the balance sheet data as of December 31, 2008, 2009 and 2010 are derived from our audited financial statements included herein. The summary historical financial data for the nine months ended September 30, 2010 and 2011 and the balance sheet data as of September 30, 2010 and 2011 are derived from our unaudited financial statements provided herein.
 
The following unaudited pro forma consolidated financial data of Armstrong Resource Partners, L.P. at September 30, 2011, for the year ended December 31, 2010, and for the nine months ended September 30, 2011, are derived from our unaudited pro forma financial information, which is included elsewhere in this prospectus.
 
The unaudited pro forma consolidated balance sheet data at September 30, 2011 gives effect to the issuance of common units in this offering and the application of the net proceeds therefrom as described in “Use of Proceeds,” as if it had occurred on September 30, 2011. The unaudited pro forma consolidated financial data for the fiscal year ended December 31, 2010 and the nine months ended September 30, 2011 gives effect to the financial impact for the acquisition of additional reserves from Armstrong Energy with the proceeds from this offering and the subsequent leasing of those reserves back to Armstrong Energy, as if each had occurred on January 1, 2010.
 
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 and unaudited pro forma financial data in conjunction with “Selected Historical Consolidated Financial and Operating Data,” “Unaudited Pro Forma Financial Information” and


19


Table of Contents

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus.
 
                                                         
                                  Pro Forma  
                      Nine
 
                Year
    Months
 
                Ended
    Ended
 
    Year Ended December 31,     Nine Months Ended September 30,     December 31,     September 30,  
    2008     2009     2010     2010     2011     2010     2011  
                      (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)  
                            (Restated)(1)              
    (In thousands, except per unit amounts)              
 
                                                         
Results of Operations Data
                                                       
Total revenue
  $     $     $     $     $ 5,414     $           $        
Costs and expenses
    332       330       817       591       3,379                  
                                                         
Operating income (loss)
    (332 )     (330 )     (817 )     (591 )     2,035                  
Interest expense
    (4,877 )     (1,723 )                                  
Interest income
          161       4,209       2,855       1,008                  
Other income (expense), net
          (2 )     (60 )           809                  
                                                         
Net income (loss)
  $ (5,209 )   $ (1,894 )   $ 3,332     $ 2,264     $ 3,852     $           $        
                                                         
Earnings (loss) per unit, basic and diluted(1)
  $ (19.79 )   $ (2.62 )   $ 2.96     $ 2.08     $ 2.88     $           $        
                                                         
Balance Sheet Data (at period end)
                                                       
Total assets
  $ 78,683     $ 91,097     $ 137,929     $ 115,461     $ 146,738     $           $        
Working capital
    (28,667 )     215       155       215       335                  
Total debt
    28,878                                          
Total partners’ capital
    49,791       89,497       125,929       113,861       134,781                  
Other Data
                                                       
Royalty coal tons produced by lessee (unaudited)
                            1,921                  
Net cash provided by (used in):
                                                       
Operating activities
  $ (5,255 )   $ (308 )   $ 13,792     $ 2,264     $ 6,386     $           $        
Investing activities
    (24,458 )     (12,424 )     (46,892 )     (24,364 )     (11,386 )                
Financing activities
    29,878       12,722       33,100       22,100       5,000                  
EBITDA (unaudited)(2)
    (332 )     (332 )     (877 )     (591 )     5,601                  
EBITDA is calculated as follows (unaudited):
                                                       
Net income (loss)
  $ (5,209 )   $ (1,894 )   $ 3,332     $ 2,264     $ 3,852     $           $        
Depletion
                            2,757                  
Interest, net
    4,877       1,562       (4,209 )     (2,855 )     (1,008 )                
                                                         
    $ (332 )   $ (332 )   $ (877 )   $ (591 )   $ 5,601     $           $        
                                                         
 
 
(1) The financial statements for the nine month period ended September 30, 2011 have been restated to correct for an error in the calculation of depletion expense. See Note 3 to the interim financial statements.
 
(2) Amounts do not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering.
 
(3) 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, and depletion.
 
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


20


Table of Contents

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.
 
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 company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and
 
• helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure, which is useful for trending, analyzing and benchmarking the performance and value of our business.


21


Table of Contents

 
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:
 
  •  the method of mining;
 
  •  timing of new mine openings;
 
  •  planned production and sales volumes;
 
  •  credit review of its customers;
 
  •  marketing of the coal mined;
 
  •  coal transportation arrangements;
 
  •  employee wages;
 
  •  permitting;
 
  •  surety bonding; and
 
  •  mine closure and reclamation.
 
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


Table of Contents

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 lessee’s 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:
 
  •  the domestic and foreign supply and demand for coal;
 
  •  the relative cost, quantity and quality of coal available from competitors;
 
  •  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;
 
  •  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;
 
  •  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;
 
  •  adverse weather, climatic or other natural conditions, including natural disasters;
 
  •  domestic and foreign economic conditions, including economic slowdowns;
 
  •  the proximity to, capacity of and cost of, transportation, port and unloading facilities; and
 
  •  market price fluctuations for sulfur dioxide emission allowances.
 
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 Energy’s production is subject to operating conditions or events beyond its or our control, including:
 
  •  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;
 
  •  delays or challenges to and difficulties in obtaining or renewing permits necessary to produce coal or operate mining or related processing and loading facilities;
 
  •  adverse weather and natural disasters, such as heavy rains or snow, flooding, and other natural events affecting operations, transportation, or customers;
 
  •  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;
 
  •  mining, processing, and plant equipment failures and unexpected maintenance problems;
 
  •  unexpected or accidental surface subsidence from underground mining;
 
  •  accidental mine water discharges, fires, explosions, or similar mining accidents; and
 
  •  competition and/or conflicts with other natural resource extraction activities and production within Armstrong Energy’s operating areas, such as coalbed methane extraction or oil and gas development.


23


Table of Contents

 
These conditions or events could cause a delay or halt of production or shipments, or our lessee’s 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 “PRB”). The most important factors on which it competes are:
 
  •  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);
 
  •  coal quality characteristics (primarily heat, sulfur, ash, and moisture content); and
 
  •  reliability of supply.
 
Our lessee’s 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 lessee’s 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


Table of Contents

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 lessee’s 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 lessee’s business and our royalty revenue stream over the long term. In 2011, our lessee sold substantially all 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:
 
  •  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;
 
  •  environmental and other governmental regulations, including those impacting coal-fired power plants;
 
  •  energy conservation efforts and related governmental policies; and
 
  •  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.
 
According to the EIA, total electricity consumption in the United States rose by 4.3% during 2010 compared with 2009, primarily because of the effect of the recovery from the economic downturn on industrial electricity demand in 2009, and U.S. electric generation from coal rose by 5.2% in 2010 compared with 2009. However, decreases in the demand for electricity could take place in the future, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession, or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.
 
Changes in the coal industry that affect our lessee’s 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 lessee’s 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 lessee’s 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 2010, nearly all 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:
 
  •  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
 
  •  technological developments, including those related to alternative energy sources.
 
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


25


Table of Contents

to construct and permits to construct these plants are easier to obtain, as natural gas-fired plants are seen as having a lower environmental impact than coal-fired plants. In addition, state and federal mandates for increased use of electricity from renewable energy sources could have an adverse impact on the market for our coal. Many states have mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national energy portfolio standard in the U.S., although none of these proposals have been enacted to date. Possible 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:
 
  •  quality of the coal;
 
  •  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 lessee’s mines are currently located;
 
  •  the percentage of coal ultimately recoverable;
 
  •  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;
 
  •  assumptions concerning the timing for the development of the reserves; and
 
  •  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.
 
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.
 
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 lessee’s operating costs or disrupt or delay its production, potentially reducing our royalty revenues.
 
Our lessee’s 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,


26


Table of Contents

particularly steel-based supplies, diesel fuel, and rubber tires, increase, our lessee’s 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 lessee’s ability to mine our coal reserves or result in significant unanticipated costs.
 
A title defect or the loss of one of our or Armstrong Energy’s 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 Energy’s 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 Energy’s 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 lessee’s 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 lessee’s 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 lessee’s 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 lessee’s 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 lessee’s customers from entering into multi-year coal supply agreements. If a lower percentage of our lessee’s 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 provided by such agreements. Some of our lessee’s 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


27


Table of Contents

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 lessee’s largest customers could adversely affect our coal royalty revenues.
 
For the year ended December 31, 2010, our lessee derived approximately 76% of its total coal revenues from sales to its two largest customers — Tennessee Valley Authority (“TVA”) and Louisville Gas and Electric (“LGE”). For the fiscal year ended December 31, 2010, coal sales to TVA and LGE constituted approximately 40% and 36% of our lessee’s total coal revenues, respectively. Our lessee’s multi-year coal supply agreements with TVA expire in 2013 and 2018, and its multi-year coal supply agreements with LGE expire in 2015 and 2016; however, most of its multi-year coal supply agreements with TVA and LGE 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 lessee’s 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 lessee’s arrangements with TVA or LGE are terminated early pursuant to the re-opener provisions, or our lessee fails to extend or renew its arrangements with TVA or LGE, our coal royalty revenues could be negatively impacted.
 
If our lessee’s multi-year coal supply agreements with TVA or LGE are terminated or if our lessee fails to extend or renew its multi-year coal supply agreements with TVA or LGE, 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 lessee’s business operations. Our lessee’s 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 lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee’s 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 lessee’s operations are concentrated in Western Kentucky and the Illinois Basin, and a disruption within that geographic region could adversely affect the Partnership’s performance.
 
Our reserves and Armstrong Energy’s 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 lessee’s 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 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.


28


Table of Contents

Our lessee’s ability to operate its business effectively could be impaired if it fails to attract and retain key management personnel.
 
Armstrong Energy’s 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 management’s long-standing relationships within its industry. The loss of any of its senior executives could have a material adverse effect on Armstrong Energy’s 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 Energy’s 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 lessee’s labor and overall productivity or costs could be materially and adversely affected, thereby reducing our royalty revenues.
 
Our lessee’s work force could become unionized in the future.
 
All of our lessee’s 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 lessee’s operations were to become unionized, it could adversely affect its productivity and increase the risk of work stoppages. In addition, our lessee’s operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our lessee’s operations. Any unionization of our lessee’s 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 lessee’s 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 lessee’s 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 lessee’s customers may significantly affect our lessee’s 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 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 lessee’s business and our coal royalty revenues.


29


Table of Contents

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:
 
  •  the amount of coal produced from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;
 
  •  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;
 
  •  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;
 
  •  with respect to our coal reserves, the proximity to and capacity of transportation facilities;
 
  •  the price and availability of alternative fuels;
 
  •  the impact of future environmental and climate change regulations, including those impacting coal-fired power plants;
 
  •  the level of worldwide energy and steel consumption;
 
  •  prevailing economic and market conditions;
 
  •  difficulties by our lessee in collecting receivables because of credit or financial problems of purchasers of coal mined from our reserves;
 
  •  the effects on the mining of coal from our reserves of new or expanded health and safety regulations;
 
  •  domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility industry or the steel industry;
 
  •  changes in tax laws;
 
  •  weather conditions; and
 
  •  force majeure.
 
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.”


30


Table of Contents

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:
 
  •  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;
 
  •  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;
 
  •  we may be more vulnerable to competitive pressures or a downturn in the coal mining business or the economy generally; and
 
  •  our flexibility in responding to changing business and economic conditions may be limited.
 
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:
 
  •  incur additional debt;
 
  •  make distributions on or redeem or repurchase common units;
 
  •  make certain investments and acquisitions;
 
  •  incur certain liens or permit them to exist;
 
  •  enter into certain types of transactions with affiliates;
 
  •  merge or consolidate with another company; and
 
  •  transfer or otherwise dispose of assets.
 
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


31


Table of Contents

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 will be required by Section 404 of the Sarbanes-Oxley Act to evaluate the effectiveness of our internal controls. We have identified control deficiencies, including material weaknesses, in the past, which have been remediated. If we are unable to establish and maintain effective internal controls, our financial condition and operating results could be adversely affected.
 
We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We are also in the process of performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We anticipate that we will be required to comply with Section 404 for the year ending December 31, 2013.
 
However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a deficiency or combination of deficiencies in internal controls over financial reports that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. A “significant deficiency” is a deficiency or combination of deficiencies that is less severe than a material weakness.
 
We have identified deficiencies in our internal control over financial reporting, including in connection with the financial statement close process for the year ended December 31, 2011, in which we identified an error in our calculation of 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 management might not be able to certify, and our independent registered public accounting firm might not be able to deliver an unqualified report on the adequacy of our internal control over financial reporting.
 
If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our consolidated financial statements, and as a result our common unit price may be adversely affected. If we fail to remedy any material weakness, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our common 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


32


Table of Contents

environmental laws by the EPA and other regulatory agencies. Future regulation of greenhouse gas emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers and may restrict the construction of new coal-fired power plants.
 
The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions. In addition, a federal appeals court has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, although the U.S. Supreme Court has since held that federal common law provides no basis for such claims. Future regulation, litigation, and permitting related to greenhouse gas emissions may cause some users of coal to switch from coal to a lower-carbon fuel, or otherwise reduce the use of and demand for fossil fuels, 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 lessee’s 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 EIA’s 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.
 
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


33


Table of Contents

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 lessee’s coal and the price our lessee will receive, which could materially and adversely affect our royalty payments.
 
Our lessee’s failure to obtain and renew permits and approvals necessary for its mining operations could materially reduce our royalty revenues.
 
We depend on our lessee’s 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 EPA’s 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 lessee’s 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 lessee’s 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.”
 
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


34


Table of Contents

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.
 
Our lessee received notice from the EPA dated July 25, 2011 that the EPA believes that the proposed discharge plan submitted by our lessee in connection with our lessee’s Section 404 permit application for the expanded mining at our Midway Mine would result in unacceptable impacts on ARNIs, and in particular, downstream waters outside the scope of the permit area. As a result, it is possible that the Corps will deny our lessee’s pending permit application, or that the EPA will elevate the permit application to a higher level of review should the Corps proceed with the issuance of the permit notwithstanding EPA’s concerns. Ultimately, the EPA may consider initiating a Section 404(c) “veto” of the permit. A material delay in the issuance of this permit, or other Section 404 permits that our lessee may require as part of its mining operations, or the denial or veto of such permits, could have a materially negative effect on our lessee’s operations and our royalty revenues.
 
Federal or state regulatory agencies have the authority to order certain of our lessee’s 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 lessee’s mines, our coal royalty revenues could materially decline.
 
Extensive environmental laws and regulations impose significant costs on our lessee’s mining operations, and future laws and regulations could materially increase those costs or limit our lessee’s 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:
 
  •  limitations on land use;
 
  •  mine permitting and licensing requirements;
 
  •  reclamation and restoration of mining properties after mining is completed;
 
  •  management of materials generated by mining operations;
 
  •  the storage, treatment, and disposal of wastes;
 
  •  remediation of contaminated soil and groundwater;
 
  •  air quality standards;
 
  •  water pollution;
 
  •  protection of human health, plant-life, and wildlife, including endangered or threatened species;
 
  •  protection of wetlands;
 
  •  the discharge of materials into the environment;
 
  •  the effects of mining on surface water and groundwater quality and availability; and
 
  •  the management of electrical equipment containing polychlorinated biphenyls.
 
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


35


Table of Contents

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 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 lessee’s 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 Interior’s 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 lessee’s 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 lessee’s business activities, result in litigation, or materially adversely affect production, which could reduce our coal royalty revenues.
 
The conduct of our lessee’s 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:
 
  •  the processes for obtaining or renewing permits;
 
  •  costs associated with providing healthcare benefits to employees;
 
  •  health and safety standards;
 
  •  accounting standards;


36


Table of Contents

 
  •  taxation requirements; and
 
  •  competition laws.
 
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:
 
  •  sealing off abandoned areas of underground coal mines;
 
  •  mine safety equipment, training, and emergency reporting requirements;
 
  •  substantially increased civil penalties for regulatory violations;
 
  •  training and availability of mine rescue teams;
 
  •  underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
 
  •  flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and
 
  •  post-accident two-way communications and electronic tracking systems.
 
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 Company’s 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 lessee’s current or future mines operate and could increase our lessee’s operating costs or otherwise may prevent, delay or reduce our lessee’s planned production, any of which could adversely affect our lessee’s coal production and our royalty revenue stream.
 
Although we are unable to quantify the full impact, implementing and our lessee’s compliance with new laws and regulations could have an adverse impact on our lessee’s business and results of operations and could result in harsher sanctions in the event of any violations. See “Business — Regulation and Laws.”


37


Table of Contents

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 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:
 
  •  changes in oil and gas prices;
 
  •  changes in our funds from operations and earnings estimates;
 
  •  publication of research reports about us, Armstrong Energy, or the energy services industry;
 
  •  increase in market interest rates, which may increase our cost of capital;
 
  •  changes in applicable laws or regulations, court rulings, and enforcement and legal actions;
 
  •  changes in market valuations of similar companies;
 
  •  adverse market reaction to any increased indebtedness we may incur in the future;
 
  •  additions or departures of key management personnel of Armstrong Energy;
 
  •  actions of our general partner;
 
  •  speculation in the press or investment community;
 
  •  a large volume of sellers of our common units pursuant to our resale registration statement with a relatively small volume of purchasers; or
 
  •  general market and economic conditions.
 
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.


38


Table of Contents

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.”
 
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 Energy’s board of directors believes may involve conflicts of


39


Table of Contents

interest. See “Management” and “Management — Board of Directors and Board Committees — Conflicts Committee.”
 
Our partnership agreement limits our general partner’s 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 reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
 
  •  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;
 
  •  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;
 
  •  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;
 
  •  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
 
  •  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.
 
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 Energy’s board of directors may change the management and allocation policies relating to Armstrong Resource Partners without the approval of our unitholders.
 
Armstrong Energy’s 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 Energy’s certificate of incorporation or Armstrong Energy’s bylaws, and Armstrong Energy’s board of directors may at any time change or make exceptions to these policies. Because these policies relate to matters concerning the day to


40


Table of Contents

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 Energy’s 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 Energy’s 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 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 Energy’s 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 approximately     % of our outstanding common units (or     % 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 of 2002, 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. Complying with these statutes, regulations and requirements will occupy a significant amount of time of the officers and


41


Table of Contents

directors of Armstrong Energy who manage us and will significantly increase our costs and expenses. We will need to:
 
  •  institute a more comprehensive compliance function;
 
  •  design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
 
  •  comply with rules promulgated by Nasdaq or any other stock exchange on which our common units are listed;
 
  •  prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
 
  •  establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;
 
  •  involve and retain to a greater degree outside counsel and accountants in the above activities; and
 
  •  establish an investor relations function.
 
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 common 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 $      in as adjusted, net tangible book value per common 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     % 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.
 
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.


42


Table of Contents

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:
 
  •  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
 
  •  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.
 
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 unitholder’s 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:
 
  •  an existing unitholder’s proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each common unit may decrease;
 
  •  the relative voting strength of each previously outstanding common unit may be diminished; and
 
  •  the market price of the common units may decline.
 
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


43


Table of Contents

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:
 
  •  we do not have any employees and we rely solely on the directors, officers, and employees of Armstrong Energy;
 
  •  under our Partnership Agreement, we reimburse the general partner and Armstrong Energy for the costs of managing and for operating the Partnership;
 
  •  the amount of cash expenditures, borrowings and reserves may affect cash available to pay distributions to unitholders;
 
  •  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 partner’s liability;
 
  •  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
 
  •  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.
 
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 GP’s 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.


44


Table of Contents

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, 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.


45


Table of Contents

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 Obama’s Budget Proposal for Fiscal Year 2012 (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 IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s 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 counsel’s 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 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.


46


Table of Contents

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.”
 
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


47


Table of Contents

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 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.


48


Table of Contents

 
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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. These risks, contingencies and uncertainties include, but are not limited to, the following:
 
  •  market demand for coal and electricity;
 
  •  geologic conditions, weather and other inherent risks of coal mining that are beyond our or our lessee’s control;
 
  •  competition within our industry and with producers of competing energy sources;
 
  •  excess production and production capacity;
 
  •  our ability to acquire or develop coal reserves in an economically feasible manner;
 
  •  inaccuracies in our estimates of our coal reserves;
 
  •  availability and price of mining and other industrial supplies, including steel-based supplies, diesel fuel, rubber tires and explosives;
 
  •  availability of skilled employees and other workforce factors;
 
  •  disruptions in the quantities of coal produced from our reserves as a consequence of weather or equipment or mine failures;
 
  •  our lessee’s ability to collect payments from its customers;
 
  •  defects in title or the loss of a leasehold interest;
 
  •  railroad, barge, truck and other transportation performance and costs affecting the timing or delivery of our lessee’s coal to customers;
 
  •  our lessee’s ability to secure new coal supply arrangements or to renew existing coal supply arrangements;
 
  •  our lessee’s relationships with, and other conditions affecting, its customers;
 
  •  the deferral of contracted shipments of coal by our lessee’s customers;
 
  •  our ability to service our outstanding indebtedness;
 
  •  our ability to comply with the restrictions imposed by Armstrong Energy’s Senior Secured Credit Facility and other financing arrangements, as applicable to us;
 
  •  the availability and cost of surety bonds;
 
  •  terrorist attacks, military action or war;


49


Table of Contents

 
  •  our lessee’s ability to obtain and renew various permits, including permits authorizing the disposition of certain mining waste;
 
  •  existing and future legislation and regulations affecting both our lessee’s 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;
 
  •  customers’ ability to meet existing or new regulatory requirements and associated costs, including disposal of coal combustion waste material;
 
  •  Armstrong Energy’s ability to attract/retain key management personnel;
 
  •  efforts to organize our lessee’s workforce for representation under a collective bargaining agreement;
 
  •  costs to comply with the Sarbanes-Oxley Act of 2002; and
 
  •  the other factors affecting our business described below under the caption “Risk Factors.”


50


Table of Contents

 
USE OF PROCEEDS
 
We estimate that the net proceeds to us from the sale of our common units in this offering will be $      million, at an assumed initial public offering price of $      per unit, the midpoint of the price range set forth on he cover of this prospectus, and after deducting estimated underwriting discounts and commissions and offering expenses estimated at $      million. Our net proceeds will increase by approximately $      million if the underwriters’ option to purchase additional 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 $      million, or $      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 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. If this offering is completed and the net proceeds are applied in this manner, we expect to have a     % undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves, excluding the Union/Webster Counties reserves. 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 Energy’s outstanding borrowings under the Senior Secured Revolving Credit Facility.


51


Table of Contents

 
CAPITALIZATION
 
The following table shows:
 
  •  Our capitalization as of September 30, 2011; and
 
  •  Our pro forma capitalization as of September 30, 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.
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Selected Historical Consolidated Financial and Operating Data,” “Unaudited Pro Forma Financial Information,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                 
    As of September 30, 2011
        Pro-Forma As
    Actual   Adjusted(1)
    (In thousands)
 
Cash and cash equivalents
  $ 155     $        
                 
Total long-term debt
  $     $    
Partners’ capital:
               
Common unitholders
    134,370          
General partner
    411              
                 
Total partners’ capital
    134,781          
                 
Total capitalization
  $ 134,781     $  
                 
 
 
(1) 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 $      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 1.0 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 $      million. Similarly, each decrease of 1.0 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 $      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.


52


Table of Contents

 
DILUTION
 
Dilution is the amount by which the offering price paid by the purchasers of common 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 September 30, 2011, after giving effect to the offering of 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 $      million, or $      per unit. Net tangible book value excludes $      million of net intangible assets. 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 (all unit and per unit amounts do not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering):
 
                 
Assumed initial public offering price per common unit
          $        
                 
Net tangible book value per unit before the offering(1)
          $        
                 
Increase in net tangible book value per unit attributable to purchasers in the offering
               
Less: Pro forma net tangible book value per unit after the offering(2)
               
                 
Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)
          $        
                 
 
 
(1) Determined by dividing the number of units (          common units and           general partner units) held by our general partner and its affiliates, into the net tangible book value of our assets.
 
(2) Determined by dividing the total number of units to be outstanding after this offering (          common units and           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.
 
(3) 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 $      and $      , 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:
 
                                 
    Units Acquired     Total Consideration  
 
  Number     Percent     Amount     Percent  
    (In thousands)  
 
General partner and affiliates(1)(2)
                  %   $                   %
Purchasers in the offering
                               
                                 
Total
            100.0 %           $ 100.0 %
                                 
 
 
(1) The units acquired by our general partner and its affiliates consist of           common units,          subordinated units and           general partner units.
 
(2) Assumes the underwriters’ option to purchase additional common units is not exercised.


53


Table of Contents

 
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 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.
 
Definition of Available Cash.  Available cash generally means, for each fiscal quarter:
 
  •  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
 
  •  the amount of any cash reserves that are necessary or appropriate in the reasonable discretion of our general partner and Armstrong Energy 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 it is bound 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 or Armstrong Energy so determines.
 
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 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.
 
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


54


Table of Contents

receipts received during or after the quarter in which the liquidation date occurs shall be applied and distributed solely in accordance with, and subject to the following terms and conditions.
 
The liquidator shall 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 Revised Uniform Limited Partnership Act (the “Delaware Act”) and the following:
 
  •  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 Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the partners. The liquidator may, in its absolute discretion, distribute the Partnership’s 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.
 
  •  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.
 
  •  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 year 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 year (or, if later, within 90 days after said date of such occurrence).


55


Table of Contents

 
UNAUDITED PRO FORMA FINANCIAL INFORMATION
 
The following unaudited pro forma consolidated financial statements of Armstrong Resource Partners, L.P. at September 30, 2011, for the year ended December 31, 2010, and for the nine months ended September 30, 2011, are based on the historical consolidated financial statements of Armstrong Resource Partners, L.P., which are included elsewhere in this prospectus.
 
The unaudited pro forma consolidated balance sheet at September 30, 2011 gives effect to the issuance of common units in this offering and the application of the net proceeds therefrom as described in “Use of Proceeds,” as if it had occurred on September 30, 2011. The unaudited pro forma consolidated statements of operations for the fiscal year ended December 31, 2010 and the nine months ended September 30, 2011 gives effect to the financial impact for the acquisition of additional reserves from Armstrong Energy with the proceeds from this offering and the subsequent leasing of those reserves back to Armstrong Energy, as if each had occurred on January 1, 2010.
 
The unaudited pro forma financial statements of Armstrong Resource Partners, L.P. exclude all federal and state income taxes as income taxes will be the responsibility of the unitholders and not of Armstrong Resource Partners, L.P.
 
This unaudited pro forma consolidated financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes related to those consolidated financial statements included elsewhere in this prospectus.
 
Our unaudited pro forma adjustments are based on available information and certain assumptions that we believe are reasonable. Presentation of our unaudited pro forma consolidated financial and operating data is prepared in conformity with Article 11 of Regulation S-X. The unaudited pro forma consolidated financial and operating data is included for illustrative and informational purposes only and is not necessarily indicative of results we expect in future periods.


56


Table of Contents

Unaudited Pro Forma Consolidated Statement of Operations
For the Nine Months Ended September 30, 2011
 
                         
    As Reported
          Pro Forma
 
    for the Nine
          for the Nine
 
    Months
    Adjustments
    Months
 
    Ended September 30,
    Related to the
    Ended September 30,
 
    2011     Offering     2011  
    (Restated)              
    (Dollars in thousands, except per unit amounts)  
 
Revenue
  $ 5,414     $       (A)   $        
Costs and expenses:
                       
Legal, accounting, and other professional services
    79                  
Related-party service expense
    540                  
Depletion
    2,757       (B)        
Other operating, general, and administrative costs
    3                  
                         
Operating income
    2,035                  
Other income (expense)
                       
Interest income
    1,008                  
Other income
    809                  
                         
Net income
  $ 3,852     $           $        
                         
Pro forma net income per limited partner unit
                       
Basic and diluted
                    (C)
Pro forma weighted average number of units outstanding
                       
 
 
(A) Relates to royalty revenue earned for the nine months ended September 30, 2011 on the     % interest in the reserves of Armstrong Energy acquired from proceeds from this offering and subsequently leased back to Armstrong Energy.
 
(B) Relates to depletion expense for the nine months ended September 30, 2011 on the     % interest in the reserves of Armstrong Energy acquired from the proceeds from this offering.
 
(C) Amount does not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering.


57


Table of Contents

Unaudited Pro Forma Consolidated Statement of Operations
For the Year Ended December 31, 2010
 
                         
    As Reported
             
    for the Year
          Pro Forma
 
    Ended
    Adjustments
    for the Year
 
    December 31,
    Related to the
    Ended
 
    2010     Offering     December 31, 2010  
    (Dollars in thousands, except per unit amounts)  
 
Revenue
  $     $       (D)   $        
Costs and expenses:
                       
Legal, accounting, and other professional services
    117                  
Related-party service expense
    700                  
Depletion
          (E)        
                         
Operating income
    (817 )                
Other income (expense)
                       
Interest income
    4,209                  
Interest expense
                     
Other income
    (60 )                
                         
Net income
  $ 3,332     $           $        
                         
Pro forma net income per limited partner unit
                       
Basic and diluted
                    (F)
Pro forma weighted average number of units outstanding
                       
 
 
(D) Relates to royalty revenue earned for the twelve months ended December 31, 2010 on the     % interest in the reserves of Armstrong Energy acquired from proceeds from this offering and subsequently leased back to Armstrong Energy.
 
(E) Relates to depletion expense for the twelve months ended December 31, 2010 on the     % interest in the reserves of Armstrong Energy acquired from the proceeds from this offering.
 
(F) Amount does not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering.


58


Table of Contents

Unaudited Pro Forma Condensed Consolidated Balance Sheet
As of September 30, 2011
 
                         
    As Reported
    Adjustments
    Pro Forma
 
    as of September 30,
    Related to the
    as of September 30,
 
    2011     Offering     2011  
    (Restated)     (Dollars in thousands)        
 
Assets
                       
Current assets:
                       
Cash and cash equivalents
  $ 155     $           $        
Other current assets
    180                  
                         
Total current assets
    335                  
Property, plant, equipment, and mine development, net
    142,325       (G)        
Related party notes receivable
                     
Related party other receivables, net
    4,078                  
                         
Total assets
  $ 146,738     $           $        
                         
Liabilities and partners’ capital
                       
Other non-current liabilities
  $ 11,957     $           $        
                         
Total liabilities
    11,957                  
Partners’ capital
                       
Limited partners’ interest
    134,370       (H)        
General partners’ interest
    411                  
                         
Total partners’ capital
    134,781                  
                         
Total liabilities and partners’ capital
  $ 146,738     $           $        
                         
 
 
(G) Relates to a     % undivided interest in land and mineral reserves acquired from Armstrong Energy with the proceeds from this offering.
 
(H) Reflects the adjustments to limited partners’ capital for the public offering of the Partnership’s common units as follows (dollars in thousands):
 
         
Proceeds from this offering(1)
  $        
Less: estimated fess and expense related with this offering
       
         
Net proceeds from this offering
       
         
 
(1) To reflect the issuance of           of the Partnership’s common units offered hereby at an assumed initial public offering price of $      per unit (the midpoint of the range set forth on the front cover page of this prospectus).


59


Table of Contents

 
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, and 2010 and the balance sheet data as of December 31, 2008, 2009, and 2010 are derived from the audited financial statements appearing elsewhere in this prospectus. The selected historical financial data for the nine months ended September 30, 2010 and 2011 and the balance sheet data as of September 30, 2010 and 2011 are derived from the unaudited financial statements 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus.
 
                                         
    Year Ended December 31,     Nine Months Ended September 30,  
    2008     2009     2010     2010     2011  
                      Unaudited     Unaudited
 
                            (Restated)(1)  
    (In thousands, except per unit amounts)  
 
Results of Operations Data
                                       
Total revenues
  $     $     $     $     $ 5,414  
Costs and expenses
    332       330       817       591       3,379  
                                         
Operating income (loss)
    (332 )     (330 )     (817 )     (591 )     2,035  
Interest expense
    (4,877 )     (1,723 )                  
Interest income
          161       4,209       2,855       1,008  
Other income (expense), net
          (2 )     (60 )           809  
                                         
Net income (loss)
  $ (5,209 )   $ (1,894 )   $ 3,332     $ 2,264     $ 3,852  
                                         
Earnings (loss) per unit, basic and diluted(2)
  $ (19.79 )   $ (2.62 )   $ 2.96     $ 2.08     $ 2.88  
                                         
Balance Sheet Data (at period end)
                                       
Total assets
  $ 78,683     $ 91,097     $ 137,929     $ 115,461     $ 146,738  
Working capital
    (28,667 )     215       155       215       335  
Total debt
    28,878                          
Total partners’ capital
    49,791       89,497       125,929       113,861       134,781  
Other Data
                                       
Royalty coal tons produced by lessee (unaudited)
                            1,921  
Net cash provided by (used in):
                                       
Operating activities
  $ (5,255 )   $ (308 )   $ 13,792     $ 2,264     $ 6,386  
Investing activities
    (24,458 )     (12,424 )     (46,892 )     (24,364 )     (11,386 )
Financing activities
    29,878       12,722       33,100       22,100       5,000  
EBITDA (unaudited)(3)
    (332 )     (332 )     (877 )     (591 )     5,601  
EBITDA is calculated as follows (unaudited):
                                       
Net income (loss)
  $ (5,209 )   $ (1,894 )   $ 3,332     $ 2,264     $ 3,852  
Depreciation, depletion and amortization
                            2,757  
Interest, net
    4,877       1,562       (4,209 )     (2,855 )     (1,008 )
                                         
    $ (332 )   $ (332 )   $ (877 )   $ (591 )   $ 5,601  
                                         
 
 
(1) The financial statements for the nine month period ended September 30, 2011 have been restated to correct for an error in the calculation of depletion expense. See Note 3 to the interim financial statements.
 
(2) Amounts do not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering.


60


Table of Contents

 
(3) 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, and depletion.
 
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.
 
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 company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and
 
  •  helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure, which is useful for trending, analyzing, and benchmarking the performance and value of our business.


61


Table of Contents

 
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Selected Historical Consolidated Financial and Operating Data” and our audited and unaudited financial statements and related notes appearing elsewhere in this prospectus. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this prospectus under “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors.” We assume no obligation to update any of these forward-looking statements.
 
As discussed in Note 3 to the condensed consolidated financial statements, as of and for the six and nine months ended June 30, 2011 and September 30, 2011, respectively, our financial statements have been restated. The accompanying Management’s Discussion and Analysis of Financial Condition and Results of Operations gives effect to the restatement.
 
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. We currently wholly own approximately 66 million tons of coal reserves and have a 39.45% undivided interest in approximately 138 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 99.6% 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 Energy’s control of Elk Creek, GP, our results are consolidated in Armstrong Energy’s 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 the first nine months of 2011, Armstrong Energy is obligated to pay us $5.4 million 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 $0.8 million in the nine months ended September 30, 2011.
 
Factors that Impact Our Business
 
In 2011, our lessee sold 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


62


Table of Contents

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.
 
We believe the other key factors that influence our business are:
 
  •  demand for coal;
 
  •  demand for electricity;
 
  •  economic conditions;
 
  •  the quantity and quality of coal available from competitors;
 
  •  competition for production of electricity from non-coal sources;
 
  •  domestic air emission standards and the ability of coal-fired power plants to meet these standards using
 
coal produced from the Illinois Basin;
 
  •  legislative, regulatory and judicial developments, including delays, challenges to, and difficulties in
 
acquiring, maintaining or renewing necessary permits or mineral or surface rights; and
 
  •  our ability to meet governmental financial security requirements associated with mining and
 
reclamation activities.
 
For additional information regarding some of the risks and uncertainties that affect our business and the industry in which we operate, please see “Risk Factors.”
 
Recent Trends and Economic Factors Affecting the Coal Industry
 
Coal consumption and production in the United States have been driven in recent periods by several market dynamics and trends. Total coal consumption in the United States in 2010 increased by approximately 50 million tons, or 5.0%, from 2009 levels. The rise in U.S. domestic coal consumption during 2010 was largely a function of the recovering economic growth following the 2008-2009 recession and the rebound in industrial electricity consumption and domestic steel making output. According to the EIA, coal is expected to remain the dominant energy source for electric power generation for the foreseeable future. Please read “The Coal Industry— Recent Trends and — Coal Consumption and Demand” for the recent trends and economic factors affecting the coal industry.
 
Related Party Transactions
 
Elk Creek GP, a subsidiary of Armstrong Energy, is our general partner and owns a 0.4% 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.
 
Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010
 
Revenue
 
Revenue for the nine months ended September 30, 2011 totaled $5.4 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 nine months ended September 30, 2011 that generated royalty revenues was approximately 1.9 million tons, resulting in average royalty revenue per ton of $2.82.


63


Table of Contents

Related Party Service Expense
 
Related party service expense of $0.5 million for the nine months ended September 30, 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.
 
Depletion Expense
 
Depletion expense was $2.8 million for the nine months ended September 30, 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 $1.8 million, or 64.7%, to $1.0 million for the nine months ended September 30, 2011, as compared to $2.9 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 $0.8 million for the nine months ended September 30, 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 September 30, 2011, the principal amount outstanding under the credit agreement was $134.6 million and the credit support fee paid for the nine months ended September 30, 2011 totaled $0.8 million.
 
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
 
Legal, Accounting, and Other Professional Services
 
Legal, accounting and other professional services expense 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.


64


Table of Contents

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.
 
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
 
Legal, Accounting, and Other Professional Services
 
Legal, accounting, and other professional services increased $0.1 million, or 22.5%, to $0.3 million for the year ended December 31, 2009, as compared to $0.2 million in the year prior. The increase is due to higher professional fees incurred in 2009 due to a financing that was cancelled. The expense in 2008 relates primarily to professional fees incurred associated with the establishment of the Partnership.
 
Interest Income
 
Interest income totaled $0.2 million for the year ended December 31, 2009, as compared to zero for the year ended December 31, 2008. The increase is due to interest earned on a promissory note made in favor of Armstrong Energy totaling $11.0 million in November 2009 for them to meet certain debt service obligations.
 
Interest Expense
 
Interest expense decreased $3.2 million, or 64.7%, to $1.7 million for the year ended December 31, 2009, as compared to $4.9 million for the year ended December 31, 2008. The decrease is due to lower average borrowings in 2009, as compared to 2008. In 2008, we borrowed $54.0 million for the acquisition of mineral rights and other assets, of which $25.1 million was repaid in 2008 and the remainder in June 2009.
 
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:
 
                                         
    Year Ended December 31,   Nine Months Ended September 30,
    2008   2009   2010   2010   2011
    (In thousands)
 
Net cash provided by (used in):
                                       
Operating Activities
  $ (5,255 )   $ (308 )   $ 13,792     $ 2,264     $ 6,386  
Investing Activities
  $ (24,458 )   $ (12,424 )   $ (46,892 )   $ (24,364 )   $ (11,386 )
Financing Activities
  $ 29,878     $ 12,722     $ 33,100     $ 22,100     $ 5,000  


65


Table of Contents

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010
 
Net cash provided by operating activities was $6.4 million for the nine months ended September 30, 2011, an increase of $4.1 million from net cash provided by operating activities of $2.3 million for the same period of 2010. The increase in cash provided by operating activities was principally attributable to higher depletion expense in the nine months ended September 30, 2011, as 2011 is the first year production occurred under our leases with Armstrong Energy.
 
Net cash used in investing activities was $11.4 million for the nine months ended September 30, 2011 compared to $24.4 million for the nine months ended September 30, 2010. For the nine months ended September 30, 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 nine months ended September 30, 2010 relates primarily to advances made to Armstrong Energy.
 
Net cash provided by financing activities was $5.0 million for the nine months ended September 30, 2011 compared to $22.1 million for the same period of the year prior. This decrease is due to $17.1 million of higher partner contributions in 2010, which was loaned to Armstrong Energy for the repayment of long-term debt.
 
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.
 
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
 
Net cash used in operating activities was $0.3 million for 2009, as compared to $5.3 million for 2008. The change is due primarily to improved operating results from lower interest expenses in 2009 compared to the year prior. In addition, advance royalties owed by Armstrong Energy increased by $1.6 million in 2009.
 
Net cash used in investing activities was $12.4 million for 2009 compared to $24.5 million for 2008. This $12.1 million decrease was primarily attributable to lower capital expenditures in 2009, partially offset by an increase in amounts loaned to Armstrong Energy.
 
Net cash provided by financing activities was $12.7 million for 2009 compared to $29.9 million for 2008. The decrease is due to a decrease in partner capital contributions in 2009 of $13.4 million, offset by an increase in debt payments of $3.8 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


66


Table of Contents

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 September 30, 2011, the principal amount outstanding under the credit agreement was $134.6 million and the credit support fee paid for the nine months ended September 30, 2011 totaled $0.8 million. This debt is not recorded on our balance sheet.
 
Contractual Obligations
 
We do not have any contractual obligations due as of December 31, 2010. As noted above, we are a co-borrower with respect to Armstrong Energy’s 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 September 30, 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 $34.6 million under the revolving credit facility. The following table provides details of the obligations due under the Senior Secured Term Loan as of September 30, 2011:
 
                                         
    Payments Due by Period
        Less than
          More than
    Total   One Year   1-3 Years   3-5 Years   5 Years
 
Senior secured term loan obligations (principal and interest)
  $ 117,159     $ 21,182     $ 48,279     $ 47,698         —    
                                         
 
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. 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.
 
Related Party Other Receivables, Net
 
Related party other receivables, net primarily represents the Partnership’s cash position. Elk Creek GP manages, on behalf of the Partnership, substantially all cash, investing and financing activities of the Partnership.


67


Table of Contents

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:
 
  •  our operating and financial performance;
 
  •  current business conditions and projections;
 
  •  the likelihood of achieving a liquidity event for the shares of common units underlying these restricted units grants, such as an initial public offering or sale of our company, given prevailing market conditions;
 
  •  our stage of development;
 
  •  any adjustment necessary to recognize a lack of marketability for our common units;
 
  •  the market performance of comparable publicly traded companies; and
 
  •  the U.S. and global capital market conditions.
 
To date, our only restricted unit awards were granted in October 2011, totaling 42,500 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 $144 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 $137. The overall fair value of the grants will be expensed through March 31, 2012, as this is the most probable vesting date.
 
New Accounting Standards Issued and Adopted
 
In January 2010, the Financial Accounting Standards Board (the “FASB”) issued accounting guidance that requires new fair value disclosures, including disclosures about significant transfers into and out of Level 1 and Level 2 fair-value measurements and a description of the reasons for the transfers. In addition, the guidance requires new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The new disclosure requirements became effective for interim and annual periods beginning January 1, 2010, except for the disclosure of activity within Level 3 fair value measurements, which became effective January 1, 2011. The new guidance did not have an impact on our consolidated financial statements.


68


Table of Contents

New Accounting Standards Issued and Not Yet Adopted
 
In June 2011, the FASB amended requirements for the presentation of other comprehensive income (loss), requiring presentation of comprehensive income (loss) in either a single, continuous statement of comprehensive income or on separate but consecutive statements, the statement of operations and the statement of other comprehensive income (loss). The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, or March 31, 2012 for us. The adoption of this guidance will not impact our financial position, results of operations or cash flows and will only impact the presentation of other comprehensive income (loss) on the financial statements.
 
In May 2011, the FASB amended the guidance regarding fair value measurement and disclosure. The amended guidance clarifies the application of existing fair value measurement and disclosure requirements. The amendment is effective for interim and annual periods beginning after December 15, 2011, or March 31, 2012 for us. Early adoption is not permitted. The adoption of this amendment is not expected to materially affect our consolidated financial statements.
 
Quantitative and Qualitative Disclosures about Market Risk
 
We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market 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 Energy’s 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 $0.03 per ton of royalty revenue associated with coal leased from our 39.45% undivided interest in the reserves of Armstrong Energy.
 
Seasonality
 
Our lessee’s 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 lessee’s 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.


69


Table of Contents

 
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 world’s electricity generation and approximately 68% of global steel production is fueled by coal. Global hard coal and brown coal production totaled more than 7.5 billion tons in 2009 according to the WCA.
 
Coal is the most abundant fossil fuel in the United States. The EIA estimates that there are approximately 261 billion tons of recoverable coal reserves in the United States, more than in any other country, which represents over 200 years of domestic coal supply based on current production rates. The United States is second only to China in annual coal production, producing approximately 1.1 billion tons in 2010, according to the EIA.
 
Coal is ranked by heat content, with anthracite, bituminous, subbituminous, and lignite coal representing the highest to lowest carbon and heat ranking, respectively. Coal is also characterized by end use market as either thermal coal or metallurgical coal. Thermal coal is used by utilities and independent and industrial power producers to generate electricity and/or steam or heat, and metallurgical coal is used by steel companies to produce metallurgical coke for use in the steel making process. Important factors in evaluating thermal coal quality are its Btu or heat content, sulfur, ash, and moisture content, while metallurgical coal is evaluated on the additional metrics of contained volatile matter and coking characteristics, including expansion, plasticity, and strength.
 
Electricity generation accounts for 68% of global coal consumption (2008) while industrial consumption accounts for nearly 36% of global coal production. Thermal coal’s abundance and relatively wide in-situ global resource distribution have contributed to its relative ease of availability and competitive cost versus other electricity generating fuels. Global thermal coal trade is expected to grow to 1.1 billion annual tons in 2016 from 850 million tons in 2010, driven largely by increased electricity demand in the developing world, a significant portion of which is expected to be supplied by coal-fired power plants. The U.S. domestic thermal coal market consumption, which accounts for close to 90% of U.S. domestic coal production, is expected to grow by 25% by 2035 from 2009 levels, according to the EIA, and coal-fired electricity generation is expected to continue to be the largest single fuel source of U.S. electricity (43% in 2035).
 
Recent Trends
 
U.S. and international coal market supply, demand, and prices are influenced by many factors including relative coal quality, available capacity and costs of transportation and related infrastructure (such as rail, barge, and river or export terminals), mining production costs, and the relative costs of generating electricity with competing fuels (natural gas, fuel oil, hydro, nuclear, and renewable such as wind and solar power). U.S. domestic thermal coal demand and global thermal coal demand are strongly correlated with the pace of domestic and global economic growth.
 
Our lessee’s 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 2010, a substantial majority of which was sold by U.S. coal producers to operators of electricity generation plants. Coal-fired electricity generation is the largest component of total world electricity generation. The following market dynamics and trends currently impact thermal coal consumption and production in the United States and are reshaping competitive advantages for coal producers.
 
  •  Stable long-term outlook for U.S. thermal coal market.  According to the EIA, coal-fired electricity generation accounted for approximately 45% of all electricity generation in the United States in 2010.


70


Table of Contents

  Coal continues to be the lowest cost fossil fuel source of energy for electric power generation. Despite recent increases in generation from natural gas, as well as federal and state subsidies for the construction and operation of renewable energy, the EIA projects that generation from coal will increase by 25% from 2009 to 2035 and coal-fired generation will remain the largest single source of electricity generation in 2035.
 
  •  Increasing demand for coal produced in the Illinois Basin.  According to Wood Mackenzie, a leading commodities consultancy, demand for coal produced from the Illinois Basin is expected to grow by 69% from 2009 through 2015 and by 126% from 2009 through 2030. We believe this is due to a combination of factors including:
 
  •  Significant expansion of scrubbed coal-fired electricity generating capacity.  The EIA forecasts a 32% increase in FGD installed on the coal-fired generation fleet from 168 gigawatts in 2009 to 222 gigawatts, or 70% of all U.S. coal-fired capacity in the electric sector by 2035, as electricity generation operators invest in retrofit emissions reduction technology to comply with new EPA regulations under the Cross-State Air Pollution Rule and the proposed Utility Boiler MACT regulations. Illinois Basin coal generally has a higher sulfur content per ton than coal produced in other regions. However, we believe that FGD utilization will enable operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.
 
  •  Declines in Central Appalachian thermal coal production.  Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 128 million tons in 2010 to 64 million tons in 2015, due to reserve depletion, regulatory-driven decreases in Central Appalachian surface thermal coal production, and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.
 
  •  Growing demand for seaborne thermal coal.  Global trade in thermal coal accounted for nearly 70% of all global coal exports in 2010 and is projected to rise from 850 million tons in 2010 to 1.1 billion tons by 2016. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality, and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.
 
Coal Consumption and Demand
 
The vast majority of thermal coal consumed in the United States is used to generate electricity, with the balance used by a variety of industrial users to heat and power a range of manufacturing and processing facilities. Metallurgical coal is primarily used in steelmaking blast furnaces. In 2009, coal-fired power plants produced approximately 45% of all electric power generation, more than natural gas and nuclear, the two next largest domestic fuel sources, combined. Thermal coal used by electric utilities and other power producers accounted for 976 million tons or 93.1% of total coal consumption in 2010, an increase of 42 million tons or 4.5% over 2009 consumption levels.
 
Total coal consumption in the United States in 2010 increased by approximately 51 million tons, or 5.1%, from 2009 levels. The rise in U.S. domestic coal consumption during 2010 was largely a function of the recovering economic growth following the 2008-2009 recession and the rebound in industrial electricity consumption and domestic steel making output. In 2010, electricity consumption in the United States increased approximately 4.3% from 2009, and the average growth rate in the decade prior to 2010 was approximately 0.7% per year according to EIA estimates. Because coal-fired generation is used in most cases


71


Table of Contents

to meet base load electricity demand requirements, coal consumption has generally grown at the pace of electricity demand growth. Among coal’s 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 2011 reference case that total coal consumption will grow by approximately 32% through 2035, primarily due to steady increases in coal-fired electric power generation and the introduction of coal-to-liquids plants.
 
The following table sets forth historical and forecasted U.S. coal consumption as aggregated by the EIA for the periods indicated.
 
                                                         
    U.S. Coal Consumption by Sector  
    Actual
    Actual
    Forecast
    Forecast
    Forecast
    Forecast
    Forecast
 
    2008     2009     2015     2020     2025     2030     2035  
    (Tons in millions)  
 
Electric Power
    1,041       937       928       989       1,066       1,094       1,119  
Industrial
    54       45       49       49       48       48       47  
Steel Production
    22       15       22       22       21       20       18  
Residential/Commercial
    4       3       3       3       3       3       3  
Coal-to-Liquids
                11       13       44       82       128  
                                                         
Total U.S. Consumption
    1,121       1,000       1,013       1,076       1,182       1,247       1,315  
 
 
Source: EIA 2011 Energy Outlook
 
Illinois Basin Coal Market
 
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 lessee’s market area was generated by coal-fired power plants. The table below compares the total electricity generation in our lessee’s 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


72


Table of Contents

 
The number of new coal-fired power plants in the Illinois Basin coal market is expected to increase, as eight new plants have recently been built or are permitted and under construction. The table below represents the EIA Form 860 information and/or public filing data on these new and under construction coal-fired units, which represent over 5,000mw of nameplate capacity.
 
                                 
                Under
       
                Construction
  MW
  Effective
Utility Name
 
Plant Name
  State   County   Region   Nameplate   Year
 
Virginia Electric & Power Co. 
  Virginia City Hybrid Energy Center   VA   Wise   RFC     585       2012  
Duke Energy Carolinas LLC
  Cliffside   NC   Cleveland   SERC     800       2011  
Duke Energy Indiana Inc. 
  Edwardsport (IGCC)   IN   Knox   RFC     618       2011  
Cash Creek Generating LLC
  Cash Creek (Coal Gasification)   KY   Henderson   SERC     640       2011  
GenPower
  Longview Power LLC   WV   Monongalia   RFC     695       2011  
Louisiana Gas & Electric
  Trimble County   KY   Trimble   SERC     834       2010  
City Utilities of Springfield
  Southwest Power Station   MO   Greene   SERC     300       2010  
Dynegy Services Plum Point Inc. 
  Plum Point Energy Station   AR   Mississippi   SERC     665       2010  
 
 
Source: EIA
 
More importantly, the progressive tightening by the EPA of SO2, NOx and other hazardous air pollutant emissions standards from coal-fired electricity generation plants is expected to result in additional significant increases in the number of generating stations retrofitted with FGD systems.
 
U.S. Scrubber Market
 
The 1990 amendments to the Clean Air Act imposed progressively stringent regulations on the emissions of SO2 and NOx. Among the coal-fired electricity generation industry’s 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 EPA’s hazardous air pollutants regulations.
 
To implement requirements under the Clean Air Act, in July 2011, the EPA adopted the CSAPR (aimed at SO2 and NOx). In December 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued a ruling to stay the CSAPR pending judicial review. The EPA is also presently developing additional rules to further reduce the release of certain combustion by-product emissions from fossil fuel power plants. These rules include the proposed Utility Boiler MACT that would regulate the emission of other air pollutants, including mercury and other metals, fine particulates, and acid gases such as hydrogen chloride (HCl).
 
To comply with the expected tightening of emissions limitations, operators of coal-fired electricity generation have increasingly invested in FGD, selective and non-selective catalytic reduction systems and other advanced control technologies at their large, base load power plants. 199gw of the current 316gw of U.S. coal-fired generation is presently equipped with FGD emissions systems. We believe that with the implementation of the CSAPR and MACT, new FGD systems will likely be installed on additional coal-fired generation increasing the total amount of generation capacity to approximately 70% of all U.S. capacity in the electric sector capacity by 2035.
 
Today, the number of scrubbers being installed at coal-fired power plants across the United States is growing, and the operating and economic profile use of this technology has become well understood and broadly applied. We expect that the continuation of this trend will substantially increase the demand for higher sulfur coal given the competitive cost of Illinois Basin coal, and will expand the competitive reach of our coal and our primary market area.
 
The following table contains Wood Mackenzie’s 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


73


Table of Contents

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       11,987       9,121  
Coal Tons Affected (Million Tons)
    120       34       32       38       29  
 
 
Source: Wood Mackenzie Illinois Basin Market Outlook, March 2011
 
Wood Mackenzie forecasts that the U.S. domestic electricity generation coal consumption will grow from a projected 975 million tons in 2011 to 985 million tons by 2015. More importantly, the Wood Mackenzie forecast projects Illinois Basin coal production growth from 117 million tons in 2011 to 167 million tons by 2015 (43% growth) and then to over 200 million tons by 2020.
 
Long-Term U.S. Thermal Coal Outlook — Fall 2011: Summary Table of Key Data
(tons in millions)
 
                                                                 
    2011     2012     2013     2014     2015     2020     2025     2030  
 
Supply (Mst)
    1,112       1,109       1,113       1,108       1,145       1,139       1,179       1,240  
                                                                 
Powder River Basin
    467       487       483       486       508       481       508       552  
Central Appalachia
    115       89       76       64       64       46       56       71  
Illinois Basin
    117       130       144       157       167       204       216       224  
Northern Appalachia
    116       121       129       134       136       132       125       124  
Metallurgical (not including Thermal Cross Over)
    86       84       82       69       70       81       87       93  
Imports
    10       8       5       3       3       5       5       5  
Other (including Refuse or Petcoke)
    201       190       195       196       197             181       171  
Stockpile Increase (Decrease)
    41                               190              
                                                                 
Demand (Mst)
    1,154       1,109       1,113       1,108       1,145       1,139       1,179       1,240  
                                                                 
Electricity Generation
    975       942       942       967       985       954       837       794  
Industrial
    59       52       51       52       52       53       54       54  
Thermal Export
    33       32       38       21       38       52       200       299  
Metallurgical Demand (includes Thermal Cross Over)
    86       84       82       69       70       81       87       93  
 
 
Source: Wood Mackenzie Long Term US Thermal Coal Market Outlook, October 2011
 
Wood Mackenzie estimates that demand for Illinois Basin coal will grow at a compound annual rate of 3.7%, taking total consumption from 114 million tons in 2011 to more than 225 million tons by 2030. This is compared to total U.S. coal production, which Wood Mackenzie estimates will grow at a compound annual


74


Table of Contents

rate of 0.2% over the same period. Importantly, Illinois Basin coal production is projected to grow more sharply over the 2010-2020 period (6.3% CAGR) than over the latter part of the 20-year projection period.
 
(GRAPH)
 
 
Source: Wood Mackenzie
 
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
 
(PIE CHART)
 
 
Source: BP Statistical Review of World Energy, June 2011
 
Thermal coal fueled 44% of electricity generation in 2007 and is projected by EIA to fuel 43% of world electricity generation in 2035. Coal’s relative abundance, wide distribution, competitive pricing and favorable transportation profile has facilitated its global adoption as a reliable electricity generation fuel. The rapid industrialization of the emerging Asian economies, particularly China and India, are supporting forecasts for significant increases in seaborne thermal coal trade. In 2010, Asia accounted for 66% of world thermal coal imports.
 
The Australian Bureau of Agricultural and Resource Economics and Sciences (ABARES) projects world thermal coal trade will grow by 4% annually to 1.1 billion tons in 2016, with Asia accounting for more than 717 million tons of import demand, up from 562 million tons in 2010.


75


Table of Contents

In the Atlantic thermal coal market, European Union and other European coal imports are projected to rise from 207 million tons in 2010 to 246 million tons by 2016.
 
We believe the projected robust growth in global thermal coal trade to satisfy growing demand for electricity generation will create substantial opportunities for U.S. coal producers with competitive transportation advantages to profitably export thermal coal.
 
The Illinois Basin coal production region is strategically well positioned with access to the Green, Ohio and Mississippi River systems to deliver coal to New Orleans or Port of Mobile coal export terminals for delivery of coal to growing Atlantic and Pacific import coal consumers.
 
Costs and Pricing Trends
 
Coal prices are influenced by a number of factors and vary materially by region. As a result of these regional characteristics, prices of coal by product type within a given major coal producing region tend to be relatively consistent with each other. The price of coal within a region is influenced by market conditions, coal quality, transportation costs involved in moving coal from the mine to the point of use and mine operating costs. For example, higher carbon and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices within a given geographic region.
 
The cost of coal at the mine is also influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Within a particular geographic region, underground mining is generally more expensive than surface mining. This is due to typically higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs arising from lower productivity associated with underground mining.
 
During the past decade, the price of coal has fluctuated like any commodity as a result of changes in supply and demand. For example, when coal supplies declined from 2003 to part of 2006 and subsequently for a short time in 2007 and 2008, the prices for coal reached record highs in the United States. The increased worldwide demand for coal is being driven by higher prices for oil, together with overseas economic expansion in countries such as China and India who rely heavily on coal-fired electricity generation. At the same time, infrastructure, weather-related production interruptions and supply restrictions on exports from China and Indonesia have contributed to a tightening of worldwide thermal coal supply, affecting global prices of coal.
 
Coal Characteristics
 
The quality of coal is measured primarily by its heat content in British thermal units per pound (“Btu/lb”). However, sulfur, ash and moisture content, and volatile content and coking characteristics are also important variables in the ranking and marketing of coal. These characteristics help producers determine the best end use of a particular type of coal. The following is a description of these general coal characteristics:
 
Heat Value.  In general, the carbon content of coal supplies most of its heating value, but other factors also influence the amount of energy it contains per unit of weight. Coal with higher heat value is priced higher than coal with lower heat value because less coal is needed to generate the same quantity of electric power. Coal is generally classified into four categories, ranging from lignite, subbituminous, bituminous and anthracite, reflecting the progressive response of individual deposits of coal to increasing heat and pressure. Anthracite is coal with the highest carbon content and, therefore, the highest heat value, nearing 15,000 Btus/lb. Bituminous coal, used primarily to generate electricity and to make coke for the steel industry, has a heat value ranging between 10,500 and 15,500 Btus/lb. Subbituminous coal ranges from approximately 8,000 to 9,500 Btus/lb and is generally used for electric power generation. Finally, lignite coal is a geologically young coal and has the lowest carbon content, with a heat value ranging between approximately 4,000 and 8,000 Btus/lb.
 
Sulfur Content.  When coal is burned, SO2 and other air emissions are released. Federal and state environmental regulations limit the amount of SO2 that may be emitted as a result of combustion. Following the implementation of the Clean Air Act Title IV amendments, coal’s sulfur content could be categorized as


76


Table of Contents

“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 coal’s 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.
 
U.S. Coal Producing Regions
 
(MAP)
 
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


77


Table of Contents

centers are Northern and Central Appalachia, the Illinois Basin in the Interior region, and the Powder River Basin in the Western region. The type, quality and characteristics of coal vary by, and within each, region.
 
Appalachian Region.  The Appalachian region is divided into the Northern, Central and Southern regions, with the Northern and Central areas being the largest coal producers in the region. Northern Appalachia includes Ohio, Pennsylvania, Maryland and northern West Virginia. The area includes reserves of bituminous coal with heat content ranging from 10,300 to 13,000 Btu/lb) and sulfur content ranging from 1.0% to 2.0%. Coal produced in Northern Appalachia is marketed primarily to electric utilities, industrial consumers and the export market, with some metallurgical coal marketed to steelmakers.
 
Central Appalachia includes eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The area includes reserves of bituminous coal with a typical heat content of 12,000 Btu/lb or greater and sulfur content ranging from 0.5% to 1.5%. Coal produced in Central Appalachia is marketed primarily to electric utilities, with metallurgical coal marketed to steelmakers. The combination of reserve depletion and increasing regulatory enforcement, mining costs and geologic complexity in Central Appalachia is expected to lead to substantial production declines over the long term. In fact, actual production has declined from approximately 257 million tons in 2000 to 186 million tons in 2010. In addition, the widespread installation of scrubbers is expected to enable higher sulfur coal from Northern Appalachia and the Illinois Basin to displace coal from Central Appalachia.
 
Interior Region.  The major coal producing center of the Interior region is the Illinois Basin, which includes Illinois, Indiana and western Kentucky. The area includes reserves of bituminous coal with a heat content ranging from 10,100 to 12,600 Btu/lb and sulfur content ranging from 1.0% to 4.3%. Despite its high sulfur content, coal from the Illinois Basin can generally be used by some electric power generation facilities that have installed pollution control devices, such as scrubbers, to reduce emissions. Most of the coal produced in the Illinois Basin is used in the generation of electricity, with small amounts used in industrial applications. The EIA forecasts that production of high sulfur coal in the Illinois Basin, which has trended down since the early 1990s when many coal-fired plants switched to lower sulfur coal to reduce SO2 emissions after the passage of the Title IV amendments to the Clean Air Act, will significantly rebound as existing coal-fired capacity is retrofitted with scrubbers and new coal-fired capacity with scrubbers is added.
 
Western Region.  The Western United States region includes, among other areas, the Powder River Basin, the Western Bituminous region (including the Uinta Basin) and the Four Corners area. The Powder River Basin, the Western Region’s 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.


78


Table of Contents

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 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 purchaser’s 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.


79


Table of Contents

 
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 lessee’s 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 lessee’s 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 lessee’s 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 lessee’s 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 lessee’s mining operations, including any damages we may incur on account of our lessee’s 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 66 million tons of coal reserves and have a 39.45% undivided interest in approximately 138 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


80


Table of Contents

outstanding limited partnership interests (“common units”), representing 99.6% 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 September 30, 2011 we were owed approximately $4.1 million from Armstrong Energy.
 
We intend to use the net proceeds from this offering, plus any amount owed to us at the time of the Concurrent AE Offering (see “— Concurrent Offering”) for deferred royalty payments, to purchase an additional interest in the reserves in which we currently have a 39.45% interest. As a result, upon the closing of this offering, we expect to have an approximate           undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves which 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 Energy’s $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 Energy’s 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 Energy’s 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 Energy’s control of Elk Creek, GP, our results are consolidated in Armstrong Energy’s 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 the nine months ended September 30, 2011, Armstrong Energy is obligated to pay us $5.4 million 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 $0.8 million in the nine months ended September 30, 2011.
 
On October 11, 2011, we entered into an agreement with Armstrong Energy to purchase an additional partial undivided interest in substantially all of the coal reserves and real property owned by Armstrong Energy previously subject to the options exercised by Armstrong Resource Partners on February 9, 2011. We intend to use the net proceeds from this offering to purchase an additional interest in the reserves in which we currently have a 39.45% interest. As a result, upon the closing of that transaction, we expect to have a          


81


Table of Contents

undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves. See “Certain Relationships and Related Party Transactions — Western Diamond and Western Land Coal Reserves Sale Agreement.”
 
We are headquartered in St. Louis, Missouri.
 
Strategy
 
Our primary business strategy is to establish and grow our proven and probable reserves so that we will be able to generate royalties to make cash available for distribution to our unitholders by executing the following:
 
  •  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. We initially intend to defer the royalties earned under our leases in order to acquire an increasing percentage interest in those reserves that currently generate our income.
 
  •  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.
 
  •  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.
 
Competitive Strengths
 
We believe that the following competitive strengths will enable us to effectively execute our business strategy:
 
  •  Our lessee has a demonstrated track record for successfully completing reserve acquisitions, securing required permits, developing new mines and producing coal.  Since Armstrong Energy’s formation in 2006, it has successfully acquired coal reserves and opened seven separate mines, obtained the necessary regulatory permits for the commencement of mining operations at those mines, and developed significant multi-year contractual relationships with large customers in its market area. We believe this resulted from Armstrong Energy’s 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.
 
  •  Our proven and probable reserves have a long reserve life and attractive characteristics.  As of September 30, 2011, we either owned or had an interest in approximately 204 million tons of clean recoverable (proven and probable) coal reserves. Our reserves represent underground mineable coal, which, in combination with our lessee’s coal processing facilities, enhance our lessee’s 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.
 
  •  Our reserves are strategically located to allow access to multiple transportation options for delivery.  Our lessee’s 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


82


Table of Contents

  of New Orleans. We believe this will also enable Armstrong Energy to sell our coal in both the domestic and export markets.
 
  •  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.
 
  •  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 Energy’s senior management team have a demonstrated track record of acquiring, building and operating coal businesses profitably and safely. In addition, members of Armstrong Energy’s senior management team have significant experience managing the financial and organizational growth of businesses, including public companies.
 
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.
 
(CHART)
 
 
(1) Reserves owned solely by Armstrong Resource Partners. These include the Kronos, Lewis Creek and Ceralvo underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a 39.45% undivided interest) and Armstrong Energy (with a 60.55% undivided interest). If 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.”


83


Table of Contents

 
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.
 
(CHART)
 
 
(1) Reserves owned solely by Armstrong Resource Partners. These include the Kronos, Lewis Creek and Ceralvo underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a     % undivided interest) and Armstrong Energy (with a     % undivided interest), assuming an offering price of $      per unit, the midpoint of the price range set forth on the front cover page of this prospectus and an estimated purchase price of $      for our additional interest in the partially owned reserves.
 
Our Coal Reserves and Production
 
As of September 30, 2011, we had the rights to approximately 66 million tons and rights as joint-tenants-in common with Armstrong Energy to 138 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


84


Table of Contents

sole lessee, Armstrong Energy. The following table summarizes our coal reserves. All of our reserves are leased to Armstrong Energy.
 
                                                                                 
          Gross Clean Recoverable Tons
    Net Clean Recoverable Tons
    Quality Specifications
 
          (Proven and Probable
    (Proven and Probable
    (As Received)(2)  
          Reserves)(1)     Reserves)(1)           SO2
       
    Mining
    Proven
    Probable
          Proven
    Probable
          Heat Value
    Content
    Ash
 
    Method(3)     Reserves     Reserves     Total     Reserves     Reserves     Total     (Btu/Lb)     (Lbs/MMBtu)     (%)  
          (In thousands)     (In thousands)                    
 
Owned Reserves
                                                                               
Elk Creek(4)
    U       56,586       9,055       65,591       56,586       9,005       65,591       11,792       4.5       7.6  
Partially Owned Reserves
                                                                               
Reserves in Active Production(5)
                                                                               
Big Run(6)
    U       2,849       242       3,091       1,124       95       1,219       11,822       4.3       7.4  
Midway
    S       24,806       3,507       28,313       9,785       1,384       11,169       11,315       4.8       10.0  
Parkway
    U       1,952       58       2,010       770       23       793       11,931       4.4       7.1  
East Fork(7)
    S       2,633       553       3,186       1,039       218       1,257       11,136       7.6       11.2  
Equality Boot
    S       23,687       1,148       24,835       9,344       454       9,798       11,587       5.7       8.8  
Lewis Creek
    S       6,650       70       6,720       2,623       28       2,651       11,420       4.0       9.5  
                                                                                 
Total Partially Owned Reserves in Active Production
            62,577       5,578       68,155       24,685       2,202       26,887                          
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       37,233 (8)     11,648       48,881 (9)     14,689       4,596       19,285       11,300       4.5       8.0  
                                                                                 
Total Additional Reserves
            54,399       15,502       69,901       21,461       6,116       27,577                          
                                                                                 
Total
            173,562       30,085       203,647       102,732       17,323       120,055                          
                                                                                 
 
 
(1) Determined as of December 31, 2010. 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 Energy’s 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) Of the approximately 65.6 million Elk Creek gross clean recoverable tons and net clean recoverable tons, approximately 62.1 million tons are owned and approximately 3.5 million tons are leased. We commenced production at the Kronos mine in September 2011.
 
(5) Reserves that are in active production as of October 1, 2011.
 
(6) Big Run ceased production in October 2011.
 
(7) Warden and Kronos pits.
 
(8) Includes 167,000 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.
 
(9) Includes 972,000 tons related to reserves for which Armstrong Energy owns or leases from us a 50% or more partial joint interest and royalties on extractions may be payable to other owners.


85


Table of Contents

 
The following table summarizes the ownership status of our reserves by mine and our lessee’s historical production from our coal reserves. Our acquisition of our ownership interest in these reserves became effective February 9, 2011.
 
                                                                                 
                      Net Clean
    Gross Production(2)     Net Production(2)  
    Gross Clean
    Recoverable Tons
          Nine Months
          Nine Months
 
    Recoverable Tons
    (Proven and Probable
    Year Ended
    Ended
    Year Ended
    Ended
 
    (Proven and Probable Reserves)(1)     Reserves)(1)     December 31,
    September 30,
    December 31,
    September 30,
 
Reserve
  Owned     Leased     Total     Owned     Leased     Total     2010     2011     2010     2011  
    (In thousands)     (In thousands)     (Tons in thousands)     Pro forma
 
                      (Tons in thousands)  
 
Owned
                                                                               
Elk Creek(3)
    62,066       3,525       65,591       62,066       3,525       65,591             9.6             9.6  
Partially Owned
                                                                               
Big Run(4)
    3,091             3,091       1,219             1,219       572.1       361.5       225.7       142.6  
Midway
    28,313             28,313       11,169             11,169       1,614.8       1,290.4       637.0       509.1  
Parkway
    312       1,698       2,010       123       670       793       1,485.9       1,165.6       586.2       459.8  
East Fork
    2,302       884       3,186       908       349       1,257       1,641.1       608.6       647.4       240.1  
Equality Boot(5)
    24,835             24,835 (6)     9,798             9,798       330.8       1,493.3       130.5       589.1  
Lewis Creek (surface)(7)
    6,720             6,720       2,651             2,651             197.0             77.1  
                                                                                 
Total Partially Owned
    65,574       2,582       68,155       25,869       1,018       26,887       5,644.7       5,126.0       2,226.8       2,027.4  
                                                                                 
Total
    127,640       6,107       133,746       87,935       4,543       92,478       5,644.7       5,135.6       2,226.8       2,037.0  
                                                                                 
 
 
(1) For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.
 
(2) Determined as of December 31, 2010. 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 net production began in February 2011 and amounted to approximately 1,810,000 tons for the nine months ended September 30, 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 Energy’s coal reserves. See “Use of Proceeds.”
 
(3) Commenced production in September 2011.
 
(4) Big Run ceased production in October 2011.
 
(5) Commenced production in September 2010.
 
(6) Includes 167,000 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) Commenced production in June 2011.
 
About Armstrong Energy, Inc.
 
Armstrong Energy, Inc. was formed in 2006 to acquire and develop a large coal mining operation. Armstrong Energy holds a 0.4% equity interest in us through its wholly-owned subsidiary, Elk Creek GP, which is our general partner. Of Armstrong Energy, Inc.’s total controlled reserves of 319 million tons, 66 million tons (21%) are wholly owned by us, and 138 million tons (43%) are held by Armstrong Energy and us as joint tenants-in-common with 60.55% and 39.45% 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 2010 production, Armstrong Energy is the sixth largest producer in the Illinois Basin and


86


Table of Contents

the second largest in Western Kentucky. It commenced production in the second quarter of 2008 and currently operates six mines, including four surface and two underground mines. In addition, Armstrong Energy is seeking permits for four additional mines. Permit applications for the Hickory Ridge surface mine have been submitted to the Corps and the State of Kentucky but have yet to be issued. Armstrong Energy is also in the process of preparing permit applications relating to Ken surface mine and the Lewis Creek and Ceralvo underground mines. Armstrong Energy intends to submit those permit applications to the Corps and the State of Kentucky beginning in January 2012. Since beginning operations in 2007, Armstrong Energy’s revenue has grown to $220.6 million in 2010. For the year ended December 31, 2010, Armstrong Energy produced 5.6 million tons of coal from three surface and two underground mines. During the nine months ended September 30, 2011, it produced 5.1 million tons of coal, with seven mines in operation, and currently expects a significant increase in its production for 2011 compared to 2010. 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 Energy’s 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 September 30, 2011.
 
We are a co-borrower under Armstrong Energy’s $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 Energy’s 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 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 Energy’s ability to meet its obligations under the


87


Table of Contents

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 Energy’s 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 Energy’s 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 Energy’s 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 Energy’s current estimates of production for 2011 and 2012, we anticipate that Armstrong Energy will owe us royalties under the above-mentioned license and lease arrangements of approximately $7.8 million and $16.6 million in 2011 and 2012, respectively, of which collectively, $7.2 million will be recoupable against the advance royalty payment referred to above.
 
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 Energy’s agreement to sell a partial undivided interest in those reserves, we paid Armstrong Energy $20.0 million. The partial undivided interest in additional reserves must be transferred to us within 90 days after delivery of the purchase price. Following receipt of the proceeds of this sale, Armstrong Energy acquired, in December 2011, additional property near its existing and planned mines containing an estimated total of 7.7 million clean recoverable tons of coal and entered into leases for an estimated 14 million clean recoverable tons. In addition, Armstrong Energy entered into a joint venture with an affiliate of Peabody Energy Corporation (“Peabody”) relating to coal reserves near its Parkway mine. In connection with the joint venture, Peabody has agreed to contribute an aggregate of approximately 25 million clean recoverable tons of coal and Armstrong Energy has agreed to contribute mining assets to the joint venture.
 
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 0.4% equity interest in us. See “Business — Our Organizational History.” If the Concurrent AE Offering is completed, we expect that the net proceeds received by Armstrong Energy will be applied as described in “Use of Proceeds.” While Armstrong Energy intends to consummate the Concurrent AE Offering


88


Table of Contents

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.
 
Our Lessee’s Mining Operations
 
Armstrong Energy currently operates six 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 four surface mines and two underground mines, with three preparation plants serving these operations. In addition, Armstrong Energy is seeking permits for four additional mines. Permit applications for the Hickory Ridge surface mine have been submitted to the Corps and the State of Kentucky but have yet to be issued. Armstrong Energy is also in the process of preparing permit applications relating to Ken surface mine and the Lewis Creek and Ceralvo underground mines. Armstrong Energy intends to submit those permit applications to the Corps and the State of Kentucky beginning in January 2012. In 2010, approximately 64% of the coal that Armstrong Energy produced came from its surface mining operations.
 
Armstrong Energy’s 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 Energy’s 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 Energy’s mining operations and coal reserves:
 
(MAP)
 
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


89


Table of Contents

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 66 million tons of coal reserves and have a 39.45% undivided interest in approximately 138 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 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 Mineral’s pro rata share of the 7% production royalty described under “— Lease Agreements” below. In consideration for Western Mineral’s 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 Big Run ceased and the equipment that had been used to extract thermal coal from the West Kentucky #9 seam was relocated to the Kronos mine. The Kronos mine commenced production in September 2011. Big Run produced approximately 0.4 million clean tons of coal in 2011, which was processed at Armstrong Energy’s Midway Preparation Plant.
 
Midway Mine.  Midway is a surface mine located two miles southeast of Centertown, Kentucky in Ohio County and is west of and adjacent to the Midway Preparation Plant. The Midway Mine commenced production in April 2008 and extracts thermal coal from the West Kentucky #13a, #13, and #11 seams. Stripping ratios for coal that has not undergone any processing, or “run-of-mine” coal, at the Midway Mine are favorable and range from 12 to 13.5-to-1. Midway is expected to produce approximately 1.6 million tons of clean coal in 2011 and is currently equipped with one dragline (45 yard bucket) and a spread of surface mining equipment, including power shovels, excavators, loaders and haul trucks. Our reserve studies have indicated that Midway has approximately 28 million tons of proven and probable reserves. Coal from the


90


Table of Contents

Midway mine is transported less than one mile to the Midway Preparation Plant for processing, where it is then shipped to customers via truck, rail or barge.
 
Parkway Mine.  Parkway is an underground mine located northeast of Central City, Kentucky in Muhlenberg County that extracts thermal coal primarily from the West Kentucky #9 seam and accesses that seam from an older surface mining pit that was abandoned prior to our acquisition of Parkway. Parkway consists of two working super sections, and each section is currently equipped with two continuous miners that operate concurrently. Parkway is expected to produce approximately 1.6 million tons of clean coal in 2011. Additional reserves that we do not currently control are located adjacent to the current Parkway reserves that could extend the life of the Parkway mine. The majority of the coal from the Parkway mine is transported to the surface stockpile where it is processed at the Parkway Preparation Plant and trucked to a single customer via a seven mile private haul road.
 
East Fork Mine.  East Fork is a surface mine located three miles west of Centertown, Kentucky. The East Fork complex consists of two pits, the Warden and Kronos pits, which extract thermal coal from the West Kentucky #14 seam. The Kronos pit commenced operations in June 2009, and the Warden pit commenced operations in August 2009. East Fork is expected to produce approximately 0.8 million tons of clean coal in 2011, and there were approximately 3.2 million tons of proven and probable reserves at the East Fork mine at December 2010. We currently anticipate that production at the Kronos pit will continue until late 2011 while production at the Warden pit will continue through 2013. East Fork run-of-mine coal is trucked 3.6 miles to the Armstrong Dock Preparation Plant via a private haul road where it is processed, blended and shipped to customers.
 
Equality Boot Mine.  Equality Boot is a surface mining operation located eight miles southwest of Centertown, Kentucky, which commenced operations in September 2010. The Equality Boot mine extracts thermal coal from the West Kentucky #14, #13, #12 and #11 seams and is expected to produce approximately 2.3 million tons of coal in 2011. The Equality Boot mine uses two draglines equipped with 45 yard buckets and a spread of surface equipment, including power shovels, excavators, loaders and haul trucks to remove overburden and interburden and construct the dragline bench. Run-of-mine stripping ratios at the Equality Boot mine are favorable and have averaged less than 10-to-1, a trend we expect to continue. Equality Boot has approximately 25 million tons of proven and probable reserves. Coal from the Equality Boot mine is transported less than one mile by truck to the Equality Boot run-of-mine facility, where a 4,400 foot overland conveyor system is used to transport the coal to the 2,500 tons per hour barge loadout facility located on the Green River.


91


Table of Contents

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.
 
(GRAPH)
 
Lewis Creek Mine.  The Lewis Creek mine is a surface mine located approximately five miles south of Centertown, Kentucky and approximately 3.5 miles from the Midway Preparation Plant. Production commenced in June 2011 at Lewis Creek, and thermal coal is being mined from the West Kentucky seams #13A and #13. Lewis Creek is expected to produce approximately 0.5 million tons of clean coal in 2011. A dragline equipped with a 20 yard bucket is used in conjunction with mobile mining equipment to remove overburden and construct the dragline bench at Lewis Creek. There are approximately 7 million tons of proven and probable reserves at the Lewis Creek surface mine. Coal mined at Lewis Creek is transported by truck to the Midway Preparation Plant for processing and subsequent delivery to our customers.
 
Kronos Mine.  The Kronos mine, which commenced operations in September 2011, is an underground mine located approximately three miles southwest of Centertown, Kentucky. It will extract thermal coal from the West Kentucky #9 seam and is expected to produce approximately 0.4 million tons of clean coal in 2011. The mine currently utilizes two continuous miner super sections, but we expect to increase to four super sections in early 2012. At that time, we expect that the mine’s annual production will be 2.4 million tons. There are approximately 22 million tons of proven and probable reserves at the Kronos mine. Coal mined at Kronos is transported by truck to the Midway Preparation Plan and the Armstrong Dock Preparation Plant for processing and delivery.
 
Future Underground Mines.  Armstrong Energy anticipates opening the Lewis Creek underground mine in 2013 and the Ceralvo underground mine in 2015 in Ohio County, Kentucky, assuming that it receives all necessary permits for operation of those mines. Both mines will produce coal from the West Kentucky #9 seam utilizing two continuous miner super sections operating concurrently. Once fully operational, the Lewis Creek and Ceralvo


92


Table of Contents

underground mines are projected to produce approximately 1 million tons each of clean coal per year. There are approximately 22 million tons of proven and probable reserves at each of the Lewis Creek and Ceralvo reserves.
 
Future Surface Mines.  Armstrong Energy anticipates opening the Hickory Ridge, Ken and Maddox surface mines in 2013 and 2014. These surface mines will produce thermal coal from primarily the West Kentucky #14, #13, #13A and #11 seams. Conventional truck-and-shovel operations are anticipated to be used at all of the mines. The Hickory Ridge, Ken and Maddox surface mines have approximately 23 million tons in the aggregate of proven and probable reserves.
 
Coal Preparation Facilities
 
The majority of coal from each of Armstrong Energy’s 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 2010, Armstrong Energy’s preparation plants processed approximately 98% 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 lessee’s preparation plants do not process coal from other companies, and Armstrong Energy does not have any present intention to do so.
 
The following chart provides information regarding Armstrong Energy’s preparation plants:
 
             
   
Midway
 
Parkway
 
Armstrong Dock
 
Location:
  Centertown, Kentucky   Central City, Kentucky   Centertown, Kentucky
Inception:
  July 2008   April 2009   March 2010
Mines Serviced:
  Midway, Big Run, 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 expandable to 1,200 TPH.
 
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


93


Table of Contents

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 Energy’s 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) Jacob’s Creek, Sunnyside (part), Hillside, Cypress Creek and 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), Ben’s 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 nine months ended September 30, 2011.
 
         
Reserves
  Royalty Revenue
    (In thousands)
 
Elk Creek Reserves
  $ 43  
Armstrong Energy Reserves(1)
    5,371  
         
Total
  $ 5,414  
         
 
 
(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 2010 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 six mines, including four surface and two underground, and is seeking permits for four additional mines. Armstrong Energy controls approximately 319 million tons of proven and probable coal reserves, which includes approximately 138 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 Energy’s operations, adjacent to the Green and Ohio Rivers, together with Armstrong Energy’s river dock coal handling and rail loadout facilities, allow it to optimize coal blending and handling,


94


Table of Contents

and provide its customers with rail, barge, and truck transportation options. From Armstrong Energy’s 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, 2010, Armstrong Energy produced 5.6 million tons of coal from three surface and two underground mines. During the nine months ended September 30, 2011, Armstrong Energy produced 5.1 million tons of coal, with six mines in operation. Armstrong Energy currently expects a significant increase in its production for 2011 compared to 2010. Armstrong Energy is contractually committed to sell 7.6 million tons of coal in 2011, which represents substantially all of its currently estimated production for 2011. Similarly, as of September 30, 2011, Armstrong Energy is contractually committed to sell 8.8 million tons of coal in 2012 and 8.1 million tons of coal in 2013, which represents 99% and 83% of its expected total coal sales in 2012 and 2013, respectively.
 
Our Lessee’s 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 sales prices. In 2010, Armstrong Energy sold approximately 90% 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 Energy’s 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 September 30, 2011, Armstrong Energy had 11 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 Energy’s 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 Energy’s 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 lessee’s 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 Energy’s agreements fix annual pricing and volume obligations, though, in certain instances, the volume obligations may change depending on the customer’s 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 Energy’s 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 Energy’s 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.


95


Table of Contents

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.
 
(MAP)
 
Armstrong Energy’s primary customers are electric utilities. It may also sell coal to industrial companies, brokers and other coal producers. For the year ended December 31, 2010 and the nine months ended


96


Table of Contents

September 30, 2011, approximately 96% and 94%, respectively, of Armstrong Energy’s coal revenues related to sales to electric utilities. The majority of Armstrong Energy’s 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 2010, Armstrong Energy sold coal to eight domestic customers with operations located in numerous states. The majority of those customers operate power plants in the Midwestern and Southern regions of the United States. For the year ended December 31, 2010, Armstrong Energy derived approximately 76% of its total coal revenues from sales to its two largest customers — Tennessee Valley Authority (“TVA”) and Louisville Gas and Electric (“LGE”). For the fiscal year ended December 31, 2010, coal sales to TVA and LGE constituted approximately 40% and 36% of Armstrong Energy’s 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 2.0 million tons annually from 2012 through 2018. The price ranges from $40.57 to $41.68 per ton in 2011 and 2012. The agreement then provides that either party may elect at its sole option to reopen the agreement for negotiations with respect to price and/or other terms as it concerns all coal to be delivered in 2013 and beyond. Should either party seek to reopen the agreement (which must be done by no later than April 1, 2012) and the parties are unable to reach a mutually acceptable agreement as to those terms being renegotiated, the agreement will terminate as of December 31, 2012. The agreement also provides for typical quality adjustments. In addition, commencing on July 1, 2011, TVA has the unilateral right to terminate the agreement upon 60 days written notice, in which case TVA is required to pay us a termination fee equal to 10% of the base price multiplied by the remaining number of tons to be delivered under the agreement.
 
The agreement with TVA that was entered into in 2008 calls for delivery of between 0.9 million and 1.1 million tons annually from 2009-2013. The price ranges from $56.00 to $58.00 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 37% of Armstrong Energy’s coal shipped in 2010 was delivered by barge, which is generally less expensive than transporting coal by truck or rail. The Armstrong Dock, which is located on the Green River, can load up to six million tons of coal annually for shipment on inland waterways. For the nine months ended September 30, 2011, 50%, 27% and 23% of Armstrong Energy’s coal sales tonnage was shipped by barge, truck and rail, respectively.


97


Table of Contents

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 Energy’s main competitors include Alliance Resource Partners, L.P., Patriot Coal Corp., Peabody Energy, Inc., the Cline Group’s 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 2010, producing approximately 5% 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 Energy’s 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 Energy’s employees in exchange for a monthly fee. See “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”
 
Seasonality
 
Our lessee’s 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 lessee’s 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:
 
  •  employee health and safety;
 
  •  permitting and licensing requirements;
 
  •  air quality standards;


98


Table of Contents

 
  •  water pollution;
 
  •  storage, treatment and disposal of wastes;
 
  •  protection of plant life and wildlife, including endangered or threatened species;
 
  •  reclamation and restoration of mining properties after mining is completed;
 
  •  remediation of contaminated soil and groundwater;
 
  •  surface subsidence from underground mining;
 
  •  the effects of mining on surface and groundwater quality and availability; and
 
  •  competing uses of adjacent, overlying or underlying lands, pipelines, roads, and public facilities.
 
In addition, many of our lessee’s 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 lessee’s 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 lessee’s 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.


99


Table of Contents

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 lessee’s 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 lessee’s 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 state’s 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 OSM’s 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


100


Table of Contents

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 lessee’s 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 SMCRA’s adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines and $0.135 per ton on deep-mined coal from 2008 to 2012, with reductions to $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from 2013 to 2021. In 2010, our lessee recorded approximately $1.3 million of expense related to these reclamation fees.
 
Surety Bonds
 
Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. The cost of surety bonds 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 lessee’s 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 lessee’s reclamation obligations. Many of these bonds are renewable on a yearly basis. We cannot predict our lessee’s ability to obtain bonds, or other approved forms of performance security, or the cost of such security, in the future. As of September 30, 2011, our lessee had approximately $16.5 million in surety bonds outstanding to secure the performance of our lessee’s 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


101


Table of Contents

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 lessee’s 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 lessee’s 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 lessee’s 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 lessee’s 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 lessee’s 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 lessee’s 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.


102


Table of Contents

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 lessee’s 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 lessee’s operations, directly or indirectly, include, but are not limited to, the following:
 
  •  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.
 
  •  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 lessee’s customers’ current or anticipated future costs of using coal. In addition, NAAQSs for particulate matter may affect aspects of our lessee’s 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


103


Table of Contents

  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 EPA’s 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.
 
  •  Cross-State Air Pollution Rule.  In July 2011, the EPA promulgated the CSAPR, which replaces the EPA’s 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.
 
  •  Mercury.  In May 2011, the EPA formally proposed its rule to establish a national standard to reduce mercury and other toxic air pollutants from coal and oil-fired power plants, sometimes referred to as the EPA’s Mercury and Air Toxics Standards (“MATS”) proposed rule. The EPA is obligated to finalize the rule by November 2011, under a consent decree of the U.S. Court of Appeals for the District of Columbia Circuit in the proceeding that resulted in that court’s vacating the EPA’s Clean Air Mercury Rule (“CAMR”), which was issued in 2005 and had established a cap and trade program to reduce mercury emissions from power plants. At present, there are no federal regulations that require monitoring and reducing of mercury emissions at existing power plants. In the meantime, case-by-case MACT determinations for mercury may be required for new and reconstructed coal-fired power plants. Apart from CAMR, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has also been proposed from time to time. In addition, in March 2011, EPA issued new MACT determinations for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury, although in May the effective date of these rules for major sources was delayed for reconsideration of certain aspects of the rule.
 
  •  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.
 
  •  New Source Review.  A number of enforcement actions in recent years are affecting the impact of the EPA’s 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


104


Table of Contents

  certain modifications, to install the same air emissions control equipment as new plants. Enforcement proceedings alleging that such modifications were made without implementing the required control equipment have resulted in a number of settlements involving commitments, including those by coal-fired power plants, to incur extensive air emissions controls involving substantial expenses. Such enforcement, and other changes affecting the scope or interpretation of aspects of the NSR program, may impact demand for coal, but we are unable to predict the magnitude of any such impact on us with any reasonable degree of certainty.
 
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 lessee’s 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, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. To date, the U.S. has not ratified the Kyoto Protocol, which expires in 2012. The United States is participating in international discussions currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. A replacement treaty or other international arrangement requiring additional reductions in greenhouse gas emissions could have a potentially significant impact on the demand for coal, particularly if the United States were to adopt it but, depending on the requirements it imposes and the extent to which other nations adopt it, even if the United States does not adopt it.
 
Future regulation of greenhouse gases in the United States could occur pursuant to, for example, future U.S. treaty commitments; new domestic legislation that imposes a tax on greenhouse gas emissions, a greenhouse gas cap-and-trade program or other programs aimed at greenhouse gas reduction; or regulatory programs that may be established by the EPA under its existing authority. Congress has actively considered various proposals to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power, promote the use of clean energy and require energy efficiency measures. In June 2009, the House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act, and the Senate has considered similar legislation that would, among other things, impose a nationwide cap on greenhouse gas emissions and require major sources, including coal-fired power plants, to obtain “allowances” to meet that cap. Passage of such comprehensive climate change or energy legislation could impact the demand for coal. Any reduction in the demand for coal by North American electric power generators could reduce the price of coal that we mine and sell and thereby reduce our revenues, which could have a material adverse affect on our business and the results of our operations.
 
Even in the absence of new federal legislation, greenhouse gas emissions may be regulated in the future by the EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. Environmental Protection Agency that the EPA has authority to regulate greenhouse gas emissions under the Clean Air Act, the EPA has taken several steps towards implementing regulations regarding greenhouse gas emissions. In December 2009, the EPA issued a finding that CO2 and certain other greenhouse gases emitted by motor vehicles endanger public health and the environment. This finding allows the EPA to begin regulating greenhouse gas emissions under existing provisions of the Clean Air Act. In October 2009, the EPA published a final rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their greenhouse gas emissions to the EPA beginning in 2011 for emissions occurring in 2010. In May 2010, the EPA issued a final “tailoring rule” that determines which stationary sources of greenhouse emissions need to obtain a construction or operating permit, and install best


105


Table of Contents

available control technology for greenhouse gas emissions, under the Clean Air Act’s Prevention of Significant Deterioration or Title V programs when such facilities are built or significantly modified. Without the tailoring rule, permits would have been required for stationary sources with emissions that exceed either 100 or 250 tons per year (depending on the type of source), which the EPA considered not feasible. The tailoring rule substantially increases this threshold for greenhouse gas emissions to 75,000 tons per year beginning in January 2011, and further modifies the threshold after July 2011; the EPA has stated that the rule will be limited to the largest greenhouse gas emitters in the United States, primarily power plants, refineries, and cement production facilities that the EPA estimates are responsible for nearly 70% of greenhouse gas emissions from the country’s stationary sources. The tailoring rule also commits the EPA to undertake and complete another rulemaking by no later than July 2012 to, among other things, consider expanding permitting requirements to sources with greenhouse gas emissions greater than 50,000 tons per year. A number of lawsuits have been filed challenging the tailoring rule. The final outcome of federal legislative action on greenhouse gas emissions may change one or more of the foregoing final or proposed EPA findings and regulations. If the EPA were to set emission limits or impose additional permitting requirements for CO2 from coal-fired power plants, the amount of coal our customers purchase from us could decrease.
 
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 Jersey’s governor, and a bill passed by New Hampshire’s legislature but vetoed by its governor) to withdraw from RGGI. RGGI has been holding quarterly CO2 allowance auctions for its initial three-year compliance period from January 1, 2009 to December 31, 2011 to allow utilities to buy allowances to cover their CO2 emissions. Midwestern states and Canadian provinces have also adopted initiatives to reduce and monitor greenhouse gas emissions. In November 2007, Illinois, Iowa, Kansas, Michigan, Minnesota, South Dakota and Wisconsin signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions; also, Indiana, Ohio and Manitoba signed as observers. Draft recommendations were released in June 2009, although they have not been finalized. Climate change initiatives are also being considered or enacted in some western states.
 
Also, litigation to address climate change impacts is being pursued against major emitters of greenhouse gases. A federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of CO2; while the United States Supreme Court recently reversed the appeals court, it did not reach the question whether state common law is available for such claims because that question had not been addressed by the lower court. A second federal appeals court had earlier dismissed a case seeking damages allegedly caused by climate change that had been filed against scores of large corporate defendants, including a number of electrical power generating companies and coal companies, but the dismissal was on procedural grounds; the case has since been re-filed. Claims seeking remedies to address conditions or losses allegedly caused by climate change that in turn allegedly has resulted from greenhouse gas-generating conduct by the defendants remain pending in the courts. Such claims could continue to be asserted against our lessee’s 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


106


Table of Contents

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 lessee’s current and prospective customers, their demand for coal-fueled power may decline, which may reduce long-term demand for our coal.
 
These and other current or future climate change rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to switch from coal to lower greenhouse gas emitting fuels or shut-down coal-fired power plants. There can be no assurance at this time that a greenhouse gas cap and trade program, a greenhouse gas tax or other regulatory regime, if implemented by the states in which our lessee’s 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 lessee’s costs and time spent on CWA compliance.
 
CWA requirements that may directly or indirectly affect our lessee’s operations include the following:
 
  •  Wastewater Discharge.  Section 402 of the CWA regulates the discharge of “pollutants” into navigable waters of the United States. The National Pollutant Discharge Elimination System (“NPDES”) requires a permit for any such discharges and entails regular monitoring, reporting, and compliance with performance standards, all of which are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. Failures to comply with the CWA or the NPDES permits can lead to the imposition of penalties, compliance costs, and delays in coal production. The CWA and corresponding state laws also protect waters that states have designated for special protections including those designated as: impaired (i.e., as not meeting present water quality standards) through Total Maximum Daily Load (“TMDL”) regulations and “high quality/exceptional use” streams through anti-degradation regulations which restrict or prohibit discharges which result in degradation. Likewise, when water quality in a receiving stream is better than required, states are required to adopt an “anti-degradation policy” by which further “degradation” of the existing water quality is reviewed and possibly limited. In the case of both the TMDL and anti-degradation review, the limits in our lessee’s 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


107


Table of Contents

  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.
 
  •  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.
 
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 EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. These letters have created regulatory uncertainty regarding the issuance of Section 404 permits for coal mining operations and have substantially expanded the time required for issuance of these permits, particularly in the Appalachian region.
 
In June 2009, the Corps, the EPA, and the Department of the Interior announced an interagency action plan for “enhanced coordination procedures” in reviewing any project that requires both a SMCRA and a CWA permit, designed to reduce the harmful environmental consequences of mountain-top mining in the Appalachian region. As part of this interagency memorandum of understanding, the Corps proposed to suspend and modify NWP 21 in the Appalachian region of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia to prohibit its use to authorize discharges of fill material into waters of the United States for mountain-top mining.
 
In June 2010, the Corps announced the suspension of the NWP 21 permitting process in the Appalachian region of the six states referred to above until the Corps takes further action on NWP 21, or until NWP 21 expires on March 18, 2012. While the suspension is in effect, proposed surface coal mining projects in the Appalachian region of these states that involve discharges of dredged or fill material into waters of the United States will have to obtain individual permits from the Corps. Projects currently permitted under NWP 21 are not affected by the suspension, and NWP 21 remains available for proposed surface coal mining projects outside the Appalachian region.
 
The EPA is also taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia, and announced in September 2009 that it was delaying the issuance of 74 Section 404 permits in central Appalachia. This is especially true in West Virginia, where the EPA plans to review all applications for NPDES permits even though the State of West Virginia is authorized to issue NPDES permits in West Virginia. In addition, in April 2010, the EPA issued an interim guidance document on water quality requirements for coal mines in Appalachia. This guidance follows up on the June 2009 enhanced coordination procedures memorandum for the issuance of Section 404 permits whereby the EPA undertook a new level of review of Section 404 permits than it


108


Table of Contents

had previously undertaken. Ultimately, the EPA identified 79 coal-related applications for Section 404 permits that would need to go through that process. The EPA’s 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 lessee’s 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.
 
Our lessee received notice from the EPA dated July 25, 2011 that the EPA believes that the proposed discharge plan submitted by our lessee in connection with our lessee’s Section 404 permit application for the expanded mining at our Midway Mine would result in unacceptable impacts on ARNIs, and in particular, downstream waters outside the scope of the permit area. As a result, it is possible that the Corps will deny our lessee’s pending permit application, or that the EPA will elevate the permit application to a higher level of review should the Corps proceed with the issuance of the permit notwithstanding EPA’s concerns. Ultimately, the EPA may consider initiating a Section 404(c) “veto” of the permit. A material delay in the issuance of this permit, or other Section 404 permits that our lessee may require as part of its mining operations, or the denial or veto of such permits, could have a materially negative effect on our lessee’s operations and our royalty revenues.
 
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 lessee’s 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.


109


Table of Contents

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 is expected to issue a final decision by the end of 2011. The EPA did not address in the proposed regulations the use of coal combustion wastes as minefill, but indicated that it would separately work with the Office of Surface Mining in order to develop effective federal regulations ensuring that such placement is adequately controlled. If coal ash from coal-fired power plants is re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. If coal ash is regulated under RCRA subtitle D, it could also adversely affect our customers and potentially reduce the desirability of coal for them. In addition, contamination caused by the past disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal and therefore, also our royalty revenues.
 
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 lessee’s mines are located are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or delaying our lessee from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road


110


Table of Contents

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 Energy’s 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 lessee’s customers to use coal. Federal, state, and local regulations also require regular monitoring of our lessee’s 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 Energy’s 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.


111


Table of Contents

 
MANAGEMENT
 
We do not have any officers or directors. The board of directors and executive officers of Armstrong Energy, Inc., the owner of our general partner, will manage our operations and activities. 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 the directors of Armstrong Energy 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.
 
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, three members of the Armstrong Energy board of directors serve on an audit committee which will review our external financial reporting, recommend engagement of our independent auditors, and review procedures for internal auditing and the adequacy of our internal accounting controls. Three members of the Armstrong Energy board of directors serve on a nominating and governance committee, which recommends nominees to serve on Armstrong Energy’s board 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 directors and officers 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 are managed by the board of directors of Armstrong Energy, the parent corporation of our general partner. Armstrong Energy’s board of directors currently consists of seven directors. 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.


112


Table of Contents

Executive Officers and Directors
 
As discussed above, we are managed by the executive officers and board of directors of Armstrong Energy. Set forth below are the names, ages and positions of the executive officers and directors of Armstrong Energy as of January 31, 2012. All directors are elected for a term of three years and serve until their successors are elected and qualified. All executive officers hold office until their successors are elected and qualified.
 
             
Name
 
Age
 
Position with the Partnership
 
J. Hord Armstrong, III
    70     Chairman (Class II) and Chief Executive Officer
Martin D. Wilson
    50     President and Director (Class I)
Kenneth E. Allen
    65     Executive Vice President of Operations
David R. Cobb, P.E. 
    63     Executive Vice President of Business Development
J. Richard Gist
    55     Senior Vice President, Finance and Administration and Chief Financial Officer
Brian G. Landry
    55     Vice President, Information Technology
Anson M. Beard, Jr. 
    75     Director (Class I)
James Crain
    63     Director (Class III)
Richard F. Ford
    75     Director (Class III)
Bryan H. Lawrence
    69     Director (Class III)
Greg A. Walker
    56     Director (Class II)
 
Biographical information concerning the directors and executive officers listed above is set forth below. The term of our Class I directors expires in 2012, the term of our Class II directors expires in 2013, and the term of our Class III directors expires in 2014.
 
J. Hord Armstrong, III — Mr. Armstrong served as the Chairman and Chief Executive Officer of Armstrong Energy’s predecessor entity (the “Predecessor”), and as a member of the Predecessor’s 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. 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&K’s 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 Energy’s strategies, challenges and opportunities.
 
Martin D. Wilson — Mr. Wilson served as the Predecessor’s President, and as a member of the Predecessor’s board of managers, from its formation in 2006 until the Reorganization in October 2011. Since the Reorganization, Mr. Wilson has been the President of Armstrong Energy. 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.


113


Table of Contents

Kenneth E. Allen — Mr. Allen served as the Predecessor’s Vice President of Operations from 2007 until the Reorganization in October 2011. Since the Reorganization, Mr. Allen has been Armstrong Energy’s 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 Predecessor’s Vice President of Business Development from its inception in 2006 until the Reorganization in October 2011. Since the Reorganization, Mr. Cobb has been Armstrong Energy’s 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 Predecessor’s Vice President and Controller from 2009 until the Reorganization in October 2011. Since the Reorganization, Mr. Gist has been Armstrong Energy’s 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 Predecessor’s 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 Energy’s board in October 2011. He joined Morgan Stanley & Co. as a Vice President to found Private Client Services in 1977. He was promoted to Principal in 1979 and Managing Director in 1980. In January 1981, he was put in charge of the Firm’s 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 Firm’s 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


114


Table of Contents

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 Energy’s board of directors in October 2011. Mr. Crain has been in the energy industry for over 30 years, both as an attorney and as an executive officer. Since 1984, Mr. Crain has been an officer of Marsh Operating Company, an investment management company focusing on energy investing, including his current position as president, which he has held since 1989. Mr. Crain has served as general partner of Valmora Partners, L.P., a private investment partnership that invests in the oil and gas sector, among others, since 1997. Before joining Marsh in 1984, Mr. Crain was a partner in the law firm of Jenkens & Gilchrist, where he headed the firm’s 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 Energy’s board in October 2011. Mr. Ford is the retired general partner of Gateway Associates, L.P., a venture capital management firm that he formed in 1984. Mr. Ford serves as a member of the board of directors and a member of the audit committees of each of Barry-Wehmiller Company and Stifel Financial Corp. Mr. Ford also serves as a member of the board of directors and chair of the audit committee of Spartan Light Metal Products, Inc., a privately-held company. He currently serves on the board of directors of Washington University in St. Louis, Missouri. The board selected Mr. Ford to serve as a director because of his substantial experience in the financial services industry. He also has considerable board and committee leadership experience at other publicly held and large private companies.
 
Bryan H. Lawrence — Mr. Lawrence served as a member of the Predecessor’s board of managers from its formation in 2006 until the Reorganization. He was appointed to Armstrong Energy’s board of directors in October 2011. He is a founder and principal of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co., Inc. where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence serves as a director of Crosstex Energy, Inc., Crosstex Energy GP, LLC, Hallador Energy Company, Star Gas Partners, L.P., and Approach Resources, Inc. (each a United States publicly traded company) and Winstar Resources, Ltd., (a Canadian public company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence serves on Armstrong Energy’s board of directors because of his significant knowledge of all aspects of the energy industry.
 
Greg A. Walker — Mr. Walker was appointed to Armstrong Energy’s board of directors in October 2011. From 2009 to January 2011, he served as a Senior Vice President of Alpha Natural Resources, Inc., assisting with integration issues after the merger of Alpha Natural Resources, Inc. and Foundation Coal Holdings, Inc. From 2004 to 2009, Mr. Walker served as the Senior Vice President, General Counsel and Secretary of Foundation Coal Holdings, Inc. From 1999 to 2004, he served as the Senior Vice President, General Counsel and Secretary of RAG American Coal Holdings, Inc., which was the predecessor entity to Foundation Coal Holdings, Inc. From 1989 through 1999, he served in various capacities in the law department of Cyprus Amax Minerals Company. He spent three years in private law practice in Denver, Colorado from 1986 to 1989, and from 1981 through 1986 he held various positions within the law department of Mobil Oil Corporation. He has been a member of the board of directors since 2005, and Chairman in 2008, of the FutureGen Industrial Alliance, Inc., a not-for-profit entity whose global members are working with the United States Department of Energy to build and operate a commercial scale carbon dioxide sequestration project. He currently also serves as the Treasurer and Secretary of FutureGen. From 2007 through 2010, he served as an appointee from the United States to the Coal Industry Advisory Board, an international advisory panel to the International Energy Administration with respect to matters regarding the production, use and demand for coal on a global basis. The board selected Mr. Walker to serve as a director because of his


115


Table of Contents

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
 
Armstrong Energy’s board currently consists of seven directors. The board has established the following committees, which manage us as well as Armstrong Energy: an audit committee, a compensation committee, a nominating and governance committee and a conflicts committee. The composition and responsibilities of each committee are described below. Members serve on these committees until their resignation or until otherwise determined by the board.
 
The majority of Armstrong Energy’s board members are independent. The board has determined that each of Messrs. Beard, Crain, Ford, and Walker is an independent director pursuant to the requirements of Nasdaq, and each of the members of the audit committee satisfies the additional conditions for independence for audit committee members required by Nasdaq.
 
Audit Committee
 
Messrs. Crain, Ford and Walker, each an independent director, serve on the audit committee. Mr. Ford is the chair of the audit committee. The committee assists 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 internal audit function and independent auditors, and (iv) our compliance with legal and regulatory requirements. The board has determined that Mr. Ford qualifies as an “audit committee financial expert,” as that term is defined in Item 407(d)(5) of Regulation S-K, as promulgated by the SEC.
 
Compensation Committee
 
Messrs. Beard, Ford and Walker, each an independent director, serve on the compensation committee. Mr. Beard is the chair of the compensation committee. The committee is responsible for discharging the board’s responsibility relating to compensation of Armstrong Energy’s executive officers and directors, evaluating the performance of its executive officers in light of Armstrong Energy’s goals and objectives, and recommending to the board for approval Armstrong Energy’s compensation plans, policies, and programs. Each member of the committee is independent, a “non-employee director” for purposes of Rule 16b-3 under the Exchange Act, and an “outside director” for purposes of Section 162(m) of the Code.
 
Nominating and Governance Committee
 
Messrs. Beard, Crain and Ford, each an independent director, serve on the nominating and governance committee. Mr. Crain is the chair of this committee. The committee is responsible for (i) assisting the board by indentifying individuals qualified to become board members, and recommending to the board nominees for election as director, (ii) leading the board in its annual performance review, (iii) recommending to the board members and chairpersons for each committee, (iv) monitoring the attendance, preparation and participation of individual directors and conducting a performance evaluation of each director prior to the time he or she is considered for re-nomination to the board of directors, (v) monitoring and evaluating corporate governance issues and trends, and (vi) discharging the board’s 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 the 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


116


Table of Contents

on actions to be taken by Armstrong Energy upon the board’s request, and (iv) carrying out any other duties delegated to the conflicts committee by the board of directors.
 
Compensation Committee Interlocks and Insider Participation
 
Although the board did not have a compensation committee during the entire current or previous fiscal year, none of the individuals who currently serve on the compensation committee has served Armstrong Energy or any of its subsidiaries as an officer or employee. In addition, none of Armstrong Energy’s 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 Energy’s 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 Energy’s 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
 
Historically, Armstrong Energy’s 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 and Governance 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 Energy’s compensation program for the fiscal year ended December 31, 2010 for its named executive officers, who are listed as follows:
 
  •  J. Hord Armstrong, III, Chairman and Chief Executive Officer;
 
  •  Martin D. Wilson, President;
 
  •  Kenneth E. Allen, Executive Vice President of Operations;
 
  •  David R. Cobb, P.E., Executive Vice President of Business Development; and
 
  •  J. Richard Gist, Senior Vice President, Finance and Administration and Chief Financial Officer.
 
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 Energy’s 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


117


Table of Contents

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 Energy’s 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:
 
  •  To retain talented individuals to contribute to Armstrong Energy’s sustained progress, growth and profitability; and
 
  •  To reflect the unique qualifications, skills, experiences and responsibilities of each individual.
 
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 Energy’s new compensation philosophy and objectives, administrate Armstrong Energy’s executive and director compensation programs and plans, and review and approve the compensation of Armstrong Energy’s named executive officers. The committee is currently in the process of evaluating Armstrong Energy’s historical compensation practices and customizing a new management compensation program for Armstrong Energy’s 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 committee’s responsibilities are specified in its charter. The compensation committee’s functions and authority include, among other things:
 
  •  Establishment and annual review of corporate goals and objectives relevant to the compensation of the executive officers, including the chief executive officer;
 
  •  Evaluation of the executive officers’ performance;
 
  •  Determination and approval of executive officer compensation;
 
  •  Administration of equity compensation plans, annual bonus, and long-term incentive cash-based compensation plans;
 
  •  Review and approval of employment agreements and severance arrangements of all executive officers; and
 
  •  Management of risk relating to incentive compensation.
 
Elements of Compensation
 
Historically, Armstrong Energy’s executive officers have received annual salaries as their compensation for services. In addition, Armstrong Energy’s board may grant discretionary cash bonuses and equity to its executive officers. In connection with Mr. Gist’s appointment as an executive officer, effective January 1, 2010, Armstrong Energy granted Mr. Gist 18,500 shares of common stock of Armstrong Energy, which vested on September 30, 2011. The aggregate grant date value of Mr. Gist’s award was $120,000. In addition, on June 1, 2011, Armstrong Energy granted to each of Messrs. Armstrong, Wilson, Allen and Cobb 18,500 shares of common stock of Armstrong Energy, which vest on April 1, 2013. The aggregate grant date fair value of each award was $258,000.
 
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.


118


Table of Contents

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 Energy’s 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 Energy’s 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 Energy’s named executive officers are eligible for the following benefits on the same basis as other eligible employees:
 
  •  Health insurance;
 
  •  Vacation, personal holidays and sick time;
 
  •  Life insurance and supplemental life insurance;
 
  •  Short-term and long-term disability; and
 
  •  A 401(k) plan with matching contributions.
 
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 officer’s behalf. Also, Armstrong Energy provides Mr. Wilson with an allowance for club membership dues.
 
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.
 
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 Energy’s 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.


119


Table of Contents

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. Gist’s 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 Energy’s achievement of profitability targets and Mr. Gist’s satisfactory achievement of goals and objectives as determined by Armstrong Energy’s President. For 2009, Mr. Gist was to earn a bonus equal to a minimum of 22.5% of base salary, less $15,000. In addition, Mr. Gist received a signing bonus of $15,000 in 2009.
 
In addition, pursuant to the terms of the 2009 Gist Agreement, Mr. Gist was granted 18,500 restricted shares of Armstrong Energy. 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 Energy’s shareholders. Awards will be made at the discretion of the board of directors and Armstrong Energy’s President.
 
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. 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 Energy’s President or board of directors. As of December 16, 2011, Armstrong Energy has not established any performance criteria pursuant to the 2011 Gist Agreement. Armstrong Energy’s board may grant Mr. Gist a discretionary cash bonus for 2011, however.
 
The 2011 Gist Agreement provides that Mr. Gist shall be eligible to participate in such benefits as may be authorized and adopted from time to time by the board of directors for Armstrong Energy’s 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. Gist’s termination of employment with Armstrong Energy.


120


Table of Contents

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. 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 executive’s then annual base salary. The executives’ base salary and bonus will be reviewed from time to time and may be increased. As of December 16, 2011, Armstrong Energy has not established any performance criteria pursuant to the Armstrong and Wilson Agreements. Armstrong Energy’s board may grant Mr. Armstrong and/or Mr. Wilson a discretionary cash bonus for 2011, however.
 
The Armstrong and Wilson Agreements provide that Messrs. Armstrong and Wilson shall be entitled to participate in any of Armstrong Energy’s 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 “— 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 executive’s 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 Energy’s 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 Energy’s 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.


121


Table of Contents

2010 Summary Compensation Table
 
The following table sets forth all compensation paid to Armstrong Energy’s named executive officers for the years ending December 31, 2010, 2009, and 2008.
 
                                                 
                            All Other
       
Name and Principal Position
  Year     Salary     Bonus     Stock Awards     Compensation     Total  
 
J. Hord Armstrong, III,
    2010     $ 250,000     $ 187,500     $     $ 21,456 (1)   $ 458,956  
Chairman and Chief
    2009       124,000       42,000             5,780       171,780  
Executive Officer
    2008       60,000                   3,076       63,076  
Martin D. Wilson,
    2010     $ 250,000     $ 187,500     $     $ 9,868     $ 447,368  
President
    2009       206,000                         206,000  
      2008       200,000                   1,710       201,710  
Kenneth E. Allen(2),
    2010     $ 260,000     $ 130,000     $     $ 606,219 (3)   $ 996,219  
Executive Vice President
    2009       247,000       42,000             12,560       301,560  
of Operations
    2008       243,000                   15,641       258,641  
David R. Cobb, P.E.(4),
    2010     $ 226,000     $ 113,000     $     $ 300,567 (5)   $ 639,567  
Executive Vice President of
    2009       210,000       42,000             244,428       496,428  
Business Development
    2008       182,000                   81,402       263,402  
J. Richard Gist(6),
    2010     $ 195,000     $ 88,000     $ 120,000     $ 4,129     $ 407,129  
Senior Vice President,
    2009       48,250       43,000                   91,250  
Finance and Administration
    2008                                
and Chief Financial Officer
                                               
 
 
(1) Includes Armstrong Energy’s matching contributions paid to Armstrong Energy’s 401(k) plan on behalf of Mr. Armstrong ($14,600).
 
(2) Mr. Allen was appointed Executive Vice President of Operations effective October 1, 2011. Prior to this time, Mr. Allen was Armstrong Energy’s Vice President of Operations.
 
(3) Includes overriding royalties paid to Mr. Allen ($569,000) (see “— Overriding Royalty Agreements” for a description of Mr. Allen’s agreement with Armstrong Energy regarding the payment of overriding royalties) and Armstrong Energy’s matching contributions paid to Armstrong Energy’s 401(k) plan on behalf of Mr. Allen ($15,100).
 
(4) Mr. Cobb was appointed Executive Vice President of Business Development effective October 1, 2011. Prior to this time, Mr. Cobb was Armstrong Energy’s Vice President of Business Development.
 
(5) Includes overriding royalties paid to Mr. Cobb ($265,000) (see “— Overriding Royalty Agreements” for a description of Mr. Cobb’s agreement with Armstrong Energy regarding the payment of overriding royalties) and Armstrong Energy’s matching contributions paid to Armstrong Energy’s 401(k) plan on behalf of Mr. Cobb ($13,400).
 
(6) Mr. Gist became Vice President and Controller on October 7, 2009, and Senior Vice President, Finance and Administration and Chief Financial Officer effective October 1, 2011.
 
Payments upon Termination or a Change in Control
 
Each of 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 executive’s 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


122


Table of Contents

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 executive’s 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 executive’s 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 executive’s consent, in the executive’s duties. In the event of a resignation for good reason, the executive shall be entitled to receive (i) the executive’s 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 executive’s employment, other than for cause, within 12 months of a change in control, the executive shall be entitled to receive health insurance premiums for 12 months. In addition, Armstrong Energy will pay, promptly following such termination, a lump sum payment equal to one times the executive’s 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 Energy’s 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 Energy’s 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 Energy’s 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. Gist’s 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. Gist’s 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. Gist’s 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


123


Table of Contents

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. Gist’s 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 executive’s 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. Gist’s consent, in Mr. Gist’s 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. Gist’s 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 Mr. Gist’s annual base salary at the time of his termination, plus one year’s bonus in an amount equal to 50% of Mr. Gist’s 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 Energy’s 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 Energy’s 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 Energy’s 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. Armstrong’s and Mr. Wilson’s 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 executive’s 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 Energy’s 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


124


Table of Contents

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 executive’s 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 executive’s 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 Energy’s 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 Energy’s 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 executive’s 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 executive’s 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 Energy’s operations); (ii) the annual base salary is materially reduced (except if such reduction occurs prior to a change in control and is part of an across-the-board reduction applicable to all senior level executives); (iii) The executive is required to change his regular work location to a location that is more than 75 miles from his regular work location prior to such change; (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 executive’s 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 executive’s 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


125


Table of Contents

(b) during the portion, if any, of the 24-month period commencing on the date of The executive’s separation from service that The executive is eligible to elect and elects to continue coverage for himself and his eligible dependents and Armstrong Energy’s 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 Energy’s securities and such other entity) as a result of which the holders of all of Armstrong Energy’s 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 Energy’s 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 Energy’s 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 Energy’s shareholders) of each director who was not a member of the board on such date was approved by a vote of at least two-thirds of the board of directors in office prior to the time of such first election, appointment or nomination.
 
Pursuant to the terms of the Armstrong and Wilson 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 executive’s “base amount” (as defined in Section 280G of the Code) and so that no portion of such payments received by the executive shall be subject to the excise tax imposed by Section 4999 of the Code.
 
The following table illustrates the payments and benefits due to each of Messrs. Allen, Cobb and Gist assuming that the termination or change in control took place on the last business day of Armstrong Energy’s last completed fiscal year. There would have been no payments or benefits due to Messrs. Armstrong or Wilson in such an event, as Messrs. Armstrong and Wilson were not parties to an employment agreement as of December 31, 2010.
 
                                         
                    Termination
                Termination
  in Connection
    Termination
  Termination
  Termination for
  Without
  with a Change
Name
  for Cause   Without Cause   Good Reason   Good Reason   in Control
 
Kenneth E. Allen
  $ 19,691     $ 292,315     $ 292,315     $ 19,691     $ 292,315  
David R. Cobb, P.E
  $ 19,691     $ 270,315     $ 270,315     $ 19,691     $ 270,315  
J. Richard Gist
        $ 302,154     $ 302,154           $ 302,154  


126


Table of Contents

2011 Long-Term Incentive Plan
 
Armstrong Energy’s 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 Energy’s 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 Energy’s 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 grant. The exercise price of incentive stock options granted to holders of at least 10% of Armstrong Energy’s 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 committee’s 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


127


Table of Contents

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 recipient’s performance, comparisons with compensation received by similarly-situated recipients within the industry, Armstrong Energy’s 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.


128


Table of Contents

 
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
The following table shows the amount of our common units beneficially owned as of January 31, 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. 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. Percentage computations are based on 1,342,000 common units outstanding as of January 31, 2012. 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.
 
                                 
          Common Units Beneficially
 
    Common Units Beneficially Owned Prior to this
    Owned After this
 
    Offering(1)     Offering(2)  
Name
  Number     Percent     Number     Percent  
 
J. Hord Armstrong, III
                       
Martin D. Wilson
                       
Kenneth E. Allen
                       
David R. Cobb, P.E. 
                       
J. Richard Gist
                       
Anson M. Beard, Jr. 
                       
James C. Crain
                       
Richard F. Ford
                       
Bryan H. Lawrence(3)
                       
Greg A. Walker
                       
All Directors and Executive Officers as a group (11 persons)
                       
Yorktown VII Associates LLC(3)(4)
    245,000       18.26 %     245,000       %
Yorktown VIII Associates LLC(3)(5)
    1,097,000       81.74 %     1,097,000       %
 
 
Less than 1%.
 
(1) Amounts do not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering.
 
(2) Assumes that the underwriters do not exercise their option to purchase additional common units.
 
(3) The address of this beneficial owner is 410 Park Avenue, 19th Floor, New York, New York 10022.
 
(4) These shares are held of record by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP is the sole general partner of Yorktown Energy Partners VII, L.P. Yorktown VII Associates LLC is the sole general partner of Yorktown VII Company LP. As a result, Yorktown VII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the 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.
 
(5) These shares are held of record by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP is the sole general partner of Yorktown Energy Partners VIII, L.P. Yorktown VIII Associates LLC is the sole general partner of Yorktown VIII Company LP. As a result, Yorktown VIII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the 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.


129


Table of Contents

 
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 Energy’s employees and services and for certain shared fixed costs, including, but not limited to, office lease, telephone and office equipment leases, we will pay Armstrong Energy (i) a monthly fee equal to $60,000 per month and (ii) an aggregate annual fee equal to $279,996 per year, until December 31, 2011. The monthly fee is subject to adjustment annually in accordance with the terms of the Administrative Services Agreement. 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 Energy’s 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 September 30, 2011 was $134.6 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 39.45% undivided interest through the exercise of options described above.
 
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 Energy’s 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


130


Table of Contents

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 Energy’s executive officers, and Rebecca K. Cobb, Mr. Cobb’s spouse, certain property to be used by Armstrong Energy as its office space in Madisonville, Kentucky, equipment, furniture, supplies and the use of Mr. Cobb’s 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.
 
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 Energy’s Chairman and Chief Executive Officer, pursuant to which we granted Mr. Armstrong 22,500 restricted limited partnership units. Also effective October 1, 2011, we entered into a Restricted Unit Award Agreement with Martin D. Wilson, Armstrong Energy’s President and member of its board of directors, pursuant to which we granted Mr. Wilson 20,000 restricted limited partnership units. The aforementioned


131


Table of Contents

awards do not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering. 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 grantee’s provision of services to Armstrong Resource Partners for reason other than cause, as defined in the Restricted Unit Award Agreements.
 
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 0.4% 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 $      million, assuming an offering price of $      per unit, the midpoint of the range set forth on the cover of this prospectus, related to the Concurrent AE Offering, of the net proceeds from the Concurrent AE Offering to repay a portion of Armstrong Energy’s 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 Energy’s 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 Energy’s leverage ratio and the applicable interest option elected. The interest rate as of September 30, 2011 was 5.75%.           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 conflicts 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 conflicts committee will take into account any factors it deems relevant.


132


Table of Contents

 
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 Energy’s 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 Energy’s 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:
 
  •  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;
 
  •  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  •  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.
 
In resolving a conflict, Armstrong Energy, including its conflicts committee, may, unless the resolution is specifically provided for in the Partnership Agreement, consider:
 
  •  the relative interests of any party to such conflict and the benefits and burdens relating to such interest;
 
  •  any customary or accepted industry practices or historical dealings with a particular person or entity;
 
  •  generally accepted accounting practices or principles; and
 
  •  such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
 
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:
 
  •  amount and timing of asset purchases and sales;
 
  •  cash expenditures;
 
  •  borrowings;
 
  •  the issuance of additional common units; and
 
  •  the creation, reduction or increase of reserves in any quarter.


133


Table of Contents

 
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 Energy’s 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 arm’s-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 arm’s-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


134


Table of Contents

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 partner’s state-law fiduciary duty standards. We believe this is appropriate and necessary because the board of directors of our general partner’s 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 partner’s 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 partner’s 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


135


Table of Contents

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:
 
     
State law fiduciary duty standards   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.
Partnership Agreement modified standards   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.
    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 partner’s parent corporation must be:
   
•   on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
   
•   “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).
    If our general partner does not seek approval from Armstrong Energy’s conflicts committee and Armstrong Energy’s 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.
 
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.
 
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


136


Table of Contents

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.”


137


Table of Contents

 
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.”
 
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:
 
  •  becomes the record holder of the common units and is entitled to be admitted into our Partnership as a substituted limited partner;
 
  •  automatically requests admission as a substituted limited partner in our Partnership;
 
  •  executes and agrees to be bound by the terms and conditions of our Partnership Agreement;
 
  •  represents that the transferee has the capacity, power and authority to become bound by our Partnership Agreement;
 
  •  gives the consents, waivers and approvals contained in our Partnership Agreement; and
 
  •  certifies that the transferee is an eligible citizen.
 
As used in this prospectus, an eligible citizen means a person or entity qualified to hold an interest in mineral leases on federal lands. As of the date hereof, an eligible citizen must be: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of U.S. citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.
 
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 automatically 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.
 
A transferee’s broker, agent or nominee may, but is not obligated to, complete, execute and deliver a transfer application. We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
 
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:
 
  •  the right to assign the common unit to a purchaser or other transferee; and
 
  •  the right to transfer the right to seek admission as a substituted limited partner in our Partnership for the transferred common units.


138


Table of Contents

 
Thus, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:
 
  •  will not receive cash distributions;
 
  •  will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes; and
 
  •  may not receive some federal income tax information or reports furnished to record holders of common units;
 
  •  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.
 
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 February 9, 2012.
 
  •  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.
 
  •  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.
 
  •  Dividends.  Holders of the Series A convertible preferred units are not entitled to the payment of any dividends by the Partnership.
 
  •  Conversion.
 
  •  Automatic 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 of the quotient obtained by dividing (i) $100 times the number of units to be converted, by (ii) the lower of (a) the conversion price then in effect (which shall initially be $100 per unit, but may be adjusted as provided in the designation), or (b) 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 (the “IPO Price”).
 
  •  Conversion at Option of Holder.  At any time and from time to time after the date any Series A convertible preferred units are issued and outstanding, any holder of Series A convertible preferred units may convert all or any portion of the Series A convertible preferred units held into a number of common units equal to the quotient obtained by dividing (i) $100 times the number of units to be converted, by (ii) the conversion price then in effect (which shall initially be $100 per unit, but may be adjusted as provided in the designation) .


139


Table of Contents

 
  •  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 holder’s 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 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:
 
  •  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;
 
  •  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
 
  •  Any increase in the number of authorized shares of capital stock of the Company, except as specifically required in the certificate of designations.


140


Table of Contents

 
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 Energy’s 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 Energy’s 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 of approximately $7.0 million in the nine months ended September 30, 2011. The Senior Secured Term Loan is a five-year term loan that requires principal payments in the amount of $5.0 million each on the first day of each quarter commencing on January 1, 2012 through January 1, 2016, with a final balloon payment due upon maturity on February 9, 2016. Interest payments are also payable quarterly in arrears on the first day of each quarter. The interest rate fluctuates based on Armstrong Energy’s leverage ratio and the applicable interest option elected. The interest rate as of September 30, 2011 was 5.75%. The Senior Secured Revolving Credit Facility provides for quarterly interest payments in arrears that fluctuate on the same terms as Armstrong Energy’s term loan. The Senior Secured Revolving Credit Facility also provides for a commitment fee based on the unused portion of the facility at certain times. As of September 30, 2011, Armstrong Energy had $34.6 million outstanding, with $15.4 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 Energy’s 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 0.37433% as of September 30, 2011. This agreement has quarterly settlement dates and matures on February 9, 2016.
 
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 Energy’s reorganization. The amendment also made certain changes to Armstrong Energy’s financial covenants, including its maximum leverage ratio. In addition, Armstrong Energy’s interest rate increased to 5.75%, which can be reduced in future periods to the extent Armstrong Energy’s 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 Energy’s 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.


141


Table of Contents

 
THE PARTNERSHIP AGREEMENT
 
The following is a summary of the material provisions of our Partnership Agreement.
 
We summarize the following provisions of our Partnership Agreement elsewhere in this prospectus:
 
  •  with regard to distributions of available cash, please see “Cash Distribution Policy”;
 
  •  with regard to the transfer of common units, please see “Description of the Common Units — Transfer of Common Units”; and
 
  •  with regard to allocations of taxable income and taxable loss, please see “Material Tax Consequences.”
 
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
 
Our purpose 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 or Armstrong Energy 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 and Armstrong Energy do not have the authority to cause us to engage, directly or indirectly, in any business activity that they reasonably determine would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
 
Although our general partner and Armstrong Energy have 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 and Armstrong Energy have no current plans to do so.
 
Power of Attorney
 
Each limited partner and each person who acquires a common unit from a unitholder 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
 
Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”
 
For a discussion of our general partner’s right to contribute capital to maintain its 0.4% general partner interest if we issue additional units, please read “— Issuance of Additional Interests.”


142


Table of Contents

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 common units 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:
 
  •  to approve some amendments to our Partnership Agreement; or
 
  •  to take other action under our Partnership Agreement;
 
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 as a group to remove or replace our general partner, to approve some 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 unitholder 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 Partnership’s outstanding units.


143


Table of Contents

The following matters require the unitholder vote specified below:
 
Issuance of additional common units — No approval right.
 
Amendment of the Partnership Agreement — Certain amendments may be made by the general partner without the approval of the unitholders. 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 Partnership’s 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 unitholders 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, of each of Armstrong Energy and its affiliates and those of the general partner. Please read “— Transfer of General Partner Interest.”
 
Transfer of ownership interests in the general partner — No approval right.
 
If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval 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 common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional Partnership common units or other equity securities may dilute the value of the interests of the then existing holders of common units in our net assets.
 
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 common units are not entitled.


144


Table of Contents

Upon issuance of additional Partnership securities, our general partner may make additional capital contributions to the extent necessary to maintain its 0.4% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities of the Partnership whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units that existed immediately prior to each issuance. The holders of common units do not have preemptive rights to acquire additional common units or other Partnership securities.
 
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 common 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:
 
  •  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;
 
  •  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;
 
  •  change the term of the Partnership;
 
  •  provide that we are not dissolved upon an election to dissolve our Partnership by our general partner that is approved by a common unit majority; or
 
  •  give any person the right to dissolve our Partnership other than our general partner’s right to dissolve our Partnership with the approval of a unit majority.
 
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:
 
  •  a change in our name, the location of our principal place of our business, our registered agent or our registered office;
 
  •  the admission, substitution, withdrawal or removal of partners in accordance with our Partnership Agreement;
 
  •  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, the operating company nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
 
  •  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;


145


Table of Contents

 
  •  an amendment that is necessary, in the opinion of our 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, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;
 
  •  subject to the limitations on the issuance of additional Partnership securities described above, an amendment that in the discretion of our general partner is necessary or advisable for the authorization of additional Partnership securities or rights to acquire Partnership securities;
 
  •  any amendment expressly permitted in our Partnership Agreement to be made by our general partner acting alone;
 
  •  an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our Partnership Agreement;
 
  •  any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our Partnership Agreement;
 
  •  a merger, conversion or conveyance effected in accordance with the Partnership Agreement; and
 
  •  any other amendments substantially similar to any of the matters described in the clauses above.
 
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:
 
  •  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;
 
  •  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;
 
  •  are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any 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;
 
  •  are necessary or advisable for any action taken by our general partner relating to splits or combinations of common units under the provisions of our Partnership Agreement; or
 
  •  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.
 
Opinion of Counsel and Unitholder 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 common units constitute not less than the voting requirement sought to be reduced.


146


Table of Contents

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 our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders 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:
 
  •  the election of our general partner to dissolve us, if approved by the holders of a unit majority;
 
  •  the sale, exchange or other disposition of all or substantially all of the assets and properties of our Partnership and the subsidiaries;
 
  •  the entry of a decree of judicial dissolution of our Partnership; or
 
  •  the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our Partnership Agreement or withdrawal or removal following approval and admission of a successor.
 
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:
 
  •  the action would not result in the loss of limited liability of any limited partner; and
 
  •  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.
 
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 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 unitholder approval upon 90 days’ notice to the limited partners if at the time notice is given at least 50% of the outstanding units are held or controlled by one


147


Table of Contents

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 unitholders. See “— Transfer of General Partner Interest.”
 
Upon the 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 majority of the 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 dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of the outstanding units agree in writing to continue our business and to appoint a successor general partner. See “— Termination and Dissolution.”
 
Yorktown unilaterally may remove our general partner in some circumstances. Unitholders other than Yorktown 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. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units.
 
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 under circumstances where cause does not exist, the departing partner shall have the option, exercisable prior to the effective date of the departure of such departing partner, to require its duly elected successor to purchase its general partner interest(s) in us and any of our subsidiaries for an amount in cash equal to the fair market value of such interest(s).
 
In the event of removal of the general partner under circumstances where cause exists or withdrawal of the general partner where that withdrawal violates the Partnership Agreement, a successor general partner will have the option to purchase the general partner interest(s), as described above, of the 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 our benefit.
 
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 each of Armstrong Energy and its affiliates and those of the general partner.
 
Transfer of Ownership Interests in the General Partner
 
At any time, the partners of our general partner may sell or transfer all or part of their Partnership interests in our general partner without the approval of the unitholders.
 
Change of Management Provisions
 
Our Partnership Agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Elk Creek GP as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more


148


Table of Contents

of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the managers of our general partner.
 
Our Partnership Agreement also provides that if our general partner is removed under circumstances where cause does not exist, the departing partner shall have the option, exercisable prior to the effective date of the departure of such departing partner, to require its duly elected successor to purchase its general partner interest(s) in us and any of our subsidiaries for an amount in cash equal to the fair market value of such interest(s).
 
Limited Call Right
 
If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons 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:
 
  •  the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
 
  •  the current market price as of the date three days before the date the notice is mailed.
 
As a result of our general partner’s 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 unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units 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, unitholders or assignees who are record holders of common units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units 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 common units will not be voted, except that, in the case of units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the votes on those units in the same ratios as the votes of limited partners on other common units are cast.
 
Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of common units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders 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 unitholders requires approval by holders of a greater percentage of the common units, in which case the quorum shall be the greater percentage.
 
Each record holder of a common unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. See “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates or a person or group who acquires the common units with the prior approval of the managers, acquires, in the aggregate, beneficial


149


Table of Contents

ownership of 20% or more of any class of units then outstanding, the person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units 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 common units under our Partnership Agreement will be delivered to the record holder by us or by the transfer agent.
 
Status as Limited Partner or Assignee
 
Except as described above under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.
 
An assignee of a common unit, 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 for the right to share in allocations and distributions from us, including liquidating distributions. The general partner will vote and exercise other powers attributable to common units 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 common units, and will not receive cash distributions, federal income tax allocations or reports furnished to holders of common units. 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 that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem, upon 30 days’ advance notice, the common units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a 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 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 common units and may not receive distributions in kind upon our liquidation.
 
Indemnification
 
Under our Partnership Agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
 
  •  our general partner;
 
  •  Yorktown;
 
  •  any departing general partner;
 
  •  any person who is or was an affiliate of a general partner or any departing general partner;
 
  •  any person who is or was a member, partner, officer, director, employee, agent or trustee of any of our subsidiaries, a general partner or any departing general partner or any affiliate of any of our subsidiaries, a general partner or any departing general partner; or


150


Table of Contents

 
  •  any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner as an officer, director, employee, member, partner, agent or trustee of another person.
 
Any indemnification under these provisions will only be out of our 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 us to effectuate indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our 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 our behalf and all other necessary appropriate expenses allocable to us or otherwise reasonably incurred by our general partner in connection with operating our 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 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 of our 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. We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, 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 common unit 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:
 
  •  true and full information regarding the status of the business and financial condition of the Partnership;
 
  •  promptly after they becoming available, copies of the Partnership’s federal, state and local income tax returns for each year;
 
  •  a current list of the name and last known address of each partner;
 
  •  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;
 
  •  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
 
  •  any other information regarding our affairs as is just and reasonable.
 
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 or which we are required by law or by agreements with third parties to keep confidential.


151


Table of Contents

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, including Yorktown, 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.


152


Table of Contents

 
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           common 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           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:
 
  •  units of restricted securities will be available for sale at various times after the date of this prospectus pursuant to Rule 144; and
 
  •  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.
 
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:
 
  •  1% of the number of common units then outstanding, which will equal approximately units immediately after consummation of this offering; or
 
  •  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.
 
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 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.


153


Table of Contents

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, Armstrong Energy’s officers and directors and holders of all of our common units have agreed with the underwriters not to offer, sell, 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 (subject to extension) after the date of this prospectus, except with the prior written consent of          , on behalf of the underwriters. See “Underwriting.” may release any of the securities subject to these lock-up agreements at any time without notice.
 
Immediately following the consummation of this offering, unitholders subject to lock-up agreements will hold           common units, representing about     % of our outstanding common units after giving effect to this offering.


154


Table of Contents

 
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 counsel’s 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


155


Table of Contents

taxable to the partnership or the partner unless the amount of cash distributed to the partner is in excess of the partner’s 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 partnership’s 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:
 
  •  Neither we nor any of our operating companies has elected or will elect to be treated as a corporation; and
 
  •  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.
 
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 unitholder’s tax basis in its common units, or taxable capital gain, after the unitholder’s tax basis in its common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s 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 LLP’s opinion that we will be classified as a partnership for United States federal income tax purposes.


156


Table of Contents

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:
 
  •  assignees who have executed and delivered transfer applications and are awaiting admission as limited partners; and
 
  •  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.
 
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 Teasdale’s 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 unitholder’s tax basis in its common units immediately before the distribution. Our cash distributions in excess of a unitholder’s 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 unitholder’s 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 unitholder’s “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 unitholder’s percentage interest in us because of our issuance of additional common units will decrease the unitholder’s share of our nonrecourse liabilities and thus will result in a corresponding


157


Table of Contents

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 unitholder’s 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 unitholder’s realization of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed relinquished in the exchange.
 
Basis of Common Units
 
A unitholder’s 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 unitholder’s 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 unitholder’s 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 unitholder’s 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 unitholder’s tax basis in the unitholder’s 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 unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the unitholder’s 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 taxpayer’s 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


158


Table of Contents

investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s 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 unitholder’s 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 taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
 
  •  interest on indebtedness properly allocable to property held for investment;
 
  •  our interest expense attributed to portfolio income; and
 
  •  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
 
The computation of a unitholder’s 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 unitholder’s 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


159


Table of Contents

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 partner’s “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 partner’s share of an item of income, gain, loss, or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including:
 
  •  the partner’s relative contributions to us;
 
  •  the interests of all the partners in profits and losses;
 
  •  the interest of all the partners in cash flow; and
 
  •  the rights of all the partners to distributions of capital upon liquidation.
 
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 partner’s 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:
 
  •  any of our income, gain, loss, or deduction with respect to those common units would not be reportable by the unitholder;
 
  •  any cash distributions received by the unitholder as to those common units would be fully taxable; and
 
  •  all of these distributions may be subject to tax as ordinary income.
 
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.”


160


Table of Contents

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 unitholder’s 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 unitholder’s net investment income or (2) the amount by which the unitholder’s 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 purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect the unitholder’s 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 unitholder’s 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 property’s 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)


161


Table of Contents

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 property’s 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 unitholder’s tax basis for its common units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the unitholder’s 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 transferee’s 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 transferee’s 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


162


Table of Contents

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


163


Table of Contents

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 unitholder’s 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 partner’s 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


164


Table of Contents

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:
 
  •  for sale to customers in the ordinary course of business (i.e., we are a “dealer” with respect to that property);
 
  •  for use in a trade or business within the meaning of Section 1231 of the Internal Revenue Code; or
 
  •  as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.
 
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 unitholder’s 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


165


Table of Contents

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 unitholder’s 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 unitholder’s 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 unitholder’s 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 unitholder’s 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 unitholder’s 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,


166


Table of Contents

(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 the last Congressional session, 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 unitholder’s amount realized and the unitholder’s tax basis for the common units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property received by it plus the unitholder’s share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s 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 unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than the unitholder’s 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 partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can


167


Table of Contents

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:
 
  •  a short sale;
 
  •  an offsetting notional principal contract; or
 
  •  a futures or forward contract with respect to the partnership interest or substantially identical property.
 
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 unitholder’s 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.


168


Table of Contents

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 unitholder’s interest until the certificate evidencing such unitholder’s interest is surrendered for registration of transfer and such certificate is accompanied by a transfer application duly executed by the transferee (or the transferee’s 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 property’s 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


169


Table of Contents

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 organization’s 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


170


Table of Contents

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 corporation’s “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 unitholder’s gain would be effectively connected with that unitholder’s 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 unitholder’s 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 year’s tax liability and possibly may result in an audit of its return. Any audit of a unitholder’s 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.


171


Table of Contents

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:
 
  •  the name, address, and taxpayer identification number of the beneficial owner and the nominee;
 
  •  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;
 
  •  the amount and description of common units held, acquired, or transferred for the beneficial owner; and
 
  •  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.
 
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:
 
  •  for which there is, or was, “substantial authority;” or
 
  •  as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
 
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


172


Table of Contents

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 taxpayer’s 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:
 
  •  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “Accuracy-Related Penalties;”
 
  •  for those persons otherwise entitled to deduct interest on United States federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and
 
  •  in the case of a listed transaction, an extended statute of limitations.
 
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


173


Table of Contents

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 unitholder’s 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.


174


Table of Contents

 
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:
 
  •  whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;
 
  •  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;
 
  •  whether the investment is permitted under the terms of the applicable documents governing the ERISA Plan;
 
  •  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
 
  •  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.”
 
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


175


Table of Contents

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 entity’s assets would not be considered to be “plan assets” if, among other things:
 
  (a)  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;
 
  (b)  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
 
  (c)  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.
 
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.


176


Table of Contents

 
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:
 
         
    Number of
 
Name of Underwriter
  Common Units  
 
Raymond James & Associates, Inc. 
       
FBR Capital Markets & Co. 
       
Total
       
 
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:
 
  •  the representations and warranties made by us to the underwriters are true;
 
  •  there is no material adverse change in the financial market; and
 
  •  we deliver customary closing documents and legal opinions to the underwriters.
 
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           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.
 
                         
          Total Without
       
          Over-
    Total With
 
    Per Common
    Allotment
    Over-Allotment
 
    Unit     Exercise     Exercise  
 
Price to the public
                       
Underwriting discount and commissions
                       
Proceeds to us (before offering expenses)
                       
 
The expenses of this offering that are payable by us are estimated to be $     .


177


Table of Contents

Indemnification
 
We have agreed to indemnify the underwriters against certain liabilities that may arise in connection with this offering, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for those liabilities.
 
Lock-Up Agreements
 
Subject to specified exceptions, we, our general partner’s managers, executive officers, unitholders and Armstrong Energy, Inc. have agreed with the underwriters, for a period of     days after the date of this prospectus, without the prior written consent of          :
 
  •  not to offer for sale, sell, pledge or otherwise dispose of the common units;
 
  •  not to grant or sell any option or contract to purchase any of the common units;
 
  •  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;
 
  •  not to enter into any swap or other agreement that transfers any of the economic consequences of ownership of or otherwise transfer or dispose of, directly or indirectly, any of the common units; and
 
  •  not to enter into any hedging, collar or other transaction or arrangement that is designed or reasonably expected to lead to or result in a transfer, in whole or in part, of any of the economic consequences of ownership of the common units, whether or not such transfer would be for any consideration.
 
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.
 
          may, in its discretion and at any time, release all or any portion of the securities subject to these agreements.          does not have any present intent or any understanding to release all or any portion of the securities subject to these agreements.
 
The          -day period described in the preceding paragraphs will be extended if:
 
  •  during the last 17 days of the          -day period, we issue a release concerning distributable cash or announce material news or a material event relating to us occurs; or
 
  •  prior to the expiration of the          -day period, we announce that we will release earnings results during the 16-day period beginning on the last day of the -day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the release concerning distributable cash, the announcement of material news or the occurrence of the material event.
 
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:
 
  •  short sales;
 
  •  syndicate covering transactions;
 
  •  imposition of penalty bids; and
 
  •  purchases to cover positions created by short sales.
 
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


178


Table of Contents

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.
 
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 expect to apply 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.
 
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.


179


Table of Contents

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 underwriting discounts and commissions 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 (EEA) which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of any common units which are the subject of the offering contemplated by this prospectus may not be made in that Relevant Member State, except that an offer to the public in that Relevant Member State of any common units may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:
 
  (a)  to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;
 
  (b)  to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;
 
  (c)  it is a “qualified investor” within the meaning of the law in that Relevant Member State implementing Article 2(1)(e) of the Prospectus Directive; and
 
  (d)  in the case of any common units acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (i) the common units acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than “qualified investors” (as defined in the Prospectus Directive), or in circumstances in which the prior consent of the representative has been given to the offer or resale; or (ii) where common units have been acquired by it on behalf of persons in any Relevant Member State other than qualified investors, the offer of those common units to it is not treated under the Prospectus Directive as having been made to such persons.
 
In addition, in the United Kingdom, this document is being distributed only to, and is directed only at, and any offer subsequently made may only be directed at persons who are “qualified investors” (as defined in the Prospectus Directive) (i) who have professional experience in matters relating to investments falling within Article 19 (5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Order”) and/or (ii) who are high net worth companies (or persons to whom it may otherwise be lawfully communicated) falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This document must not be acted on or relied on in the United Kingdom by persons


180


Table of Contents

who are not relevant persons. In the United Kingdom, any investment or investment activity to which this document relates is only available to, and will be engaged in with, relevant persons.
 
Notice to Prospective Investors in Australia
 
This document has not been lodged with the Australian Securities & Investments Commission and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:
 
  (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 accountant’s 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 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.


181


Table of Contents

 
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, 2010 were prepared by Weir International, Inc., an independent mining and geological consultant.
 
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS
 
The consolidated financial statements of Armstrong Resource Partners, L.P. and subsidiaries as of December 31, 2010 and 2009 and for each of the years in the two-year period ended December 31, 2010 appearing in this prospectus have been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report appearing in this prospectus, and are included in reliance upon such report given on their authority as experts in accounting and auditing.
 
The consolidated financial statements of Armstrong Resource Partners, L.P. and subsidiaries as of December 31, 2008 and for the year ended December 31, 2008 appearing in this prospectus have been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report appearing in this prospectus.
 
CHANGE IN AUDITOR
 
Prior to engaging Ernst & Young as our independent registered public accounting firm, KPMG LLP was engaged as our 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 LLP’s 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 KPMG’s 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 LLP’s interaction with our former controller, KPMG LLP believed that we lacked an adequately trained finance and accounting controller with appropriate GAAP expertise. In KPMG LLP’s 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.


182


Table of Contents

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 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 LLP’s completion of the 2008 audit, our board of managers dismissed Grant Thornton LLP. Grant Thornton LLP’s 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 LLP’s and KPMG LLP’s 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 Partnership’s filings with the SEC are available to the public on the SEC’s 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 SEC’s 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 periodic reports, proxy and information statements and other information with the SEC. Such annual, quarterly and current reports; proxy and information statements; and other information can be inspected and copied at the locations set forth above. We will report our financial statements on a year ended December 31. We intend to furnish our 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.


183


 

 
INDEX TO FINANCIAL STATEMENTS
 
         
    F-2  
    F-3  
    F-4  
    F-5  
    F-6  
    F-7  
    F-8  
    F-14  
    F-15  
    F-16  
    F-17  
    F-18  


F-1


Table of Contents

 
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, 2010 and 2009, and the related consolidated statements of operations, partners’ capital, and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s 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 Partnership’s 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 Partnership’s 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, 2010 and 2009, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
 
/s/  ERNST & YOUNG LLP
 
St. Louis, Missouri
May 9, 2011
Except for Note 10, as to which
the date is October 7, 2011.


F-2


Table of Contents

 
Report of Independent Registered Public Accounting Firm
 
The Partners
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, L.P. and Subsidiaries)
 
We have audited the accompanying consolidated statements of operations, partners’ capital and cash flows for the period from March 31, 2008 (inception) to December 31, 2008 of Armstrong Resource Partners, L.P. and Subsidiaries (formerly Elk Creek, LP and Subsidiaries) (collectively, the “Company”), a development stage enterprise (a Delaware Limited Partnership). These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows for the period from March 31, 2008 (inception) to December 31, 2008 of Armstrong Resource Partners, L.P. and Subsidiaries (formerly Elk Creek, L.P. and Subsidiaries), a development stage enterprise, in conformity with accounting principles generally accepted in the United States of America.
 
/s/  GRANT THORNTON LLP
 
St. Louis, Missouri
July 30, 2010 (except for earnings per limited partner unit and the
“Amendment to the Partnership Agreement” paragraph in Note 10,
as to which the date is October 7, 2011)


F-3


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)

CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2010     2009  
    (Dollars in thousands)  
 
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 155     $ 155  
Inventory
          60  
                 
Total current assets
    155       215  
Mineral rights and land
    75,591       75,591  
Related-party notes receivable
    48,470       11,161  
Related-party other receivables, net
    13,713       4,130  
                 
Total assets
  $ 137,929     $ 91,097  
                 
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities:
               
Accounts payable and accrued liabilities
  $     $  
Note payable
           
                 
Total current liabilities
           
Other non-current liabilities
    12,000       1,600  
                 
Total liabilities
    12,000       1,600  
                 
Partners’ capital:
               
Limited partner’s interest (1,292,000 and 961,000 units issued and outstanding as of December 31, 2010 and 2009, respectively)
    125,532       89,113  
General partner’s interest
    397       384  
                 
Total partners’ capital
    125,929       89,497  
                 
Total liabilities and partners’ capital
  $ 137,929     $ 91,097  
                 
 
See accompanying notes.


F-4


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)

CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Amounts in thousands,
 
    except per unit amounts)  
 
Revenue
  $     $     $  
Costs and expenses:
                       
Legal, accounting, and other professional services
    117       294       240  
Organizational expense
                53  
Related-party service expense
    700       36       27  
Other operating, general, and administrative costs
                12  
                         
Operating loss
    (817 )     (330 )     (332 )
Other expense:
                       
Interest income
    4,209       161        
Interest expense
          (1,723 )     (4,877 )
Other
    (60 )     (2 )      
                         
Net income (loss)
  $ 3,332     $ (1,894 )   $ (5,209 )
                         
Net income attributable to:
                       
General partner
  $ 15     $ (16 )   $ (102 )
                         
Limited partners
  $ 3,317     $ (1,878 )   $ (5,107 )
                         
Basic and diluted net income (loss) per limited partner unit
  $ 2.96     $ (2.62 )   $ (19.79 )
                         
Weighted average number of units outstanding
    1,121       716       258  
                         
 
See accompanying notes.


F-5


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 
                                 
          Limited
    General
       
          Partner’s
    Partner’s
       
    Common Units     Interest     Interest     Total  
          (Dollars in thousands)        
 
Balance at March 31, 2008 (inception)
        $     $     $  
Partner contributions
    545,000       54,500       500       55,000  
Net loss for the year
          (5,107 )     (102 )     (5,209 )
                                 
Balance at December 31, 2008
    545,000       49,393       398       49,791  
Partner contributions
    416,000       41,600             41,600  
Net loss for the year
          (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 for the year
          3,317       15       3,332  
                                 
Balance at December 31, 2010
    1,292,000     $ 125,532     $ 397     $ 125,929  
                                 
 
See accompanying notes.


F-6


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Dollars in thousands)  
 
Operating activities
                       
Net income (loss)
  $ 3,332     $ (1,894 )   $ (5,209 )
Adjustments to reconcile net loss to net cash used in operating activities:
                       
Change in working capital accounts:
                       
Increase in inventory
    60             (60 )
Increase in other non-current liabilities
    10,400       1,600        
(Decrease) increase in accounts payable
          (14 )     14  
                         
Net cash provided by (used in) operating activities
    13,792       (308 )     (5,255 )
                         
Investing activity
                       
Related-party notes receivable
    (37,309 )     (11,161 )      
Related-party other receivables, net
    (9,583 )     (1,263 )     (2,867 )
Investment in mineral rights and land
                (21,591 )
                         
Cash used in investing activity
    (46,892 )     (12,424 )     (24,458 )
                         
Financing activities
                       
Partners’ capital contributions
    33,100       41,600       55,000  
Payment of debt
          (28,878 )     (25,122 )
                         
Net cash provided by financing activities
    33,100       12,722       29,878  
                         
Net change in cash
          (10 )     165  
Cash, at the beginning of the year
    155       165        
                         
Cash, at the end of the year
  $ 155     $ 155     $ 165  
                         
                         
Cash paid — interest
  $     $ 2,636       3,964  
Non-cash investment in property and mineral rights
                       
acquired with debt
  $     $     $ 54,000  
 
See accompanying notes.


F-7


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands)
December 31, 2010
 
1.   DESCRIPTION OF BUSINESS AND ENTITY STRUCTURE
 
In September 2011, Elk Creek, L.P. changed its name to Armstrong Resource Partners, L.P. (ARP). 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); 95% of AE’s equity is held by the limited partner.
 
ARP is headquartered in St. Louis, Missouri, with operational facilities in Western Kentucky. As of December 31, 2010, 2009 and 2008, 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 0.5% at December 31, 2010, with additional capital contributions by the limited partners.
 
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 9. 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 mining related taxes, administrative expenses, and royalties due to landowners.
 
The entities described below are wholly owned and have been consolidated in the financial statements:
 
     
Company
 
Abbreviation
 
Elk Creek Operating GP, LLC
  ECO-GP
Elk Creek Operating LP, LLC
  ECO-LP
Ceralvo Holdings, LLC
  CVH
Ceralvo Resources, LLC
  CVR
 
The Partnership acquired mineral rights and other assets on March 31, 2008. CVH purchased land and mineral rights in Western Kentucky from an unrelated third party for $21.5 million in cash and a $59.2 million promissory note, which was discounted using an effective interest rate of 12% due to the seller in various amounts in 2009 and 2008. All amounts due under promissory notes were paid as of December 31, 2009.
 
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 accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of income and loss during the reporting periods. Actual results could differ from those estimates.


F-8


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in thousands)
December 31, 2010
 
Cash and Cash Equivalents
 
Cash and cash equivalents are stated at cost, which approximates fair value. The Partnership considers all cash and temporary investments having an original maturity of less than three months to be cash equivalents.
 
Financial Instruments
 
Cash and cash equivalents, accounts receivable, accounts payable, and long term debt are stated at their approximate fair value on the consolidated balance sheets due to the short maturity and financial nature of the balances.
 
Accounts and Other Receivables
 
The Partnership has neither trade accounts receivable nor an allowance for doubtful accounts, as it currently is a land holding company. Other receivables at December 31, 2010 and 2009, include $63,487 and $15,632, respectively, of nontrade, related party receivables related to funds advanced to a sister company (ACC) and the ultimate parent company, offset by accounts payable at December 31, 2010 and 2009, of $1,304 and $341, respectively, to the ultimate parent for expenses paid on behalf of the Partnership. All recorded amounts are expected to be fully recoverable. See additional details in Note 5.
 
Inventories
 
Inventories consist of mining supplies that are valued at the lower of cost or market. At December 31, 2010 and 2009, the Partnership had not commenced production and had no coal inventory.
 
Minerals Rights and Land
 
Coal reserves, mineral rights, and land are recorded at cost as mineral rights and land. As of December 31, 2010 and 2009, the net book value of coal reserves is for properties that the Partnership is not mining and, therefore, where the coal is not currently being depleted.
 
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.
 
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 Partnership’s income is ultimately sustained by the taxing authorities.
 
Accounting Pronouncements Adopted
 
In June 2009, the Financial Accounting Standards Board (“FASB”) issued accounting guidance in Accounting Standards Codification (“ASC”) 810 that modifies how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The guidance clarifies that the determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity


F-9


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in thousands)
December 31, 2010
 
that most significantly affect the entity’s economic performance. The guidance also requires an ongoing reassessment of whether a company is the primary beneficiary of a variable interest entity and additional disclosures about a company’s involvement in variable interest entities and any associated changes in risk exposure. The guidance is applicable for annual periods beginning after November 15, 2009 (January 1, 2010 for the Company). The Partnership performed a qualitative assessment of its existing interests and determined that it held no interest in variable interest entities.
 
In January 2010, ASC guidance for fair value measurements and disclosure was updated to require additional disclosures related to transfers in and out of Level 1 and Level 2 fair value measurements. The guidance was amended to clarify the level of disaggregation required for assets and liabilities and the disclosures required for inputs and valuation techniques used to measure the fair value of assets and liabilities that fall in either Level 2 or Level 3. The updated guidance was effective for the Partnership’s fiscal year beginning January 1, 2010. The adoption had no impact on the Partnership’s consolidated financial position, results of operations, or cash flows.
 
3.   MINERAL RIGHTS AND LAND
 
Coal reserves are estimated at 65,591 proven and probable tons (unaudited) with a net book value of $74,720 at both December 31, 2010 and 2009, based on the fair value at the date of acquisition. All amounts are attributable to properties where the Partnership was not currently engaged in mining operations and, therefore, not currently being depleted. Included in the book value of coal are mineral rights for leased coal interests; the net book value of these mineral rights was $4,121 at both December 31, 2010 and 2009. The remaining net book value of the Partnership’s coal reserves of $70,599 at both December 31, 2010 and 2009, relates to coal reserves owned in fee ownership.
 
Mineral rights and land consist of the following as of December 31,
 
                 
    2010     2009  
 
Land
  $ 871     $ 871  
Mineral rights
    74,720       74,720  
                 
Total
  $ 75,591     $ 75,591  
                 
 
4.   RISK MANAGEMENT AND CONCENTRATIONS
 
The Partnership’s operations are concentrated in Western Kentucky, and a disruption within that geographic region could adversely impact the Partnership’s performance.
 
5.   RELATED PARTY TRANSACTIONS
 
At December 31, 2010 and 2009, $15,017 and $4,471, respectively, of intercompany receivables remained net of payables of $1,304 and $341, respectively, to AE and ACC for expenses paid on behalf of the Partnership. Also, AE charged the Partnership $700, $36 and $27 representing an allocated cost for shared accounting and administrative expenses provided during the years ended December 31, 2010, 2009 and 2008, 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 against 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-


F-10


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in thousands)
December 31, 2010
 
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 Note. The interest recorded for the year ended December 31, 2010 and 2009, was $4,209 and $161, respectively. The Notes and accrued interest are due the earlier of May 31, 2014, or the 91st day after AE’s notes payable to third parties have been repaid in full. In addition, AE granted the Partnership the option to purchase a portion of the reserves controlled by AE; this option vests upon AE repaying its notes payable to third parties in full. As the Partnership has the option to purchase reserves from AE or transfer reserves in lieu of repayment of receivables, the Partnership believes it has control of the repayment. Therefore, the Partnership expects repayment in accordance with the aforementioned payment terms. However, in February 2011, as part of a refinancing of the AE debt, these Notes were repaid by a transfer of an undivided interest in reserves to the Partnership. See Note 10 for further discussion.
 
6.   LEASE OBLIGATIONS
 
The Partnership currently has no equipment or facility leases as of December 31, 2010 and 2009.
 
7.   ROYALTIES
 
On December 15, 2008, CVR entered into a coal mining sublease agreement whereby ACC would perform all mine development, mining operations, and coal sales from property leased from CVH. All mining-related costs, including asset retirement obligations, are the responsibility of ACC. The Partnership will receive a monthly royalty based on production and sales of coal from these mines. The Partnership received $1,600 in 2009 and an additional $10,400 in December 2010 as an advance royalty against these future production royalties. As of December 31, 2010, the $12,000 is recorded as both a related-party other receivable and deferred income. As the receivable is not expected to be paid in the next fiscal year, the balance has been classified as long term. The advance royalty is recorded as a liability on the consolidated balance sheet and will be recognized as income as the royalties are earned. In addition, ACC will pay all future advance and production royalties on the CVR properties. Current plans call for ACC to start producing coal in 2011. As discussed in Note 10, as part of a debt repayment by ACC, the Partnership received an undivided interest in a portion of certain reserves. The determination of the Partnership’s portion took into consideration the advance royalty. Accordingly this advance royalty was eliminated in 2011.
 
CVR also grants ACC right of first refusal to mine any current or future property owned by CVR during the term of the coal mining sublease. In exchange for said mining rights, ACC will pay CVR the greater of 7% of the coal sales price or three dollars and fifty cents per ton sold for the previous month’s production.
 
Mining-based royalties are also payable to certain employees of AE and an individual who assisted with the purchase of mining properties. However, those royalties are fully recoverable from ACC and WD based on the terms of the subleases. No such royalties have been incurred or recovered during the years ended December 31, 2010 and 2009.
 
8.   MEMBERS’ INTEREST
 
No distributions have been made to any of the members of ARP or any of its subsidiaries.
 
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.


F-11


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in thousands)
December 31, 2010
 
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 Partnership’s consolidated financial statements.
 
10.   SUBSEQUENT EVENTS
 
The Company has evaluated subsequent events through the date of this report, May 9, 2011.
 
Ownership Items
 
On January 17, 2011, additional capital of $5,000 was contributed by the limited partners in ARP as part of the repayment of AE’s secured promissory note obligations.
 
Debt Repayment
 
On February 9, 2011, AE repaid its secured promissory note obligations and entered into a new credit agreement. As a result of the repayment of the secured promissory notes, the related party promissory notes to ARP were converted to a 39.45% undivided interest in the coal reserves held by AE, which were subsequently leased back to AE. The Partnership will now receive a royalty based on its interest in the reserves at a rate of 7% of revenue generated by AE associated with these reserves. Included in related party other receivables, net at December 31, 2010 was a $12,000 advance royalty receivable that was offset against the transfer of the undivided interest and as such will be eliminated. In addition, ARP is a guarantor of the new credit agreement and its assets are pledged as collateral. As compensation for these restrictions, ARP will receive a fee of 1% of the weighted-average outstanding balance under the credit agreement.
 
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 investment funds managed by Yorktown Partners LLC 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 ARP’s 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 partner’s 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 1,292,000, 961,000 and 545,000 common units issued and outstanding to limited partners as of December 31, 2010, 2009, and 2008, respectively.
 
Restricted Unit Grant
 
On October 1, 2011, the Partnership granted 42,500 restricted units to certain executives. The restricted units 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. 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


F-12


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in thousands)
December 31, 2010
 
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 Partnership’s common units at the date of grant and is amortized to expense ratably over the vesting period, net of forfeitures. Because ARP’s 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 will be expensed through March 31, 2012, as this is the most probable vesting date.


F-13


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, L.P. and Subsidiaries)
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    September 30,
    December 31,
 
    2011     2010  
    (Unaudited)        
    (Restated)        
    (Dollars in thousands)  
 
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 155     $ 155  
Other current assets
    180     $  
                 
Total current assets
    335       155  
Mineral rights, net and land
    142,325       75,591  
Related party notes receivable
          48,470  
Related party other receivables, net
    4,078       13,713  
                 
Total assets
  $ 146,738     $ 137,929  
                 
                 
LIABILITIES AND PARTNERS’ CAPITAL
               
Other non-current liabilities
  $ 11,957     $ 12,000  
                 
Total liabilities
    11,957       12,000  
Partners’ equity:
               
Limited partners’ interest (1,342,000 and 1,292,000 units issued and outstanding as of September 30, 2011 and December 31, 2010, respectively
    134,370       125,532  
General partners’ interest
    411       397  
                 
Total partners’ capital
    134,781       125,929  
                 
Total liabilities and partners’ capital
  $ 146,738     $ 137,929  
                 
 
See accompanying notes to unaudited condensed consolidated financial statements.


F-14


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, L.P. and Subsidiaries)
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
                 
    Nine Months Ended
 
    September 30,  
    2011     2010  
    (Amounts in thousands, except per unit amounts)  
    (Restated)        
Revenue
  $ 5,414     $  
Costs and Expenses:
               
Legal, accounting, and other professional services
    79       66  
Related-party service expense
    540       525  
Depletion
    2,757        
Other operating, general, and administrative costs
    3        
                 
Operating income / (loss)
    2,035       (591 )
Other Income (Expense)
               
Interest income
    1,008       2,855  
Other income, net
    809        
                 
Net income
  $ 3,852     $ 2,264  
                 
Net income attributable to:
               
General Partner
  $ 14     $ 10  
                 
Limited Partner
  $ 3,838     $ 2,254  
                 
Basic and diluted net income per limited partner unit
  $ 2.88     $ 2.08  
                 
Weighted average number of units outstanding
    1,339       1,085  
                 
 
See accompanying notes to unaudited condensed consolidated financial statements.


F-15


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, L.P. and Subsidiaries)
 
 
                 
    Nine Months Ended September 30,  
    2011     2010  
    (Restated)        
    (Amounts in thousands, except per unit amounts)  
 
Cash Flows from Operating Activities:
               
Net income
  $ 3,852     $ 2,264  
Adjustments to reconcile net income to cash provided by
               
operating activities:
               
Depletion
    2,757        
Change in operating assets and liabilities:
               
Other current assets
    (180 )      
Other non-current liabilities
    (43 )      
                 
Net cash provided by operating activities:
    6,386       2,264  
                 
Cash Flows from Investing Activities:
               
Related-party notes receivable
    48,470       (24,596 )
Related-party other receivables
    9,635       232  
Investment in mineral reserves and land
    (69,491 )      
                 
Net cash used in investing activities
    (11,386 )     (24,364 )
                 
Cash Flows from Financing Activities:
               
Partners’ capital contributions
    5,000       22,100  
                 
Net cash provided by financing activities
    5,000       22,100  
                 
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-16


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, L.P. and Subsidiaries)
 
UNAUDITED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
 
                                 
    Nine Months Ended September 30, 2011  
          Limited
    General
       
          Partners’
    Partner’s
       
    Common Units     Interest     Interest     Total  
          (Restated)     (Restated)     (Restated)  
    (Dollars in thousands)  
 
Balance at December 31, 2010
    1,292,000     $ 125,532     $ 397     $ 125,929  
Partner contributions
    50,000       5,000             5,000  
Net income
          3,838       14       3,852  
                                 
Balance at September 30, 2011
    1,342,000     $ 134,370     $ 411     $ 134,781  
                                 
 
See accompanying notes to unaudited condensed consolidated financial statements.


F-17


Table of Contents

Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
(Dollars in thousands)
 
1.   DESCRIPTION OF BUSINESS AND ENTITY STRUCTURE
 
In September 2011, Elk Creek, L.P. changed its name to Armstrong Resource Partners, L.P. (“ARP”). 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 company”); 96% of AE’s equity is held by the limited partner.
 
ARP is headquartered in St. Louis, Missouri, with operational assets in Western Kentucky. For the nine months ended September 30, 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 September 30, 2011, with additional capital contributions by the limited partners.
 
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. 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 mining related taxes, depletion, administrative expenses, and royalties due to landowners.
 
The entities described below are wholly owned and have been consolidated in the financial statements:
 
         
Company
  Abbreviation  
 
Elk Creek Operating GP, LLC
    ECO-GP  
Elk Creek Operating LP, LLC
    ECO-LP  
Ceralvo Holdings, LLC
    CVH  
Western Mineral Development, LLC
    WMD  
 
The Partnership acquired mineral rights and other assets on March 31, 2008 when CVH purchased land and mineral rights in Western Kentucky from an unrelated third party for $21,500 in cash and a $59,162 promissory note. The note was discounted using an effective interest rate of 12% due to the seller in various amounts in 2009 and 2008. All amounts due under promissory notes were paid as of December 31, 2009.
 
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting and U.S. Securities and Exchange Commission regulations. In the opinion of management, all adjustments, consisting of normal, recurring accruals considered necessary for a fair presentation, have been included. Results of operations for the nine months ended September 30, 2011 are not necessarily indicative of results to be expected for the year ending December 31, 2011. These financial statements should be read in conjunction with the audited financial statements and related notes as of and for the year ended December 31, 2010.
 
The Partnership has evaluated subsequent events and transactions for potential recognition or disclosure in the financial statements through the day the financial statements are available to be issued.
 
2.   NEWLY ADOPTED ACCOUNTING STANDARDS AND STANDARDS NOT YET IMPLEMENTED
 
In January 2010, the FASB issued accounting guidance that requires new fair value disclosures, including disclosures about significant transfers into and out of Level 1 and Level 2 fair-value measurements and a description of the reasons for the transfers. In addition, the guidance requires new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The new disclosure


F-18


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
(Dollars in thousands)
 
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 Partnership’s 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 Partnership’s 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 Partnership’s consolidated financial statements.
 
3.   Restatement
 
The Partnership has restated its previously issued financial statements for the six and nine month periods ended June 30, 2011 and September 30, 2011, respectively, to correct the accounting for depletion. An error was identified in the calculation of depletion expense resulting in an understatement of the results of operations. The restatement has no effect on the Partnership’s net cash flows or liquidity.
 
Impact of the Financial Statement Adjustments on the Consolidated Statements of Operations
 
The table below presents the impact of the financial statement adjustments related to the restatement of the Company’s previously issued Consolidated Statements of Operations for the six and nine months ended June 30, 2011 and September 30, 2011, respectively:
 
                                                 
    Six Months Ended June 30, 2011     Nine Months Ended September 30, 2011  
    As Reported     Adjustment     As Adjusted     As Reported     Adjustment     As Adjusted  
 
Depletion
  $ 2,342     $ (792 )   $ 1,550     $ 4,163     $ (1,406 )   $ 2,757  
Operating income
    316       792       1,108       629       1,406       2,035  
Net income
    1,730       792       2,522       2,446       1,406       3,852  
Basic and diluted net income per limited partner unit
  $ 1.29     $ 0.60     $ 1.89     $ 1.82     $ 1.06     $ 2.88  


F-19


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
(Dollars in thousands)
 
Impact of the Financial Statement Adjustments on the Consolidated Balance Sheets
 
The table below presents the impact of the financial statement adjustments related to the restatement of the Company’s previously issued Consolidated Balance Sheets for the six and nine months ended June 30, 2011 and September 30, 2011, respectively:
 
                                                 
    As of June 30, 2011     As of September 30, 2011  
    As Reported     Adjustment     As Adjusted     As Reported     Adjustment     As Adjusted  
 
Mineral reserves, net and land
  $ 142,740     $ 792     $ 143,532     $ 140,919     $ 1,406     $ 142,325  
Total assets
    144,659       792       145,451       145,332       1,406       146,738  
Partners’ Equity
                                               
Limited partners’ interest
    132,256       789       133,045       132,969       1,401       134,370  
General partners’ interest
    403       3       406       406       5       411  
Total partners’ capital
    132,659       792       133,451       133,375       1,406       134,781  
Total liabilities and partners’ capital
    144,659       792       145,451       145,332       1,406       146,738  
 
Impact of the Financial Statement Adjustments on the Consolidated Statements of Cash Flows
 
The restatement of the Consolidated Statements of Cash Flows for the six and nine months ended June 30, 2011 and September 30, 2011, respectively, did not affect the Company’s cash flows from financing or investing activities. The table below reflects adjustments to the Company’s cash flows from operating activities:
 
                                                 
    Six Months Ended June 30, 2011     Nine Months Ended September 30, 2011  
    As Reported     Adjustment     As Adjusted     As Reported     Adjustment     As Adjusted  
 
Cash flows from operating activities:
                                               
Net income
  $ 1,730     $ 792     $ 2,522     $ 2,446     $ 1,406     $ 3,852  
Depletion
    2,342       (792 )     1,550       4,163       (1,406 )     2,757  
Net cash provided by operating activities
    4,072             4,072       6,386             6,386  
 
4.   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 investment funds managed by Yorktown Partners LLC, the Partnership’s 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 ARP’s 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 partner’s 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 September 30, 2011 and December 31, 2010, respectively.


F-20


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
(Dollars in thousands)
 
5.   RELATED-PARTY TRANSACTIONS
 
On November 30, 2009, and again on March 31, 2010, May 31, 2010, and November 30, 2010, AE entered into promissory notes with the Partnership (“ARP promissory notes”) whereby the Partnership loaned funds to AE for the sole purpose of meeting certain debt service obligations. The amounts were $11,000 on November 30, 2009; $9,500 on March 31, 2010; $12,600 on May 31, 2010; and $11,000 on November 30, 2010. The ARP promissory notes had a fixed interest rate of 3%. In addition, contingent interest equal to 7% of revenue would be accrued to the extent it exceeds the fixed interest amount. No payments of principal or interest were due until the earliest of May 31, 2014, or the 91st day after the secured promissory notes had been paid in full. Further, the Partnership, in lieu of receipt of the outstanding amounts of principal and interest, had the option to obtain an interest in the mineral rights and land of AE equal to the percentage of the aggregate amount of principal loaned and related accrued interest to the amount paid by AE to repay or repurchase and retire the ARP promissory notes. This option could only be exercised if all of the aforementioned debt obligations are repaid in full.
 
On February 9, 2011, AE repaid its secured promissory note obligations and entered into a new credit agreement. As a result of the repayment, the Partnership exercised its option to convert the ARP promissory notes to a 39.45% undivided interest in certain reserves and land held by AE. Outstanding principal and interest of the ARP promissory notes totaled $46,620 as of February 9, 2011. As additional consideration for the land and mineral reserves transferred, the Partnership paid $5,000 cash and certain amounts due to the Partnership totaling $17,871 were forgiven, resulting in aggregate consideration of $69,491. Of the purchase price, $12,389 and $57,102 has been allocated to the land and mineral rights, respectively. Simultaneous with this transaction, the Partnership entered into a lease agreement, under mutually agreeable terms and conditions, for AE to mine the acquired mineral reserves. The lease is for a term of 10 years and can be extended for additional periods until all the respective merchantable and mineable coal is removed. In connection with the lease, the Partnership will receive a royalty from AE based on its interest in the reserves at a rate of 7% of revenue.
 
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 Partnership’s wholly owned subsidiaries, WMD and 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.
 
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 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


F-21


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
(Dollars in thousands)
 
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 September 30, 2011, the principal amount outstanding under the credit agreement was $134,600 and the credit support fee earned by the Partnership for the nine months ended September 30, 2011 was $810.
 
At September 30, 2011 and December 31, 2010, $9,965 and $15,017, respectively, of intercompany receivables remained net of payables of $5,887 and $1,304, respectively, to AE and ACC for expenses paid on behalf of the Partnership. Also, AE charged the Partnership $540 and $525, representing an allocated cost for shared accounting and administrative expenses provided, during the nine months ended September 30, 2011 and 2010, 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.
 
6.   MINERAL RIGHTS AND LAND
 
Mineral rights and land consist of the following:
 
                 
    September 30, 2011     December 31, 2010  
    (Restated)        
 
Land
  $ 13,260     $ 871  
Mineral rights
    131,822       74,720  
                 
      145,082       75,591  
Less depletion
    (2,757 )      
                 
Total
  $ 142,325     $ 75,591  
                 
 
7.   MEMBERS’ INTEREST
 
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 in ARP as part of the repayment of AE’s secured promissory notes.
 
8.   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 Partnership’s consolidated financial statements.
 
9.   EQUITY AWARDS
 
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 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


F-22


Table of Contents

 
Armstrong Resource Partners, L.P. and Subsidiaries
(formerly Elk Creek, LP and Subsidiaries)
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
(Dollars in thousands)
 
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 Partnership’s common units at the date of grant and is amortized to expense ratably over the vesting period, net of forfeitures. Because ARP’s 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.


F-23


Table of Contents

 
ARMSTRONG RESOURCE PARTNERS, L.P.
 
Common Units
 
of
 
Limited Partnership Interest
 
 
 
PROSPECTUS
 
 
 
Raymond James
 
FBR
 
          , 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 dealer’s obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 


Table of Contents

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*
       
Nasdaq listing fee*
       
Printing and engraving expenses*
       
Legal fees and expenses*
       
Accounting fees and expenses*
       
Transfer agent fees*
       
Miscellaneous*
       
         
Total*
       
 
 
* To be completed by amendment.
 
Item 14.   Indemnification of Directors and Officers
 
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 do not give effect to an assumed 6.607 to 1 unit split to be effected prior to this offering):
 
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 300,000 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 306,000 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


Table of Contents

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 110,000 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 95,000 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 126,000 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 110,000 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 50,000 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 42,500 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 Yorktown Energy Partners IX, L.P. in consideration of $20,000,000. These shares were issued in a transaction exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.
 
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.
 
Item 17.   Undertakings
 
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


Table of Contents

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


Table of Contents

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 February 10, 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 February 10, 2012.
 
         
Signature
 
Title
 
     
*

J. Hord Armstrong, III
  Chairman and Chief Executive Officer
(Principal Executive Officer)
     
/s/  Martin D. Wilson

Martin D. Wilson
  President and Director
     
*

J. Richard Gist
  Senior Vice President, Finance and Administration
and Chief Financial Officer
(Principal Financial and Accounting Officer)
     
*

Anson M. Beard, Jr.
  Director
     
*

James C. Crain
  Director
     
*

Richard F. Ford
  Director
     
*

Bryan H. Lawrence
  Director
     
*

Greg A. Walker
  Director
         
*By:  
/s/  Martin D. Wilson

Attorney-in-fact
   


II-4


Table of Contents

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*   Second Amended and Restated Agreement of Limited Partnership, dated as of          .
  3 .5*   Form of Designations of Series A Convertible Preferred Units of Armstrong Resource Partners, L.P.
  5 .1*   Form of Opinion of Armstrong Teasdale LLP.
  8 .1*   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.
  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.


II-5


Table of Contents

         
Exhibit
   
Number
 
Description
 
  10 .14   Tennessee Valley Authority Coal Acquisition & Supply Contract Supplement No. 7, dated as of December 29, 2009.
  10 .15   Tennessee Valley Authority Coal Supply & Origination Contract Supplement No. 8, dated as of May 25, 2011.
  10 .16   Tennessee Valley Authority Coal Supply & Origination Contract Supplement No. 9, dated as of August 9, 2011.
  10 .17*   Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of January 1, 2008.
  10 .18*   Amendment No. 1 to Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of July 1, 2008.
  10 .19*   Amendment No. 2 to Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of December 22, 2009.
  10 .20*   Letter Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated December 8, 2008.
  10 .21*   Letter Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated April 1, 2009.
  10 .22*   Settlement Agreement and Release by and between Louisville Gas and Electric Company and Kentucky Utilities Company and Armstrong Coal Company, Inc., dated as of December 22, 2009.
  10 .23*   Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of December 22, 2009.
  10 .24*   Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of January 1, 2012.
  10 .25*   Fuel Purchase Order by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated July 1, 2008.
  10 .26*   Amendment No. 1 to Fuel Purchase Order dated July 1, 2008 by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated July 28, 2008.
  10 .27*   Fuel Purchase Order by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated January 1, 2010.
  10 .28**†   Letter Agreement between Armstrong Land Company, LLC and J. Richard Gist, dated as of September 14, 2009.
  10 .29**†   Employment Agreement by and between Armstrong Energy, Inc. and J. Richard Gist, dated as of October 1, 2011.
  10 .30**†   Employment Agreement by and between Armstrong Energy, Inc. and J. Hord Armstrong, III, dated as of October 1, 2011.
  10 .31**†   Employment Agreement by and between Armstrong Energy, Inc. and Martin D. Wilson, dated as of October 1, 2011.
  10 .32**†   Employment Agreement by and between Armstrong Coal Co. and Kenneth E. Allen, dated as of June 1, 2007.
  10 .33**†   Employment Agreement by and between Armstrong Coal Co. and David R. Cobb, dated as of January 19, 2007.
  10 .34†   Employment Agreement by and between Armstrong Energy, Inc. and Brian G. Landry, dated as of December 1, 2011.
  10 .35**†   Restricted Unit Award Agreement between Armstrong Resource Partners, L.P. and J. Hord Armstrong, III, dated as of October 1, 2011.
  10 .36**†   Restricted Unit Award Agreement between Armstrong Resource Partners, L.P. and Martin D. Wilson, dated as of October 1, 2011.

II-6


Table of Contents

         
Exhibit
   
Number
 
Description
 
  10 .37**†   Form of Armstrong Energy, Inc. Director Indemnification Agreement.
  10 .38**†   Armstrong Energy, Inc. 2011 Long-Term Incentive Plan.
  10 .39†   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 .40**†   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 .41*   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 .42*   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 .43*   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 .44*   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 .45*   Promissory Note of Armstrong Land Company, LLC in favor of Elk Creek, L.P. in the principal amount of $11.0 million, dated November 30, 2010.
  10 .46*   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 .47*   Lease and Sublease Agreement between Armstrong Coal Company, Inc. and Ceralvo Holdings, LLC, dated February 9, 2011.
  10 .48*   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 .49*   Lease Agreement by and between Armstrong Coal Company, Inc. and David and Rebecca Cobb, dated August 1, 2009.
  10 .50*   Purchase Agreement between Western Land Company, LLC and Pond Creek Partners, LLC, effective January 5, 2011.
  10 .51*   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 .52*   Coal Mining Lease and Sublease by and between Ceralvo Holdings, LLC and Armstrong Coal Company, Inc., dated as of February 9, 2011.
  10 .53*   Contract to Sell Real Estate by and between Western Diamond LLC, Western Land Company, LLC and Western Mineral Development, LLC, dated as of October 11, 2011.
  10 .54**   Form of Lease Agreement between Armstrong Resource Partners, L.P. and Armstrong Energy, Inc.
  16 .1**   Letter from Grant Thornton LLP to Securities and Exchange Commission.
  16 .2**   Letter from KPMG LLP to Securities and Exchange Commission.
  21 .1**   List of Subsidiaries.
  23 .1*   Consent of Armstrong Teasdale LLP (included in Exhibit 5.1).
  23 .2   Consent of Ernst & Young LLP.
  23 .3   Consent of Grant Thornton LLP.
  23 .4**   Consent of Weir International, Inc.

II-7


Table of Contents

         
Exhibit
   
Number
 
Description
 
  24 .1**   Power of Attorney (included on signature page).
  99 .1*   Audit Committee Charter.
  99 .2*   Compensation Committee Charter.
  99 .3*   Nominating and Corporate Governance Committee Charter.
 
 
* To be filed by amendment.
 
** Previously filed.
 
Indicates a management contract or compensatory plan or arrangement.

II-8