Attached files

file filename
EX-1.1 - EX-1.1 - Armstrong Resource Partners, L.P.c65698a6exv1w1.htm
EX-23.2 - EX-23.2 - Armstrong Resource Partners, L.P.c65698a6exv23w2.htm
EX-10.62 - EX-10.62 - Armstrong Resource Partners, L.P.c65698a6exv10w62.htm
Table of Contents

As filed with the Securities and Exchange Commission on May 30, 2012
Registration Statement No. 333-177260
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Amendment No. 6
to
Form S-1
 
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
 
 
 
ARMSTRONG RESOURCE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
 
         
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 MAY 30, 2012
           Common Units
 
ARMSTRONG RESOURCE PARTNERS, L.P.
Limited Partner Interests
 
 
This is the initial public offering of our common units. We are offering     common units representing limited partner interests in Armstrong Resource Partners, L.P. No public market currently exists for our common units. We currently expect the initial public offering price to be between $     and $     per common unit.
 
We have applied to list our common units on the Nasdaq Capital Market (“Nasdaq”) under the symbol ‘‘ARPS.” There is no assurance that this application will be approved. We are an “emerging growth company,” as such term is defined in Section 2(a)(19) of the Securities Act of 1933, as amended.
Investing in our common units involves risks. You should read the section entitled “Risk Factors” beginning on page 22 for a discussion of certain risk factors that you should consider before investing in our common units. These risks include the following:
  •  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, Inc., which we refer to as Armstrong Energy.
  •  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.
 
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
  $       $  
 
 
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
Stifel Nicolaus Weisel
 
Prospectus, dated          , 2012


Table of Contents

(MAP)


 

 
TABLE OF CONTENTS
 
         
    Page
 
    ii  
    1  
    22  
    50  
    52  
    53  
    54  
    55  
    57  
    59  
    68  
    78  
    110  
    128  
    130  
    134  
    139  
    142  
    143  
    154  
    156  
    176  
    178  
    184  
    184  
    184  
    184  
    185  
    F-1  
 EX-1.1
 EX-10.62
 EX-23.2
 
No dealer, salesperson or other individual has been authorized to give any information or to make any representation other than those contained in this prospectus in connection with the offer made by this prospectus and, if given or made, such information or representations must not be relied upon as having been authorized by us or the underwriters. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities in any jurisdiction in which such an offer or solicitation is not authorized or in which the person making such offer or solicitation is not qualified to do so, or to any person to whom it is unlawful to make such offer or solicitation. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create any implication that there has been no change in our affairs or that information contained herein is correct as of any time subsequent to the date hereof.


i


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, 2011. In addition, we pay a subscription fee to Wood Mackenzie to obtain access to pre-prepared reports. Except with respect to payment for Weir International, Inc.’s services in this regard and the subscription fee paid to Wood Mackenzie, we did not fund and are not otherwise affiliated with any of the sources cited in this prospectus. Forward-looking information obtained from these sources is subject to the same qualifications and additional uncertainties regarding the other forward-looking statements in this prospectus.
 
For investors outside the United States: We have not, and the underwriters have not, done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus must inform themselves, and observe any restrictions relating to, the offering of the common units of limited partnership interest and the distribution of this prospectus outside the United States.


ii


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 22 of this prospectus and the financial statements and related notes thereto included elsewhere in this prospectus.
 
As used in this prospectus, unless the context otherwise requires or indicates, references to “Armstrong Resource Partners,” the “Partnership,” “we,” “our,” and “us” are to Armstrong Resource Partners, L.P. and its subsidiaries taken as a whole. References to “Armstrong Energy, Inc.” and “Armstrong Energy” are to Armstrong Energy, Inc. and its subsidiaries taken as a whole. References to “limited partners” include holders of common units representing limited partnership interests in Armstrong Resource Partners.
 
As described more fully below, concurrently with the offering of common units of Armstrong Resource Partners, L.P. being made pursuant to this prospectus, Armstrong Energy, Inc. is engaging in an offering of its common stock. This prospectus relates solely to the offering of the common units of Armstrong Resource Partners, L.P. and does not relate to the concurrent offering by Armstrong Energy, Inc., which will be made by a separate prospectus.
 
About the Partnership
 
We are a limited partnership formed in 2008 to engage in the business of management and leasing of coal properties and collection of coal production royalties in the Western Kentucky region of the Illinois Basin. We currently own approximately 65 million tons of coal reserves and, as of March 31, 2012, had a 50.81% undivided interest in approximately 140 million tons of coal reserves owned by Armstrong Energy, all located in Ohio and Muhlenberg counties in Western Kentucky. Our coal is generally low chlorine, high sulfur coal. Our outstanding limited partnership interests (“common units”), representing 98.36% of our common units, are owned by investment funds managed by Yorktown Partners LLC (collectively, “Yorktown”). We are not engaged in the permitting, production or sale of coal, nor in the operation or reclamation of coal mining activity. We are a fee mineral and surface rights owning entity. It is our intention to remain a coal leasing enterprise and not to engage in coal production ourselves.
 
We currently lease all of our reserves to Armstrong Energy, our sole lessee, in exchange for royalty payments in the amount of 7% of the revenue received from coal sold from those reserves. Armstrong Energy is a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin with both surface and underground mines. Armstrong Energy is currently deferring the cash payment of those royalty payments. Partially as a result of those deferrals, as of December 31, 2011 we were owed approximately $5.7 million from Armstrong Energy.
 
We intend to use the net proceeds from this offering to purchase an additional estimated 8% to 10% partial undivided interest in the reserves in which we had, as of March 31, 2012, a 50.81% interest. See “— Business Developments” and “Certain Relationships and Related Party Transactions — Membership Interest Purchase Agreement.” The actual percentage acquired will depend on the fair value of the reserves at the time of the acquisition and the net proceeds received in this offering. In addition, our interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves could be increased as a result of an additional acquisition through the offset of unpaid deferred royalties owed to us.
 
We expect Armstrong Energy to continue to defer royalty payments due to us and we do not plan to pay distributions to any of our unitholders, except for amounts necessary to enable unitholders to pay anticipated income tax liabilities, for the foreseeable future. As a result, we expect to continue to acquire an increasing percentage undivided interest in Armstrong 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


1


Table of Contents

borrowings under the Senior Secured Credit Facility. Under the terms of the Senior Secured Credit Facility, without the consent of all lenders (if there are fewer than three lenders at the time of any dividend or distribution) or the lenders having more than 50% of the aggregate commitments (if there are three or more lenders at the time of any dividend or distribution) under that facility, we are currently prohibited from making dividend payments or other distributions to our unitholders in excess of $5.0 million per year and $10.0 million in aggregate, except for dividends or other distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership until February 9, 2016, the date on which the Senior Secured Credit Facility matures. We are not permitted to borrow additional funds under the Senior Secured Credit Facility and as such, it is not a source of liquidity for us.
 
A wholly owned subsidiary of Armstrong Energy, Inc., Elk Creek GP, LLC (“Elk Creek GP”), is our general partner. Pursuant to our Second Amended and Restated Agreement of Limited Partnership, to be effective upon the closing of this offering (the “Partnership Agreement”), Elk Creek GP has the exclusive authority to conduct, direct and manage all of our activities. By virtue of Armstrong 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 2011 and the three months ended March 31, 2012, Armstrong Energy is obligated to pay us $7.2 million and $2.1 million, respectively, for production royalties under our leases for such period. In addition, we earned a credit and collateral support fee as a result of our financing activities in the amount of $1.15 million and $0.3 million in 2011 and the three months ended March 31, 2012, respectively.
 
The following table summarizes our coal reserves as of December 31, 2011. All of our reserves are leased to Armstrong Energy.
 
                                                                                 
          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       56,430       8,985       65,415       56,430       8,985       65,415       11,792       4.5       7.6  
Partially Owned Reserves
                                                                               
Reserves in Active Production(5)
                                                                               
Midway
    S       19,377       1,427       20,805       7,644       563       8,207       11,315       4.8       10.0  
Parkway
    U       7,535       5,434       12,969       2,973       2,144       5,116       11,931       4.4       7.1  
East Fork(6)
    S       2,287       550       2,837       902       217       1,119       11,136       7.6       11.2  
Equality Boot
    S       21,841       1,151       22,992 (7)     8,616       454       9,070       11,587       5.7       8.8  
Lewis Creek
    S       6,160       101       6,261       2,430       40       2,470       11,420       4.0       9.5  
Maddox
    S       512             512       202             202       11,315       4.8       10.0  
                                                                                 
Total Partially Owned Reserves in Active Production
            57,712       8,663       66,376       22,767       3,418       26,185                          
Additional Reserves
                                                                               
Ken
    S       17,166       3,854       21,020       6,772       1,520       8,292       11,809       5.0       7.5  
Other
    S/U       40,145       12,016       52,159 (8)     15,837       4,740       20,578       11,300       4.5       8.0  
                                                                                 
Total Additional Reserves
            57,311       15,870       73,179       22,609       6,261       28,870                          
                                                                                 
Total
            171,453       33,518       204,970       101,807       18,663       120,470                          
                                                                                 
 
 
(1) Determined as of December 31, 2011. Gross amounts reflect the combined 100% joint ownership interest of Armstrong Resource Partners and Armstrong Energy in reserves in active production. Net amounts


2


Table of Contents

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) We commenced production at the Kronos underground mine in September 2011.
 
(5) Reserves that are in active production as of December 31, 2011.
 
(6) Warden and Kronos surface pits. Production at the Kronos pit ceased in August 2011.
 
(7) Includes approximately 0.3 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.
 
(8) Includes approximately 1.9 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.
 
The following table summarizes the ownership status of our reserves by mine as of December 31, 2011 and our 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
          Year
          Year
 
    (Proven and Probable
    (Proven and Probable
    Year Ended
    Ended
    Year Ended
    Ended
 
    Reserves)(1)     Reserves)(1)     December 31,
    December 31,
    December 31,
    December 31,
 
Reserve
  Owned     Leased     Total     Owned     Leased     Total     2010     2011     2010     2011  
    (In thousands)     (In thousands)     (Tons in thousands)     (Tons in thousands)  
 
Owned
                                                                               
Elk Creek(3)
    61,890       3,525       65,415       61,890       3,525       65,415             (4)            
Partially Owned
                                                                               
Midway
    20,805             20,805       8,207             8,207       1,614.8       1,589.2       637.0       626.9  
Parkway
    2,326       10,643       12,969       918       4,199       5,116       1,485.9       1,491.9       586.2       588.6  
East Fork(5)
    2,193       645       2,837       865       254       1,119       1,641.1       745.9       647.4       294.3  
Equality Boot
    22,992             22,992 (6)     9,070             9,070       330.8       1,916.8       130.5       756.2  
Lewis Creek
    6,261             6,261       2,470             2,470             474.9             187.4  
Maddox
    512             512       202             202             24.9             9.8  
                                                                                 
Total Active
    55,089       11,288       66,376       21,732       4,453       26,185       5,072.6       6,243.6       2,001.1       2,463.1  
                                                                                 
Additional Reserves
                                                                               
Ken
    21,020             21,020       8,292             8,292                                  
Other
    35,427       16,732       52,159 (7)     13,977       6,601       20,578       572.1 (8)     398.8 (8)     225.7       157.3  
                                                                                 
Total Additional
    56,447       16,732       73,179       22,269       6,601       28,870                                  
                                                                                 
Total
    173,426       31,545       204,970       105,891       14,579       120,470       5,644.7       6,642.4       2,226.8       2,620.4  
                                                                                 
 
 
(1) For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.
 
(2) Determined as of December 31, 2011. Gross amounts reflect the combined 100% joint ownership interest of Armstrong Resource Partners and Armstrong Energy in reserves in active production. Net production amounts reflect our 39.45% undivided interest in such jointly controlled reserves as if we had this ownership since January 1, 2010. Our actual proportion of sales began in February 2011 and amounted to approximately 2.5 million tons for the year ended December 31, 2011. Upon completion of this offering,


3


Table of Contents

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 at the Kronos mine in September 2011.
 
(4) The Kronos underground mine produced approximately 0.2 million tons of coal in 2011, but the production was capitalized and not included in our results of operations because the mine was still in the developmental phase.
 
(5) Warden and Kronos surface pits. Production at the Kronos pit ceased in August 2011.
 
(6) Includes approximately 0.3 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.
 
(7) Includes approximately 1.9 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.
 
(8) Includes production from the Big Run mine, which ceased operation in October 2011.
 
On March 30, 2012, Armstrong Energy transferred an 11.36% undivided interest in certain of its land and mineral reserves to Armstrong Resource Partners in exchange for aggregate consideration of $25.7 million. This increased Armstrong Resource Partners’ interest in certain properties of Armstrong Energy to 50.81%. See “— Business Developments.”
 
Royalty Business
 
We are a royalty business. Royalty businesses principally own and manage mineral reserves. As an owner of mineral reserves, we typically are not responsible for operating mines, but instead enter into leases with mine operators granting them the right to mine and sell reserves from our property in exchange for a royalty payment. A typical lease has a 5- to 10-year base term, with the lessee having an option to extend the lease for additional terms. Leases may include the right to renegotiate rents and royalties for the extended term. At this time we have a single lessee, Armstrong Energy, and each of the leases with it has an initial term of 10 years.
 
Our royalty revenues are calculated based on a percentage of the gross sales price of the aggregate tons of coal sold by a lessee. Our royalty revenues are affected by changes in long-term and spot commodity prices, sales volumes, our 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.
 
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


4


Table of Contents

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 0.3% equity interest in us through its wholly-owned subsidiary, Elk Creek GP, which is our general partner. As of December 31, 2011, of Armstrong Energy, Inc.’s total controlled reserves of 326 million tons, 65 million tons (20%) are wholly owned by us, and 140 million tons (43%) are held by Armstrong Energy and us as joint tenants-in-common with 49.19% and 50.81% interests, respectively, and the balance of the reserves Armstrong Energy controls are leased by Armstrong Energy from a third party, and are not included in Armstrong Resource Partners’ option to purchase an additional interest.
 
Armstrong Energy markets its coal primarily to electric utility companies as fuel for their steam-powered generators. Based on 2011 production, Armstrong Energy is the sixth largest producer in the Illinois Basin and the second largest in Western Kentucky. It commenced production in the second quarter of 2008 and currently operates seven mines, including five surface and two underground, and is seeking permits for three additional mines. Armstrong Energy’s revenue increased from zero in 2007 to $299.3 million in 2011. For the year ended December 31, 2011, it produced 6.6 million tons of coal, with seven mines in operation, and currently expects a significant increase in its production for 2012 compared to 2011. During the three months ended March 31, 2012, it produced 2.2 million tons of coal, with seven mines in operation. The majority of the foregoing production is derived from coal reserves in which we obtained an undivided interest during 2011 and that Armstrong Energy now leases from us.
 
Business Developments
 
In 2009 and 2010, Armstrong Energy borrowed an aggregate principal amount of $44.1 million from us, and the proceeds of those loans were used to satisfy various installment payments required by the promissory notes that were delivered in connection with the acquisition of Armstrong 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 December 31, 2011.
 
On February 9, 2011, Armstrong Energy entered into lease agreements with us pursuant to which we granted Armstrong Energy leases to our 39.45% undivided interest in the mining properties described above and licenses to


5


Table of Contents

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.
 
Based upon Armstrong Energy’s current estimates of production for 2012, we anticipate that Armstrong Energy will owe us royalties under the above-mentioned license and lease arrangements of approximately $14.8 million in 2012 of which $5.6 million will be recoupable against the advance royalty payment referred to above.
 
In December 2011, we sold 200,000 Series A convertible preferred units of limited partner interest to Yorktown in exchange for $20.0 million. Also in December 2011, we entered into a Membership Interest Purchase Agreement with Armstrong Energy pursuant to which Armstrong Energy agreed to sell to us, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of its membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. In exchange for Armstrong Energy’s agreement to sell a partial undivided interest in those reserves, we paid Armstrong Energy $20.0 million. In addition to the cash paid, certain amounts due to us totaling $5.7 million were forgiven by Armstrong Energy, which resulted in aggregate consideration of $25.7 million. This transaction, which closed in March 2012, resulted in the transfer by Armstrong Energy of an 11.36% undivided interest in certain of its land and mineral reserves to us. We agreed to lease the newly transferred mineral reserves to Armstrong Energy on the same terms as the February 2011 lease. As of March 31, 2012, we had a 50.81% undivided interest in certain of the land and mineral reserves of Armstrong Energy.


6


Table of Contents

Concurrent Offering
 
Concurrent with this offering of common units, Armstrong Energy, Inc. is offering its common stock pursuant to a separate initial public offering (the “Concurrent AE Offering”). Armstrong Energy indirectly holds a 0.3% equity interest in us. See “Business — Our Organizational History.” If the Concurrent AE Offering and the related transactions between Armstrong Resource Partners and Armstrong Energy are completed, we expect that Armstrong Energy will use approximately $40.0 million of the net proceeds from the Concurrent AE Offering to repay a portion of Armstrong 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 2011, a substantial majority of which was sold by U.S. coal producers to operators of electricity generation plants. Coal-fired electricity generation is the largest component of total world electricity generation. The following market dynamics and trends currently impact thermal coal consumption and production in the United States and are reshaping competitive advantages for coal producers.
 
  •  Stable long-term outlook for U.S. thermal coal market.  According to the EIA, coal-fired electricity generation accounted for approximately 42% of all electricity generation in the United States in 2011. On a long-term basis, coal continues to be the lowest cost fossil fuel source of energy for electric power generation. Despite recent increases in generation from natural gas, as well as federal and state subsidies for the construction and operation of renewable energy, the EIA projects that coal-fired generation will continue to remain the largest single source of electricity generation in 2035, at 39% of total generation by 2035, compared to approximately 42% during 2011.
 
  •  Increasing demand for coal produced in the Illinois Basin.  According to Wood Mackenzie, a leading commodities consultancy, demand for coal produced from the Illinois Basin is expected to grow by 48% from 2010 through 2015 and by 108% from 2010 through 2030. We believe this is due to a combination of factors including:
 
  è  Significant expansion of scrubbed coal-fired electricity generating capacity.  The EIA forecasts a 12% increase in flue gas desulfurization (“FGD”) installed on the coal-fired generation fleet from 199 gigawatts in 2010 to 222 gigawatts, or 70% of all U.S. coal-fired capacity in the electric sector by 2035, as electricity generation operators invest in retrofit emissions reduction technology to comply with new U.S. Environmental Protection Agency (“EPA”) regulations under the Cross-State Air Pollution Rule and the new mercury and air toxics standards (“MATS”) for power plants. Currently, the EIA estimates that approximately 63% of all U.S. coal-fired generation capacity has FGD technology installed or under construction. Illinois Basin coal generally has a higher sulfur content per ton than coal produced in other regions. However, we believe that FGD utilization will enable operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.
 
  è  Declines in Central Appalachian thermal coal production.  Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 115 million tons in 2011 to 64 million tons in 2015, due to reserve depletion, regulatory-driven decreases in Central


7


Table of Contents

  Appalachian surface thermal coal production, and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.
 
  è  Growing demand for seaborne thermal coal.  Global trade in thermal coal accounted for nearly 70% of all global coal exports in 2011 and is projected to rise from 921 million tons in 2011 to 1.1 billion tons by 2017. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality, and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.
 
Strategy
 
Our primary business strategy is to enhance unitholder value by executing the following strategies:
 
  •  Continue to grow our interest in our coal reserve holdings through additional investments in our existing proven and probable reserves.  We expect that the demand for Illinois Basin coal will rise as a result of an increase in power plants being retrofitted with scrubbers and the construction of new power plants throughout the Illinois Basin market area. Pursuant to the terms of a Royalty Deferment and Option Agreement with our sole lessee, Armstrong Energy, we have the right to acquire additional undivided interests in coal reserves controlled by Armstrong Energy in the event that Armstrong defers cash payment to us for royalties due. We expect that for the foreseeable future all or a substantial portion of our royalty revenues will be used by us to acquire additional coal reserve interests and will not be a source of cash for the payment of dividends or other distributions to our unitholders. Except for distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership, which will be paid, if at all, solely at the discretion of Elk Creek GP, our general partner, we do not anticipate paying any distributions for the foreseeable future.
 
  •  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 eight separate mines, obtained the necessary regulatory permits for the commencement of mining operations at those mines, and developed significant multi-year contractual relationships with large customers in its market area. We believe this resulted from Armstrong Energy’s deep management experience and disciplined approach to the development of its


8


Table of Contents

  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 December 31, 2011, we either owned or had an interest in approximately 205 million tons of clean recoverable (proven and probable) coal reserves. Our reserves represent underground mineable coal, which, in combination with our 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.
 
The following chart depicts the organization and ownership of Armstrong Resource Partners, L.P. prior to giving effect to the offering of common units being made hereby or to the Concurrent AE Offering, but


9


Table of Contents

assuming conversion of our Series A convertible preferred units and conversion of Armstrong Energy’s Series A preferred stock:
 
(FLOW CHART)
 
 
(1) Reserves owned solely by Armstrong Resource Partners. These include the reserves assigned to our Kronos and Lewis Creek underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a 50.81% undivided interest as of March 31, 2012) and Armstrong Energy (with a 49.19% undivided interest as of March 31, 2012). If this offering and the Concurrent AE Offering and related transactions are completed, the undivided interest of Armstrong Resource Partners will increase, and the undivided interest of Armstrong Energy will decrease, based on the net proceeds of this offering paid to Armstrong Energy and the value of the affected reserves as agreed by Armstrong Resource Partners and Armstrong Energy. See “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Energy.”


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 reserves assigned to our Kronos and Lewis Creek underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners and Armstrong Energy. Assuming an offering price of $     per unit, the midpoint of the price range set forth on the front cover page of this prospectus, and an estimated purchase price of $17.5 million for our additional interest in the partially owned reserves, we intend to acquire an additional estimated 8% to 10% partial undivided interest in certain reserves of Armstrong Energy with the net proceeds from this offering. The actual percentage acquired will depend on the fair value of the reserves at the time of the acquisition and the net proceeds received in this offering. In addition, our interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves could be increased as a result of an additional acquisition through the offset of unpaid deferred royalties owed to us.
 
Partnership Information
 
Our principal executive offices are located at 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105 and our telephone number is (314) 721-8202. Our corporate website address is www.armstrongresourcepartners.com. Information on, or accessible through, our website is not part of, or incorporated by reference in, this prospectus. We are organized under the laws of the State of Delaware.
 
Cash Distribution Policy and Restrictions on Dividends
 
Pursuant to our Partnership Agreement, within 45 days following the end of each quarter, we may, in our sole and exclusive discretion, distribute an amount equal to some or all of our available cash to unitholders of record on the applicable record date. The payment of distributions, if any, is solely within the discretion of Elk Creek GP, our general partner.
 
However, the Senior Secured Credit Facility restricts our ability to pay distributions. Under the terms of the Senior Secured Credit Facility, without the consent of all lenders (if there are fewer than three lenders at the time of any dividend or distribution) or the lenders having more than 50% of the aggregate commitments


11


Table of Contents

(if there are three or more lenders at the time of any dividend or distribution) under that facility, we are currently prohibited from making dividend payments or other distributions to our unitholders in excess of $5.0 million per year and $10.0 million in aggregate, except for dividends or other distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership until February 9, 2016, the date on which the Senior Secured Credit Facility matures.
 
Our lessee, Armstrong Energy, has historically deferred the payment to us of cash royalties pursuant to a Royalty Deferment and Option Agreement which it has entered into with us, and we expect that Armstrong Energy will continue to make such deferrals for the foreseeable future. Pursuant to the terms of that Agreement, in the event that Armstrong Energy exercises its deferral right, we have the right to acquire additional undivided interests in coal reserves controlled by Armstrong Energy. We expect that for the foreseeable future all or a substantial portion of our royalty revenues will be used by us to acquire such additional coal reserve interests and will not be a source of cash for the payment of dividends or other distributions to our unitholders.
 
Except for distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership, which will be paid, if at all, solely at the discretion of Elk Creek, GP, our general partner, we do not anticipate paying any distributions for the foreseeable future.
 
Yorktown Partners LLC
 
Yorktown was formed in 1991 and has approximately $3.0 billion in assets under management. Yorktown invests exclusively in the energy industry with an emphasis on North American oil and gas production, coal mining and midstream businesses. 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.


12


Table of Contents

For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner and Armstrong Energy, please read “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”
 
Armstrong Energy will not be in breach of its obligations under the Partnership Agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:
 
  •  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.


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.
 
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.


14


Table of Contents

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.
 
We may not choose to retain separate counsel for ourselves or for the holders of common units.
 
The attorneys, independent auditors and others who have performed services for us in the past were retained by Armstrong Energy, its affiliates and us and have continued to be retained by Armstrong Energy, its affiliates and us. Attorneys, independent auditors and others who perform services for us are selected by Armstrong Energy or the conflicts committee and may also perform services for Armstrong Energy and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between Armstrong Energy and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
 
Elk Creek GP, Armstrong Energy, and their respective affiliates may compete with us.
 
The Partnership Agreement provides that Elk Creek GP, Armstrong Energy, and their respective affiliates will not be prohibited from engaging in activities in which they compete directly with us.
 
Director Independence
 
For a discussion of the independence of the members of the board of directors of Armstrong Energy under applicable standards, please read “Management — Board of Directors and Board Committees.”
 
Review, Approval or Ratification of Transactions with Related Persons
 
If a conflict or potential conflict of interest arises between Armstrong Energy and its affiliates (including our general partner) on the one hand, and our Partnership and our limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under “— Conflicts of Interest.”
 
For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”
 
Emerging Growth Company Status
 
We are an “emerging growth company,” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS


15


Table of Contents

Act”). As such, we are eligible to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), reduced disclosure obligations regarding executive compensation in our periodic reports. We have not made a decision whether to take advantage of these exemptions.
 
In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we are choosing to opt out of any extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.
 
We could remain an “emerging growth company” for up to five years, or until the earliest of (a) the last day of the first fiscal year in which our annual gross revenues exceed $1 billion, (b) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common units that are held by non-affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or (c) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.


16


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.
 
Units to be Outstanding Immediately After this Offering
12,461,977 common units (or 12,561,977 common units if the underwriters exercise in full their over-allotment option) and 38,023 general partner units held by our general partner.
 
Units Held by Our Existing Unitholders Immediately After this Offering
11,461,977 common units (or 11,461,977 common units if the underwriters exercise in full their over-allotment option) and 38,023 general partner units held by our general partner.
 
Use of Proceeds We expect to receive net proceeds from this offering of approximately $17.5 million (or approximately $19.4 million if the underwriters exercise in full their option to purchase additional units) after deducting estimated underwriting discounts and commissions, and after our offering expenses estimated at $1.1 million, assuming the units are offered at $     per unit, which is the midpoint of the estimated offering price range shown on the front cover page of this prospectus. We intend to use the net proceeds from this offering of approximately $17.5 million to purchase an additional partial undivided interest in substantially all of the coal reserves and real property owned by Armstrong Energy previously subject to options exercised by us on February 9, 2011. See “Certain Relationships and Related Party Transactions — Western Diamond and Western Land Coal Reserves Sale Agreement.” See “Use of Proceeds” and “Description of Indebtedness.”
 
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


17


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”
 
Except as otherwise indicated, information in this prospectus reflects or assumes the following:
 
  •  a 7.6047-to-1 unit split of our common units and general partner units to be effected prior to the effectiveness of the registration statement of which this prospectus forms a part;
 
  •  the automatic conversion of all of our outstanding Series A convertible preferred units into an aggregate of 1,068,376 common units which we expect will occur immediately subsequent to the completion of this offering, at an assumed initial public offering price of $     per unit, which is the midpoint of the price range set forth on the cover of this prospectus, as described above; and
 
  •  no exercise of the underwriters’ option to purchase up to an additional      common units.
 
Risk Factors
 
Investing in our common units involves a high degree of risk. You should carefully consider the following risk factors, those other risks described in “Risk Factors,” and the other information in this prospectus, before


18


Table of Contents

deciding whether to invest in our common units. The following risks are discussed in more detail in “Risk Factors” beginning on page 22:
 
  •  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.
 
  •  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.


19


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, 2009, 2010 and 2011 and the balance sheet data as of December 31, 2009, 2010 and 2011 are derived from our audited financial statements included herein. The summary historical financial data for the three months ended March 31, 2012 and 2011 and the balance sheet data as of March 31, 2012 and 2011 are derived from our unaudited financial statements provided herein.
 
Historical results and unaudited pro forma consolidated financial information are for illustrative and informational purposes only and are not necessarily indicative of results we expect in future periods. You should read the following summary with “Selected Historical Consolidated Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our financial statements and related notes appearing elsewhere in this prospectus.
 
                                         
          Three Months
 
    Year Ended December 31,     Ended March 31,  
    2009     2010     2011     2011     2012  
                      (Unaudited)     (Unaudited)  
    (In thousands, except per unit amounts)  
 
Results of Operations Data
                                       
Total revenue
  $     $     $ 7,789     $ 1,238     $ 3,081  
Costs and expenses
    330       817       7,605       802       4,717  
                                         
Operating income (loss)
    (330 )     (817 )     184       436       (1,636 )
Interest expense
    (1,723 )                        
Interest income
    161       4,209       1,009       1,009        
Other income (expense), net
    (2 )     (60 )     1,148       162       256  
                                         
Net income (loss)
  $ (1,894 )   $ 3,332     $ 2,341     $ 1,607     $ (1,380 )
                                         
Earnings (loss) per limited partner unit, basic, without giving effect to the unit split
  $ (2.62 )   $ 2.96     $ 1.74     $ 1.20     $ (1.02 )
                                         
Earnings (loss) per limited partner unit, diluted, without giving effect to the unit split
  $ (2.62 )   $ 2.96     $ 1.73     $ 1.20     $ (1.02 )
                                         
Earnings (loss) per limited partner unit, basic and diluted, assuming unit split(1)
  $ (0.34 )   $ 0.39     $ 0.23     $ 1.60     $ (0.13 )
                                         
Balance Sheet Data (at period end)
                                       
Total assets
  $ 91,097     $ 137,929     $ 167,559     $ 144,623     $ 166,037  
Working capital
    215       155       619       155       651  
Total debt
                             
Total partners’ capital
    89,497       125,929       156,181       132,536       155,278  
Other Data
                                       
Royalty coal tons sold by lessee (unaudited)
                2,717       458       1,012  
Net cash provided by (used in):
                                       
Operating activities
  $ (308 )   $ 13,792     $ 8,007     $ 2,221     $ 2,095  
Investing activities
    (12,424 )     (46,892 )     (33,007 )     (7,221 )     339  
Financing activities
    12,722       33,100       25,000       5,000       (2,434 )
EBITDA (unaudited)(2)
    (332 )     (877 )     8,084       1,212       3,086  
EBITDA is calculated as follows (unaudited):
                                       
Net income (loss)
  $ (1,894 )   $ 3,332     $ 2,341     $ 1,607     $ (1,380 )
Depletion
                3,841       614       1,555  
Unit-based compensation expense
                2,911             2,911  
Interest, net
    1,562       (4,209 )     (1,009 )     (1,009 )      
                                         
    $ (332 )   $ (877 )   $ 8,084     $ 1,212     $ 3,086  
                                         


20


Table of Contents

 
(1) Per unit calculation reflects the assumed 7.6047-to-1 unit split to be effected prior to the effectiveness of the registration statement of which this prospectus forms a part.
 
(2) EBITDA is a non-GAAP financial measure, and when analyzing our operating performance, investors should use EBITDA in addition to, and not as an alternative for, operating income and net income (loss) (each as determined in accordance with GAAP). We use EBITDA as a supplemental financial measure. EBITDA is defined as net income (loss) before interest, net, unit compensation expense and depletion.
 
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.


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 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 a substantial majority of our coal to domestic electric power generators, and it has multi-year coal supply agreements in place with electric power generators for a significant portion of its future production. The amount of coal consumed by electric power generation is affected by, among other things:
 
  •  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 decreased by 0.6% during 2011 compared with 2010, and U.S. electric generation from coal decreased by 5.5% in 2011 compared with 2010. However, decreases in the demand for electricity could take place in the future, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession, or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.
 
Changes in the coal industry that affect our 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 2011, a substantial majority of the tons of coal sold by our lessee were to domestic electric power generators. The amount of coal consumed for U.S. electric power generation is affected by, among other things:
 
  •  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 to construct and permits to construct these plants are easier to obtain, as natural gas-fired plants are seen as having a lower environmental impact than coal-fired plants. Current developments in natural gas production processes have


25


Table of Contents

lowered the cost and increased the supply, resulting in greater use of natural gas for electricity generation. According to the EIA, total electricity generation in the United States decreased by 0.5% during 2011 compared with 2010, and U.S. electric generation from coal decreased by 6.1% in 2011 compared with 2010 and is expected to decreased by a further 10% in 2012. While the EIA projects that electricity generation will grow at an annual average rate of 0.8% through 2035, it projects that the percentage of electricity generated from coal will decrease to 39% of total generation by 2035, compared with 42% during 2011.
 
The EIA projects coal-fueled electric power generation to decline in 2012, primarily driven by depressed near-term natural gas prices that are resulting in elevated levels of coal-to-gas switching. If coal-to-gas switching lasts for a prolonged period during 2012 due to significantly depressed natural gas prices, there may be more substantial unfavorable impacts to all coal supply regions. Recent mild weather and weaker international and domestic economies have also negatively impacted coal markets. All of the foregoing could reduce demand for our lessee’s coal, which could reduce the price of coal that our lessee mines and sells from our reserves, thereby reducing our royalty revenues and materially and adversely affecting our business and results of operations.
 
In addition, state and federal mandates for increased use of electricity from renewable energy sources could have an adverse impact on the market for our coal. Many states have mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national energy portfolio standard in the U.S., although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by domestic electric power generators could reduce the price of coal that our lessee mines and sells from our reserves, thereby reducing our royalty revenues and materially and adversely affecting our business and results of operations.
 
Inaccuracies in our estimates of our coal reserves could materially adversely affect the quantities and value of our reserves.
 
Our estimates of our reserves may vary substantially from the actual amounts of coal that our lessee may be able to economically recover. The estimates of our reserves are based on engineering, economic, and geological data assembled, analyzed, and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves periodically to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired, and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:
 
  •  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.


26


Table of Contents

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, 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


27


Table of Contents

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 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, 2011, our lessee derived approximately 63% of its total coal revenues from sales to its two largest customers — Louisville Gas and Electric (“LGE”) and Tennessee Valley Authority (“TVA”). For the fiscal year ended December 31, 2011, coal sales to LGE and TVA constituted approximately 35% and 28% of our lessee’s total coal revenues, respectively. Our lessee’s multi-year coal supply agreements with LGE expire in 2015 and 2016, and its multi-year coal supply agreements with TVA expire in 2013 and 2018; however, most of its multi-year coal supply agreements with LGE and TVA contain re-opener provisions pursuant to which either party can request re-opening to renegotiate price and other terms for the remaining term of such agreement, and, subsequent to any such re-opening, the failure to reach an agreement can lead to the termination of such agreement. In addition, one of our 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 LGE or TVA are terminated early pursuant to the re-opener provisions, or our lessee fails to extend or renew its arrangements with LGE or TVA, our coal royalty revenues could be negatively impacted.
 
If our lessee’s multi-year coal supply agreements with LGE or TVA are terminated or if our lessee fails to extend or renew its multi-year coal supply agreements with LGE or TVA, our lessee may be unable to timely replace such agreements. In such a case, our coal royalty revenues could be materially and adversely affected.
 
Our lessee could satisfy obligations to its customers with coal from properties other than ours, depriving us of the ability to receive royalty payments.
 
We do not control our 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


28


Table of Contents

affairs, notwithstanding that our business may be adversely affected if the officers spend less time on our business and affairs than would otherwise be available as a result of such officers’ time being split between the management of Armstrong Energy and of Armstrong Resource Partners.
 
Our 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, which could adversely affect the stability of our lessee’s production and materially reduce our profitability.
 
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


29


Table of Contents

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.
 
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 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.


31


Table of Contents

We are not permitted to borrow additional funds under the Senior Secured Credit Facility and as such, it is not a source of liquidity for us.
 
We will not be required by Section 404 of the Sarbanes-Oxley Act to evaluate the effectiveness of our internal controls until the year following our first annual report and our independent registered public accounting firm is not required to formally attest to the effectiveness of our internal controls while we qualify as an “emerging growth company”. We have identified internal control deficiencies, including material weaknesses, in the past, which have been remediated. If we are unable to establish and maintain effective internal controls, our financial condition and operating results could be adversely affected.
 
We are not currently required to comply with the SEC rules that implement Sections 302 and 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with certain of these rules, which will require management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. Additionally, our independent registered public accounting firm is not required to formally attest to the effectiveness of our internal control over financial reporting until we are no longer an “emerging growth company” as defined in the JOBS Act. At such time, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Further, we may take advantage of other accounting and disclosure related exemptions afforded to “emerging growth companies” from time to time.
 
Under applicable SEC and Public Company Accounting Oversight Board rules and regulations, a “material weakness” is a deficiency or combination of deficiencies in internal controls over financial reports that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. We have identified deficiencies constituting a “material weakness” in our internal control over financial reporting, including in connection with the financial statement close process for the year ended December 31, 2011, in which we identified an error in our calculation of depletion. Although we believe this material weakness has been remediated, if we are unable to appropriately maintain the remediation plan we have implemented and maintain any other necessary controls we implement in the future, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our common unit price may be adversely affected.
 
Risks Related to Environmental, Other Regulations and Legislation
 
New regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could adversely affect our coal royalty revenue stream.
 
One major by-product of burning coal is carbon dioxide (“CO2”), which is a greenhouse gas and a source of concern with respect to global warming, also known as Climate Change. Climate Change continues to attract government, public, and scientific attention, especially on ways to reduce greenhouse gas emissions, including from coal-fired power plants. Various international, federal, regional, and state proposals are being considered to limit emissions of greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may establish a cap-and-trade regime, and regulation under existing environmental laws by the EPA and other regulatory agencies. Future regulation of greenhouse gas emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers and may restrict the construction of new coal-fired power plants.
 
On March 27, 2012, the EPA released its proposed rule that would establish, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired


32


Table of Contents

electric utility generating power plants. The proposed rule would require new plants greater than 25 megawatts to meet an output based standard of 1000 pounds of CO2 per megawatt hour, based on the performance of natural gas combined cycle technology. New coal-fired power plants could meet the standard either by employing carbon capture and storage technology at start up or through later application of such technologies provided that the aforementioned output standard was met on average over a 30-year period. Public comments concerning the proposed rule have been solicited for submission within 60 days after the publication of the proposed rule, and future public hearings will be scheduled to discuss the proposal. If adopted, the proposed rule could negatively impact the price of coal such that it would be less attractive to utilities and ratepayers. Moreover, there is currently no large-scale use of carbon capture and storage technologies in domestic coal-fired power plants, and as a result, there is a risk that such technology may not be commercially practical in limiting emissions as otherwise required by the proposed rule.
 
The permitting of new coal-fired power plants has also recently been contested by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions. In addition, a federal appeals court has allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, although the U.S. Supreme Court has since held that federal common law provides no basis for such claims. Future regulation, litigation, and permitting related to greenhouse gas emissions may cause some users of coal to switch from coal to a lower-carbon fuel, or otherwise reduce the use of and demand for fossil fuels, particularly coal, which could have a material adverse effect on our royalty revenues. See “Business — Regulation and Laws — Climate Change.”
 
Extensive environmental requirements, including existing and potential future requirements relating to air emissions, affect our 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.


33


Table of Contents

See “Business — Regulation and Laws” for more information about the various governmental regulations affecting us.
 
Legal requirements that we expect to significantly expand scrubbed coal-fired electricity generating capacity may be overturned or not enacted at all, which could result in less demand for Illinois Basin coal than we anticipate and materially and adversely affect our royalty payments.
 
Although a number of legal requirements have been or are in the process of being implemented that are expected to expand significantly the scrubbed coal-fired electricity generating capacity in the U.S., regulations driving this trend are subject to legal challenge, and could also be the subject of future legislation that withdraws any authorization for such requirements. For example, the recently finalized Cross-State Air Pollution Rule (“CSAPR”) has been challenged in court by a number of southern and Midwestern states and several energy companies. In December 2011, the U.S. Court of Appeals for the District of Columbia issued a ruling to stay the CSAPR pending judicial review. The outcome of such legal proceedings, and other possible developments including, for example, changes in presidential administration and the administration of the EPA, or the enactment by Congress of more lenient air pollution laws than are currently in effect, could result in significantly less expansion of scrubbed coal-fired electricity generating capacity than we anticipate. This in turn could mean that the strong increase in demand for relatively high-sulfur Illinois Basin coal we believe will occur in the future may not materialize, or may not materialize as soon as it otherwise would. This could adversely affect the demand for our 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.”


34


Table of Contents

Section 404(q) of the CWA establishes a requirement that the Secretary of the Army and the Administrator of the EPA enter into an agreement assuring that delays in the issuance of permits under Section 404 are minimized. In August 1992, the Department of the Army and the EPA entered into such an agreement. The 1992 Section 404(q) Memorandum of Agreement (“MOA”) outlines the current process and time frames for resolving disputes in an effort to issue timely permit decisions. Under this MOA, the EPA may request that certain permit applications receive a higher level of review within the Department of Army. In these cases, the EPA determines that issuance of the permit will result in unacceptable adverse effects to Aquatic Resources of National Importance (“ARNI”). Alternately, the EPA may raise concerns over Section 404 program policies and procedures. An ARNI is a resource-based threshold used to determine whether a dispute between the EPA and the Corps regarding individual permit cases are eligible for elevation under the MOA. Factors used in identifying ARNIs include the economic importance of the aquatic resource, rarity or uniqueness, and/or importance of the aquatic resource to the protection, maintenance, or enhancement of the quality of the waters.
 
Federal or state regulatory agencies have the authority to order certain of our 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 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


35


Table of Contents

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;
 
  •  taxation requirements; and
 
  •  competition laws.


36


Table of Contents

 
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.”
 
Risks Related to This Offering and Our Common Units
 
An active, liquid trading market for our common units may not develop.
 
Prior to this offering, there has not been a public market for our common units. We cannot predict the extent to which investor interest in us will lead to the development of a trading market on Nasdaq or


37


Table of Contents

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.
 
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.”


38


Table of Contents

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 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


39


Table of Contents

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 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


40


Table of Contents

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 11,273,874 common units, which represents approximately 90.5% of our outstanding common units (or 89.8% if the underwriters exercise their option to purchase additional units in full). As a result, Yorktown will retain the ability to direct and control our business affairs. Yorktown will have influence over our decisions to enter into any corporate transaction regardless of whether others believe that the transaction is in our best interests.
 
Yorktown is also in the business of making investments in companies and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. Yorktown may also pursue acquisition opportunities that are complementary to our business, and, as a result, those acquisition opportunities may not be available to us. As long as Yorktown, or other funds controlled by or associated with Yorktown, continue to indirectly own a significant amount of our outstanding common units, Yorktown will continue to be able to strongly influence or effectively control our decisions. The concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive unitholders of an opportunity to receive a premium for their common units as part of a sale of our company and might ultimately affect the market price of our common units.
 
We will incur increased costs as a result of being a public company.
 
As a privately held company, we have not been responsible for the corporate governance and financial reporting practices and policies required of a publicly traded company. Following the effectiveness of the registration statement of which this prospectus is a part, we will be a public company. As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the Securities and Exchange Commission (the “SEC”) and the requirements of Nasdaq or other stock exchange on which our common units are listed, with which we are not required to comply as a private company. Under the current rules of the SEC, beginning with fiscal 2013, we must perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. Beginning with fiscal 2018, or such earlier time as we are no longer an “emerging growth company” as defined in the JOBS Act, our independent registered public accounting firm also will be required to report on our internal control over financial reporting. We will need to:
 
  •  institute a more comprehensive compliance function;
 
  •  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;


41


Table of Contents

 
  •  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.
 
Complying with these statutes, regulations and requirements will occupy a significant amount of time of the officers and directors of Armstrong Energy who manage us and will significantly increase our costs and expenses. In addition, we could be required to expend significant management time and financial resources to correct any material weaknesses in our internal control over financial reporting that may be identified.
 
We are an emerging growth company within the meaning of the JOBS Act, and if we decide to take advantage of certain exemptions from various reporting requirements applicable to emerging growth companies, our common units could be less attractive to investors.
 
We are an “emerging growth company” within the meaning of the JOBS Act. We are eligible to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including, but not limited to, reduced disclosure about our executive compensation and omission of compensation discussion and analysis. In addition, we will not be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act, including the additional level of review of our internal control over financial reporting as may occur when outside auditors attest as to our internal control over financial reporting. As a result, our unitholders may not have access to certain information they may deem important. We will remain an emerging growth company for up to five years, though we may cease to be an emerging growth company earlier under certain circumstances. If we take advantage of any of these exemptions, we do not know if some investors will find our common units less attractive as a result. The result may be a less active trading market for our common units and the market price of our common units may be more volatile.
 
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common units, or if our operating results do not meet their expectations, the price and trading volume of our common units could decline.
 
The trading market for our common units will be influenced by the research and reports that securities or industry analysts publish about us or our business. Securities analysts may elect not to provide research coverage of our common units. This lack of research coverage could adversely affect the price of our common units. We do not have any control over these reports or analysts. If any of the analysts who cover us downgrades our common units, or if our operating results do not meet the analysts’ expectations, our common unit price could decline. Moreover, if any of these analysts ceases coverage of us or fails to publish regular reports on our business, we could lose visibility in the market, which in turn could cause our common unit price and trading volume to decline and our common units to be less liquid.
 
You will incur immediate dilution in the book value of your common units as a result of this offering.
 
The initial public offering price of our common units is considerably more than the as adjusted, net tangible book value per outstanding unit. This reduction in the value of your equity is known as dilution. This dilution occurs in large part because our earlier investors paid substantially less than the initial public offering price when they purchased their common units. Investors purchasing common units in this offering will incur immediate dilution of $6.18 in as adjusted, net tangible book value per unit, based on the assumed initial public offering price of $      per unit, which is the midpoint of the price range listed on the front cover page of this prospectus. In addition, following this offering, purchasers in the offering will have contributed 12.9% of the total consideration paid by our unitholders to purchase common units. For a further description of the dilution that you will experience immediately after this offering, see “Dilution.” In addition, if we raise funds by issuing additional securities, the newly-issued common units will further dilute your percentage ownership of us.


42


Table of Contents

Our general partner may not be able to organize and effectively manage a publicly traded operating company, which could adversely affect our overall financial position.
 
Some of the senior executive officers or directors who will manage our lessee and us, through our general partner, have not previously organized or managed a publicly traded company, and those senior executive officers and directors may not be successful in doing so. The demands of organizing and managing a publicly traded company are much greater as compared to a private company and some of these senior executive officers and directors may not be able to meet those increased demands. Failure to organize and effectively manage us or our lessee could adversely affect our overall financial position or royalties.
 
Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.
 
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of Armstrong Energy, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner. See “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”
 
Unitholders other than Yorktown may not remove our general partner even if they wish to do so.
 
Armstrong Energy, Inc., the parent corporation of our general partner, manages and operates us. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business. Unitholders have no right to elect our general partner or the directors of Armstrong Energy on an annual or any other basis.
 
Furthermore, if unitholders other than Yorktown are dissatisfied with the performance of our general partner, they currently have no practical ability to remove our general partner or otherwise change its management. Yorktown unilaterally may remove our general partner in some circumstances. Unitholders other than Yorktown have no right to remove our general partner.
 
In addition, the following provisions of our Partnership Agreement may discourage a person or group from attempting to change our management:
 
  •  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;


43


Table of Contents

 
  •  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 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.


44


Table of Contents

 
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.
 
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,


45


Table of Contents

which, if enacted, may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. Further, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you.
 
Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
 
Because you will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
 
Certain United States federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.
 
Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2013 (the “Budget Proposal”) is the elimination of certain key federal income tax preferences relating to coal exploration and development. The Budget Proposal would (i) eliminate current deductions and the 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties, and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in federal income tax laws could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.
 
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the 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


46


Table of Contents

of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture and depreciation recapture. In addition, because the amount realized includes your share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. See “Material United Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.
 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, all or a substantial portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
 
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and to maintain the uniformity of the economic and tax characteristics of our common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. See “Material Tax Consequences — Tax Consequences of Common Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.
 
We prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.
 
We will prorate our items of income, gain, loss, and deduction for federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we might be required to change the allocation of items of income, gain, loss, and deduction among our unitholders. See “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”


47


Table of Contents

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, it would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, it may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss, or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
 
We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss, and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional common units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss, and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss, and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our Partnership for federal income tax purposes.
 
We will be considered to have technically terminated our Partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief is not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if


48


Table of Contents

we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that is technically terminated requests special relief and such relief is granted by the IRS, among other things, the partnership will have to provide only one Schedule K-1 to unitholders for the tax year in which the termination occurs notwithstanding two partnership tax years. See “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.
 
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
 
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Kentucky, which currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state, and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.


49


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;


50


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; and
 
  •  the other factors affecting our business described below under the caption “Risk Factors.”


51


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 $17.5 million, at an assumed initial public offering price of $     per unit, the midpoint of the price range set forth on the cover of this prospectus, and after deducting estimated underwriting discounts and commissions and offering expenses. Our net proceeds will increase by approximately $1.9 million if the underwriters’ option to purchase additional units is exercised in full. Each $1.00 increase (decrease) in the assumed initial public offering price of $     per unit, the midpoint of the price range set forth on the cover of this prospectus, would increase (decrease) the net proceeds to us of this offering by $0.9 million, or $1.0 million if the underwriters’ option is exercised in full, assuming the number of units offered by us, as set forth on the cover of this prospectus, remains the same and after deducting estimated underwriting discounts and commissions and offering expenses.
 
We intend to use the net proceeds from this offering to purchase an additional estimated 8% to 10% partial undivided interest in substantially all of the coal reserves and real property owned by Armstrong Energy previously subject to options exercised by us on February 9, 2011. As of March 31, 2012, we had a 50.81% interest in such reserves. The actual percentage acquired will depend on the fair value of the reserves at the time of acquisition. See “Certain Relationships and Related Party Transactions — Western Diamond and Western Land Coal Reserves Sale Agreement.” Armstrong Energy intends to use the proceeds of the sale of the partial undivided interest to us to repay a portion of Armstrong Energy’s outstanding borrowings under the Senior Secured Revolving Credit Facility.


52


Table of Contents

 
CAPITALIZATION
 
The following table shows:
 
  •  Our capitalization as of March 31, 2012; and
 
  •  Our pro forma capitalization as of December 31, 2011, as adjusted to reflect the net proceeds from this offering of common units at an assumed public offering price of $     per unit (the midpoint of the range set forth on the front cover page of this prospectus), after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Selected Historical Consolidated Financial and Operating Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                 
    As of March 31, 2012
        As
    Actual   Adjusted(1)(2)(3)
    (unaudited)
    (In thousands)
 
Cash and cash equivalents
  $ 155     $ 17,655  
                 
Total long-term debt
  $     $  
Partners’ capital:
               
Series A preferred units
    20,000        
Common unitholders
    134,877       172,377  
General partner
    401       401  
                 
Total partners’ capital
    155,278       172,778  
                 
Total capitalization
  $ 155,278     $ 172,778  
                 
 
 
(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 $0.9 million, after deducting the underwriting discount and estimated offering expenses payable by us. We may also increase or decrease the number of units we are offering. Each increase of 0.1 million units offered by us, together with a concomitant $1.00 increase in the assumed offering price to $     per unit, would increase total partners’ capital and total capitalization by approximately $2.9 million. Similarly, each decrease of 0.1 million units offered by us, together with a concomitant $1.00 decrease in the assumed offering price to $     per unit, would decrease total partners’ capital and total capitalization by approximately $2.7 million. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.
(2) Reflects the conversion of the outstanding Series A convertible preferred units as a result of the consummation of this offering into 1,068,376 common units based on an assumed initial public offering price of $     per unit (the midpoint of the range on the cover of this prospectus).
(3) Does not reflect the expected acquisition of an additional estimated 8% to 10% partial undivided interest in certain reserves of Armstrong Energy with the net proceeds from this offering. See “Use of Proceeds.”


53


Table of Contents

 
DILUTION
 
Dilution is the amount by which the offering price paid by the purchasers of units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2012, after giving effect to the offering of common units, the conversion of our Series A convertible preferred units into 1,068,376 common units, and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $172.8 million, or $13.82 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:
 
                 
Assumed initial public offering price per common unit
          $        
                 
Net tangible book value per unit before the offering(1)
          $ 14.89  
                 
Decrease in net tangible book value per unit attributable to purchasers in the offering
            (1.07 )
                 
Less: Pro forma net tangible book value per unit after the offering(2)
            13.82  
                 
Immediate dilution in tangible net book value per unit to purchasers in the offering(3)
          $ 6.18  
                 
 
 
(1) Determined by dividing the sum of the 38,023 general partner units and the 10,393,601 common units held by its affiliates, into the net tangible book value of our assets.
 
(2) Determined by dividing the total number of units to be outstanding after this offering (12,461,977 common units and 38,023 general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of this offering.
 
(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 $13.90 and $13.75, respectively.
 
The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:
 
                                 
    Units Acquired     Total Consideration  
 
  Number     Percent     Amount     Percent  
    (In thousands)  
 
General partner and affiliates(1)(2)
    11,500       92.0 %   $ 134,700       87.1 %
Purchasers in the offering
    1,000       8.0       20,000       12.9  
                                 
Total
    12,500       100.0 %   $ 154,700       100.0 %
                                 
 
 
(1) Includes 38,023 general partner units acquired by our general partner and 11,461,977 common units held by its affiliates.
 
(2) Assumes the underwriters’ option to purchase additional common units is not exercised.


54


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 the sole and exclusive discretion of Elk Creek GP, our general partner, distribute an amount equal to some or all of our available cash with respect to such quarter, subject to Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), pro rata to the partners as of the record date selected by our general partner in its reasonable discretion. All distributions required under the Partnership Agreement shall be made subject to Section 17-607 of the Delaware Act, and the Partnership shall not be required to distribute any portion of available cash at any time, except as may be directed in the sole discretion of our general partner.
 
Definition of Available Cash.  Available cash generally means, for each fiscal quarter ending prior to our liquidation date:
 
  •  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 to (i) provide for the proper conduct of the business of our Partnership and our subsidiaries (including reserves for future capital expenditures and for anticipated future credit needs of our Partnership and our subsidiaries) subsequent to such quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or it is bound or our or its assets are subject or (iii) provide funds for further distributions; provided, however, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of such quarter but on or before the date of determination of available cash with respect to such quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within such quarter if our general partner so determines.
 
  •  Notwithstanding the foregoing, available cash with respect to the quarter in which our liquidation date occurs and any subsequent quarter shall equal zero.
 
Restrictions under the Senior Secured Credit Facility and the Royalty Deferment and Option Agreement.  The Senior Secured Credit Facility restricts our ability to pay distributions. Under the terms of the Senior Secured Credit Facility, without the consent of all lenders (if there are fewer than three lenders at the time of any dividend or distribution) or the lenders having more than 50% of the aggregate commitments (if there are three or more lenders at the time of any dividend or distribution) under that facility, we are currently prohibited from making dividend payments or other distributions to holders of our partnership interests in excess of $5.0 million per year and $10.0 million in aggregate, except for dividends or other distributions in amounts necessary to enable holders of our partnership interests to pay anticipated income tax liabilities arising from their ownership interests in the Partnership until February 9, 2016, the date on which the Senior Secured Credit Facility matures.
 
Our lessee, Armstrong Energy, has historically deferred the payment to us of cash royalties pursuant to a Royalty Deferment and Option Agreement which it has entered into with us, and we expect that Armstrong Energy will continue to make such deferrals for the foreseeable future. Pursuant to the terms of that Agreement, in the event that Armstrong Energy exercises its deferral right, we have the right to acquire additional undivided interests in coal reserves controlled by Armstrong Energy. We expect that for the foreseeable future all or a substantial portion of our royalty revenues will be used by us to acquire such additional coal reserve interests and will not be a source of cash for the payment of dividends or other distributions to our limited partners.


55


Table of Contents

Except for distributions in amounts necessary to enable limited partners to pay anticipated income tax liabilities arising from their ownership interests in the Partnership, which will be paid, if at all, solely at the discretion of our general partner we do not anticipate paying any distributions for the foreseeable future.
 
Distributions of Cash Upon Liquidation
 
If we dissolve in accordance with our Partnership Agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. In the event of the dissolution and liquidation of the Partnership, all receipts received during or after the quarter in which the liquidation date occurs, other than from certain working capital borrowings, shall be applied and distributed solely in accordance with, and subject to the following terms and conditions.
 
The liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as the liquidator determines to be in the best interest of the partners, subject to Section 17-804 of the Delaware Act and the following:
 
  •  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 period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).


56


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, 2010 and 2011 and the balance sheet data as of December 31, 2008, 2009, 2010 and 2011 are derived from the audited financial statements appearing elsewhere in this prospectus. The selected historical financial data for the three months ended March 31, 2012 and 2011 and the balance sheet data as of March 31, 2012 and 2011 are derived from the unaudited financial statements appearing elsewhere in this prospectus. Historical results are not necessarily indicative of results we expect in future periods. You should read the following summary financial data in conjunction with “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,     Three Months Ended March 31,  
    2008     2009     2010     2011     2011     2012  
                            Unaudited     Unaudited  
    (In thousands, except per unit amounts)  
 
Results of Operations Data
                                               
Total revenues
  $     $     $     $ 7,789     $ 1,238     $ 3,081  
Costs and expenses
    332       330       817       7,605       802       4,717  
                                                 
Operating income (loss)
    (332 )     (330 )     (817 )     184       436       (1,636 )
Interest expense
    (4,877 )     (1,723 )                        
Interest income
          161       4,209       1,009       1,009        
Other income (expense), net
          (2 )     (60 )     1,148       162       256  
                                                 
Net income (loss)
  $ (5,209 )   $ (1,894 )   $ 3,332     $ 2,341     $ 1,607     $ (1,380 )
                                                 
Earnings (loss) per limited partner unit, basic, without giving effect to the unit split
  $ (19.79 )   $ (2.62 )   $ 2.96     $ 1.74     $ 1.20     $ (1.02 )
                                                 
Earnings (loss) per limited partner unit, diluted, without giving effect to the unit split
  $ (19.79 )   $ (2.62 )   $ 2.96     $ 1.73     $ 1.20     $ (1.02 )
                                                 
Earnings (loss) per limited partner unit, basic and diluted, assuming unit split(1)
  $ (2.60 )   $ (0.34 )   $ 0.39     $ 0.23     $ 0.16     $ (0.13 )
                                                 
Balance Sheet Data (at period end)
                                               
Total assets
  $ 78,683     $ 91,097     $ 137,929     $ 167,559     $ 144,623     $ 166,037  
Working capital
    (28,667 )     215       155       619       155       651  
Total partners’ capital
    49,791       89,497       125,929       156,181       132,536       155,278  
Other Data
                                               
Royalty coal tons produced by lessee (unaudited)
                      2,717       458       1,012  
Net cash provided by (used in):
                                               
Operating activities
  $ (5,255 )   $ (308 )   $ 13,792     $ 8,007     $ 2,221     $ 2,095  
Investing activities
    (24,458 )     (12,424 )     (46,892 )     (33,007 )     (7,221 )     339  
Financing activities
    29,878       12,722       33,100       25,000       5,000       (2,434 )
EBITDA (unaudited)(2)
    (332 )     (332 )     (877 )     8,084       1,212       3,086  
EBITDA is calculated as follows (unaudited):
                                               
Net income (loss)
  $ (5,209 )   $ (1,894 )   $ 3,332     $ 2,341     $ 1,607     $ (1,380 )
Depletion
                      3,841       614       1,555  
Unit-based compensation expense
                      2,911             2,911  
Interest, net
    4,877       1,562       (4,209 )     (1,009 )     (1,009 )      
                                                 
    $ (332 )   $ (332 )   $ (877 )   $ 8,084     $ 1,212     $ 3,086  
                                                 
 
 
(1) Per unit calculation reflects the assumed 7.6047-to-1 unit split to be effected prior the effectiveness of the registration statement of which this prospectus forms a part.


57


Table of Contents

 
(2) EBITDA is a non-GAAP financial measure, and when analyzing our operating performance, investors should use EBITDA in addition to, and not as an alternative for, operating income and net income (loss) (each as determined in accordance with GAAP). We use EBITDA as a supplemental financial measure. EBITDA is defined as net income (loss) before interest, net, unit compensation expense and depletion.
 
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.


58


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.
 
Overview
 
We are a limited partnership formed in 2008 to engage in the business of management and leasing of coal properties and collection of royalties in the Western Kentucky region of the Illinois Basin. As of March 31, 2012, we wholly own approximately 65 million tons of coal reserves and have a 50.81% undivided interest in approximately 140 million tons of coal reserves, all located in Ohio and Muhlenberg counties in Western Kentucky. Our coal is generally low chlorine, high sulfur coal. Our outstanding limited partnership interests (“common units”), representing 99.7% of our equity interests, are owned by investment funds managed by Yorktown Partners LLC (collectively, “Yorktown”). We are not engaged in the permitting, production or sale of coal, nor in the operation or reclamation of coal mining activity. We are a fee mineral and surface rights owning entity. It is our intention to remain a coal leasing enterprise and not to engage in coal production ourselves.
 
We currently lease all of our reserves to Armstrong Energy in exchange for royalty payments in the amount of 7% of the revenue received from coal sold from those reserves. Armstrong Energy is a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin with both surface and underground mines. A subsidiary of Armstrong Energy, Inc., Elk Creek GP, is our general partner. Pursuant to our Partnership Agreement, Elk Creek GP has the exclusive authority to conduct, direct and manage all of our activities. By virtue of Armstrong 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 2011 and the three months ended March 31, 2012. Armstrong Energy is obligated to pay us $7.2 million and $2.1 million, respectively, for production royalties under our leases for such period. In addition, we earned a credit and collateral support fee as a result of our financing activities in the amount of $1.15 million and $0.3 million in 2011 and the three months ended March 31, 2012, respectively.
 
Factors that Impact Our Business
 
Our lessee sells the majority of our coal under multi-year coal supply agreements. Our lessee intends to continue to enter into multi-year coal supply agreements for a substantial portion of their annual coal production, using their remaining production to take advantage of market opportunities as they present themselves. We believe their use of multi-year coal supply agreements reduces their exposure to fluctuations in the spot price for coal and provides us with a reliable and stable revenue base with which to earn royalties. Using multi-year coal supply agreements also allows them to partially mitigate their exposure to rising costs, to the extent those contracts have full or partial cost pass through provisions or inflation adjustment provisions. For example, their contracts with LGE contain provisions that adjust the price paid for their coal in the event there is change in the price of diesel fuel, a key cost component in our coal production. Certain of their other contracts, such as those with TVA, contain provisions that permit them to seek additional price adjustments to account for changes in environmental and other laws and regulations to which they are subject, to the extent those changes increase the cost of their production of coal.


59


Table of Contents

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 2011 decreased by approximately 42 million tons, or 4.0%, from 2010 levels. The decline in U.S. domestic coal consumption during 2011 and early 2012 was partially a function of the switching to other sources of fuel. However, according to the EIA, coal is expected to remain the dominant energy source for electric power generation for the foreseeable future. Please read “The Coal Industry— Recent Trends” and “ — Coal Consumption and Demand” for the recent trends and economic factors affecting the coal industry.
 
Related Party Transactions
 
Elk Creek GP, a subsidiary of Armstrong Energy, is our general partner and owns a 0.3% equity interest in us. Elk Creek GP does not receive any management fee or other compensation for its management of the Partnership. However, in accordance with the partnership agreement, we reimburse Elk Creek GP for expenses incurred on our behalf. All direct operating, general and administrative expenses are charged to us as incurred. We also reimburse indirect general and administrative costs, including certain legal, accounting, and other professional services incurred by Elk Creek GP.
 
Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011
 
Revenue
 
Revenue for the three months ended March 31, 2012 totaled $3.1 million, as compared to $1.2 for the same period of 2011. We began earning revenue under our leases to Armstrong Energy in February 2011, resulting in a full quarter earned in 2012, compared to a partial quarter in the prior year. Total tons sold by Armstrong Energy during the three months ended March 31, 2012 that generated royalty revenues was approximately 1.0 million tons, resulting in average royalty revenue per ton of $3.04 compared to 0.5 million tons and an average royalty per ton of $2.70 for the same period in 2011.


60


Table of Contents

Related Party Service Expense
 
Related party service expense of $0.2 million for the three months ended March 31, 2012 is consistent with that incurred in the same period of 2011. Amount relates to general administrative and management services provided by Armstrong Energy on our behalf.
 
Depletion Expense
 
Depletion expense was $1.6 million for the three months ended March 31, 2011, as compared to $0.6 million for the same period of the prior year. The increase is due to additional production in 2012 under our leases to Armstrong Energy.
 
Unit-Based Compensation Expense
 
Unit-based compensation expense was $2.9 million for the three months ended March 31, 2012 compared to zero for the same period in 2011. This expense relates to restricted unit grants made in the fourth quarter of 2011 that vested on March 31, 2012. The fair value of the grants was $5.8 million, which was recognized ratably over the vesting period.
 
Interest Income
 
Interest income decreased $1.0 million to zero for the three months ended March 31, 2012. The decrease is due to the conversion in February 2011 of amounts owed to us by Armstrong Energy into an undivided interest in certain mineral reserves and land of Armstrong Energy.
 
Other Income
 
Other income totaled $0.3 million for the three months ended March 31, 2012, as compared to $0.2 million for the same period of 2011. On February 9, 2011, Armstrong Energy entered into a new credit agreement, whereby we agreed to be a co-borrower with respect to the Senior Secured Term Loan and pledged our assets as collateral and became a guarantor with respect to the Senior Secured Revolving Credit Facility and the Senior Secured Term Loan. In exchange, Armstrong Energy has agreed to pay us a credit support fee equal to 1% of the weighted average outstanding balance under the credit agreement, which can be as much as $150.0 million. As of March 31, 2012, the principal amount outstanding under the credit agreement was $120.0 million and the credit support fee paid for the three months ended March 31, 2012 and 2011 totaled $0.3 million and $0.1 million, respectively.
 
Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010
 
Revenue
 
Revenue for the year ended December 31, 2011 totaled $7.8 million, as compared to zero for the same period of 2010. The increase is due to 2011 being the first year we recognized revenue under our leases to Armstrong Energy. Total tons sold by Armstrong Energy during the year ended December 31, 2011 that generated royalty revenues was approximately 2.7 million tons, resulting in average royalty revenue per ton of $2.87.
 
Related Party Service Expense
 
Related party service expense of $0.7 million for the year ended December 31, 2011 is consistent with that incurred in the same period of 2010. Amount relates to general administrative and management services provided by Armstrong Energy on our behalf.


61


Table of Contents

Depletion Expense
 
Depletion expense was $3.8 million for the year ended December 31, 2011, as compared to zero for the same period of the prior year. The increase is due to 2011 being the first year production occurred under our leases to Armstrong Energy resulting in depletion to only be incurred during the current year.
 
Interest Income
 
Interest income decreased $3.2 million, or 76.0%, to $1.0 million for the year ended December 31, 2011, as compared to $4.2 million for the same period of 2010. The decrease is due primarily to the conversion in February 2011 of amounts owed to us by Armstrong Energy into an undivided interest in certain mineral reserves and land of Armstrong Energy.
 
Other Income
 
Other income totaled $1.1 million for the year ended December 31, 2011, as compared to zero for the same period of 2010. On February 9, 2011, Armstrong Energy entered into a new credit agreement, whereby we agreed to be a co-borrower with respect to the Senior Secured Term Loan and pledged our assets as collateral and became a guarantor with respect to the Senior Secured Revolving Credit Facility and the Senior Secured Term Loan. In exchange, Armstrong Energy has agreed to pay us a credit support fee equal to 1% of the weighted average outstanding balance under the credit agreement, which can be as much as $150.0 million. As of December 31, 2011, the principal amount outstanding under the credit agreement was $140.0 million and the credit support fee paid for the year ended December 31, 2011 totaled $1.1 million.
 
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
 
Other Operating, General and Administrative Costs
 
Other operating, general, and administrative costs decreased $0.2 million, or 60.2%, to $0.1 million for the year ended December 31, 2010, as compared to $0.3 million for the year ended December 31, 2009. The decrease is due primarily to additional professional fees incurred during 2009 related to a financing that was cancelled.
 
Related-Party Service Expense
 
Related-party service expense increased to $0.7 million for the year ended December 31, 2010. The increase represents an allocation of shared accounting and administrative expenses incurred on our behalf by Armstrong Energy.
 
Interest Income
 
Interest income increased $4.0 million to $4.2 million for the year ended December 31, 2010, as compared to $0.2 million for the year prior. The increase is due primarily to additional interest income earned on promissory notes made in favor of Armstrong Energy. In November 2009, March 2010, May 2010, and November 2010, we advanced $11.0 million, $9.5 million, $12.6 million, and $11.0 million, respectively, to Armstrong Energy in order for them to meet certain debt service obligations. Each promissory note bears interest at the greater of 3% per annum or 7% of the sales price for coal sold from certain properties specified in the promissory notes.
 
Interest Expense
 
Interest expense declined to zero for the year ended December 31, 2010, as compared to expense of $1.7 million for the year ended December 31, 2009. Interest expense incurred during 2009 related to an outstanding promissory note issued for the acquisition of mineral rights and other assets, which was paid in full in June 2009.


62


Table of Contents

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:
 
                                         
        Three Months Ended
    Year Ended December 31,   March 31,
    2009   2010   2011   2011   2012
        (In thousands)            
 
Net cash provided by (used in):
                                       
Operating Activities
  $ (308 )   $ 13,792     $ 8,007     $ 2,221     $ 2,095  
Investing Activities
  $ (12,424 )   $ (46,892 )   $ (33,007 )   $ (7,221 )   $ 339  
Financing Activities
  $ 12,722     $ 33,100     $ 25,000     $ 5,000     $ (2,434 )
 
Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011
 
Net cash provided by operating activities was $2.1 million for the three months ended March 31, 2012, a decrease of $0.1 million from net cash provided by operating activities of $2.2 million for the same period of 2011. We experienced a decline in earnings in the three months ended March 31, 2012, as compared to the same period of the prior year, due to primarily to higher depletion and unit compensation expense, offset partially by an increase in revenue from higher production under our leases to Armstrong Energy. We also experienced a decline in other non-current liabilities in the current year of approximately $1.0 million related to the recognition of deferred revenue earned from certain of our leases to Armstrong Energy.
 
Net cash provided by investing activities was $0.3 million for the three months ended March 31, 2012, as compared to net cash used in investing activities of $7.2 million for the three months March 31, 2011. For the three months ended March 31, 2012, we completed the exchange of certain amounts owed to us by Armstrong Energy totaling $25.7 million for a 11.36% undivided interest in certain mineral reserves and land of Armstrong Energy. For the three months ended March 31, 2011, the net use of cash primarily relates to the exercise of our option to obtain a 39.45% undivided interest in certain mineral reserves and land of Armstrong Energy in satisfaction of certain promissory notes, plus accrued interest and other long-term receivables owed by Armstrong Energy totaling approximately $52.5 million. In connection with that exercise, we paid an additional $5.0 million in cash and agreed to offset $12.0 million in accrued advance royalty payments owed by Armstrong Energy to us to acquire the undivided interest in certain mineral reserves and land with a fair value of $69.5 million. We had a total undivided interest in certain reserves and land of Armstrong Energy of 50.81% at March 31, 2012.
 
Net cash used in financing activities was $2.4 million for the three months ended March 31, 2012, as compared to net cash provided in financing activities of $5.0 million for the same period of the year prior. For the three months ended March 31, 2012, we repurchased 17,765 common units for $2.4 million to satisfy the tax obligations of the grantees who received restricted stock awards. Net cash provided by financing activities of $5.0 million for the three months ended March 31, 2011 related to partner contributions made in connection the acquisition of certain mineral reserves discussed above.


63


Table of Contents

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
 
Net cash provided by operating activities was $8.0 million for the year ended December 31, 2011, a decrease of $5.8 million from net cash provided by operating activities of $13.8 million for the same period of 2010. The decrease in cash provided by operating activities was principally attributable to the reduced receivable related to interest due from Armstrong Energy of $10.4 million, offset by higher depletion expense in 2011, as 2011 is the first year production occurred under our leases with Armstrong Energy and unit compensation expense related to grants issued in 2011.
 
Net cash used in investing activities was $33.0 million for the year ended December 31, 2011 compared to $46.9 million for the year ended December 31, 2010. For the year ended December 31, 2011, the net use of cash primarily relates to the exercise of our option to obtain a 39.45% undivided interest in certain mineral reserves and land of Armstrong Energy in satisfaction of certain promissory notes, plus accrued interest and other long-term receivables owed by Armstrong Energy totaling approximately $52.5 million. In connection with that exercise, we paid an additional $5.0 million in cash and agreed to offset $12.0 million in accrued advance royalty payments owed by Armstrong Energy to us to acquire the undivided interest in certain mineral reserves and land with a fair value of $69.5 million. The net use of cash for the year ended December 31, 2010 relates primarily to advances made to Armstrong Energy.
 
Net cash provided by financing activities was $25.0 million for the year ended December 31, 2011 compared to $33.1 million for the same period of the year prior. This decrease is due to $8.1 million of higher partner contributions in 2010, which was loaned to Armstrong Energy for the repayment of long-term debt and reserves purchases.
 
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
 
Net cash provided by operating activities was $13.8 million for 2010, an increase of $14.1 million from net cash used in operating activities of $0.3 million for 2009. The increase in cash provided by operating activities was principally attributable to an increase in net income of $5.2 million related to interest earned on promissory notes and the increase in advance royalties of $8.8 million in 2010 on mineral reserves leased to Armstrong Energy.
 
Net cash used in investing activities was $46.9 million for 2010 compared to $12.4 million for 2009. The $34.5 million change was primarily attributable to an increase in amounts loaned to Armstrong Energy of $26.1 million for debt service obligations and an increase in other receivables, net owed by Armstrong Energy of $8.3 million, primarily related to advance royalties.
 
Net cash provided by financing activities was $33.1 million for 2010 compared to $12.7 million for 2009. This difference was primarily attributable to a decrease in partner capital contributions of $8.5 million in 2010 and the repayment of outstanding debt obligations in 2009 of $28.9 million.
 
Off-Balance Sheet Arrangements
 
In February 2011, Armstrong Energy entered into a Senior Secured Credit Facility, which is comprised of the Senior Secured Term Loan and the Senior Secured Revolving Credit Facility. The Senior Secured Term Loan is a $100.0 million term loan, and the Senior Secured Revolving Credit Facility is a $50.0 million revolving credit facility. We agreed to be a co-borrower with respect to the Senior Secured Term Loan and pledged our assets as collateral and became a guarantor with respect to the Senior Secured Revolving Credit Facility and the Senior Secured Term Loan. In exchange, Armstrong Energy has agreed to pay us a credit support fee equal to 1% of the weighted average outstanding balance under the credit agreement, which can be as much as $150.0 million. As of March 31, 2012, the principal amount outstanding under the credit agreement was $120.0 million and the credit support fee paid for the three months ended March 31, 2012 totaled $0.3 million. This debt is not recorded on our balance sheet.


64


Table of Contents

Contractual Obligations
 
We do not have any contractual obligations due as of December 31, 2011. As noted above, we are a co-borrower with respect to Armstrong 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 December 31, 2011, the outstanding balance of the Senior Secured Credit Facility, which is included in the financial statements of Armstrong Energy, consisted of $100.0 million under the term loan and $40.0 million under the revolving credit facility. The following table provides details of the obligations due under the Senior Secured Term Loan as of December 31, 2011:
 
                                         
    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)
  $ 114,311     $ 25,404     $ 47,029     $ 41,878         —    
                                         
 
Critical Accounting Policies and Estimates
 
Our preparation of financial statements in conformity with GAAP requires that we make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. We base our judgments, estimates and assumptions on historical information and other known factors that we deem relevant. Estimates are inherently subjective as significant management judgment is required regarding the assumptions utilized to calculate accounting estimates.
 
We are an emerging growth company as such term is defined in the JOBS Act. Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to opt out of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.
 
This section describes those accounting policies and estimates that we believe are critical to understanding our historical consolidated financial statements and that we believe will be critical to understanding our consolidated financial statements subsequent to this offering.
 
Royalty Revenue
 
Royalty revenues are recognized on the basis of tons of coal sold by Armstrong Energy and the corresponding revenue from those sales. Generally, Armstrong Energy will make payments to us based on a percentage of the gross sales price.
 
Depletion
 
We deplete our mineral reserves on a units-of-production basis by lease, based upon coal mined in relation to the net cost of the mineral reserves and estimated proven and probable tonnage in those reserves. We estimate proven and probable mineral reserves with the assistance of third-party mining consultants, and we use estimation techniques and recoverability assumptions. We update our estimates of mineral reserves periodically and this may result in material adjustments to mineral reserves and depletion rates that we recognize prospectively. In addition, we record depletion related to our percentage ownership of reserves held by Armstrong Energy and us as joint tenants-in-common. This amount is based on the depletion recorded by Armstrong Energy and subject to the same methods of calculation that we use to estimate our depletion.


65


Table of Contents

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. 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 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 323,199 units. We utilized a third party specialist to determine the grant date fair value of the common units awarded. The undiscounted fair value of our common units, which totaled $18.94 per unit, was based on both a market approach using the comparable company method and an income approach using the discounted cash flow method. Given a liquidity event is expected to occur within approximately six months, a non-marketability discount of 5% was applied to determine an overall fair value per share. Based on this valuation, the overall fair value per unit was determined to be $18.02. The total fair value of the grants of $5.8 million was expensed through the vesting date of March 31, 2012.
 
New Accounting Standards Issued and Adopted
 
In January 2010, the Financial Accounting Standards Board (the “FASB”) issued accounting guidance that requires new fair value disclosures, including disclosures about significant transfers into and out of Level 1 and Level 2 fair-value measurements and a description of the reasons for the transfers. In addition, the guidance requires new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The new disclosure requirements became effective for interim and annual periods beginning January 1, 2010, except for the disclosure of activity within Level 3 fair value measurements, which


66


Table of Contents

became effective January 1, 2011. The new guidance did not have an impact on our consolidated financial statements.
 
In June 2011, the FASB amended requirements for the presentation of other comprehensive income (loss), requiring presentation of comprehensive income (loss) in either a single, continuous statement of comprehensive income or on separate but consecutive statements, the statement of operations and the statement of other comprehensive income (loss). The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, or March 31, 2012 for us. The adoption of this guidance did not impact our financial position, results of operations or cash flows.
 
In May 2011, the FASB amended the guidance regarding fair value measurement and disclosure. The amended guidance clarifies the application of existing fair value measurement and disclosure requirements. The amendment is effective for interim and annual periods beginning after December 15, 2011, or March 31, 2012 for us. Early adoption is not permitted. The adoption of this amendment did not materially affect our consolidated financial statements.
 
Quantitative and Qualitative Disclosures about Market Risk
 
We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risk is related to commodity prices.
 
Commodity Price Risk
 
All of our coal is sold by Armstrong Energy through multi-year coal supply agreements. Current conditions in the coal industry may make it difficult for Armstrong Energy to extend existing contracts or enter into supply contracts with terms of one year or more. The failure to negotiate long-term contracts could adversely affect the stability and profitability of Armstrong 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 $0.04 per ton of royalty revenue associated with coal leased from our 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.


67


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 260 billion tons of recoverable coal reserves in the United States, more than in any other country, which represents over 200 years of domestic coal supply based on current production rates. The United States is second only to China in annual coal production, producing approximately 1.1 billion tons in 2011, according to the EIA.
 
Coal is ranked by heat content, with anthracite, bituminous, subbituminous, and lignite coal representing the highest to lowest carbon and heat ranking, respectively. Coal is also characterized by end use market as either thermal coal or metallurgical coal. Thermal coal is used by utilities and independent and industrial power producers to generate electricity and/or steam or heat, and metallurgical coal is used by steel companies to produce metallurgical coke for use in the steel making process. Important factors in evaluating thermal coal quality are its Btu or heat content, sulfur, ash, and moisture content, while metallurgical coal is evaluated on the additional metrics of contained volatile matter and coking characteristics, including expansion, plasticity, and strength.
 
Electricity generation accounts for 60% of global coal consumption (2008) while industrial consumption accounts for nearly 36% of global coal production. Thermal 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 2017 from 921 million tons in 2011, driven largely by increased electricity demand in the developing world, a significant portion of which is expected to be supplied by coal-fired power plants. According to the EIA, U.S. domestic thermal coal market consumption accounts for approximately 85% of U.S. domestic coal production and coal-fired electricity generation is expected to continue to be the largest single fuel source of U.S. electricity (39% in 2035).
 
Recent Trends
 
U.S. and international coal market supply, demand, and prices are influenced by many factors including relative coal quality, available capacity and costs of transportation and related infrastructure (such as rail, barge, and river or export terminals), mining production costs, and the relative costs of generating electricity with competing fuels (natural gas, fuel oil, hydro, nuclear, and renewable such as wind and solar power). U.S. domestic thermal coal demand and global thermal coal demand are strongly correlated with the pace of domestic and global economic growth.
 
Our 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 2011, a substantial majority of which was sold by U.S. coal producers to operators of electricity generation plants. Coal-fired electricity generation is the largest component of total world electricity generation.


68


Table of Contents

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 42% of all electricity generation in the United States in 2011. On a long-term basis, coal continues to be the lowest cost fossil fuel source of energy for electric power generation. Despite recent increases in generation from natural gas, as well as federal and state subsidies for the construction and operation of renewable energy, the EIA projects that coal-fired generation will continue to remain the largest single source of electricity generation in 2035. According to the EIA, total electricity generation in the United States decreased by 0.5% during 2011 compared with 2010, and U.S. electric generation from coal decreased by 6.1% in 2011 compared with 2010 and is expected to decreased by a further 10% in 2012. While the EIA projects that electricity generation will grow at an annual average rate of 0.8% through 2035, it projects that the percentage of electricity generated from coal will decrease to 39% of total generation by 2035, compared with 42% during 2011.
 
The EIA projects coal-fueled electric power generation to decline in 2012, primarily driven by depressed near-term natural gas prices that are resulting in elevated levels of coal-to-gas switching. If coal-to-gas switching lasts for a prolonged period during 2012 due to significantly depressed natural gas prices, there may be more substantial unfavorable impacts to all coal supply regions. We expect to continually review, and adjust if necessary, our production levels in response to changes in market demand.
 
  •  Increasing demand for coal produced in the Illinois Basin.  According to Wood Mackenzie, a leading commodities consultancy, demand for coal produced from the Illinois Basin is expected to grow by 48% from 2010 through 2015 and by 108% from 2010 through 2030. We believe this is due to a combination of factors including:
 
  è  Significant expansion of scrubbed coal-fired electricity generating capacity.  The EIA forecasts a 12% increase in FGD installed on the coal-fired generation fleet from 199 gigawatts in 2010 to 222 gigawatts, or 70% of all U.S. coal-fired capacity in the electric sector by 2035, as electricity generation operators invest in retrofit emissions reduction technology to comply with new EPA regulations under the Cross-State Air Pollution Rule and the new MATS for power plants. Currently, the EIA estimates that approximately 63% of all U.S. coal-fired generation capacity has FGD technology installed or under construction. Illinois Basin coal generally has a higher sulfur content per ton than coal produced in other regions. However, we believe that FGD utilization will enable operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.
 
  è  Declines in Central Appalachian thermal coal production.  Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 115 million tons in 2011 to 64 million tons in 2015, due to reserve depletion, regulatory-driven decreases in Central Appalachian surface thermal coal production, and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.
 
  è  Growing demand for seaborne thermal coal.  Global trade in thermal coal accounted for nearly 70% of all global coal exports in 2011 and is projected to rise from 921 million tons in 2011 to 1.1 billion tons by 2017. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality, and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.


69


Table of Contents

 
Coal Consumption and Demand
 
The vast majority of thermal coal consumed in the United States is used to generate electricity, with the balance used by a variety of industrial users to heat and power a range of manufacturing and processing facilities. Metallurgical coal is primarily used in steelmaking blast furnaces. In 2011, coal-fired power plants produced approximately 42% of all electric power generation, more than natural gas and nuclear, the two next largest domestic fuel sources, combined. Thermal coal used by electric utilities and other power producers accounted for 929 million tons or 93% of total coal consumption in 2011.
 
Because coal-fired generation is used in most cases to meet base load electricity demand requirements, coal consumption has generally grown at the pace of electricity demand growth. Among 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 2012 reference case that total coal consumption will grow by approximately 10% from 2010 through 2035, primarily due to increases in coal-fired electric power generation.
 
Illinois Basin Coal Market
 
Our lessee markets and delivers coal from our reserves to electricity generating customers both in close proximity to its production area in Western Kentucky, along the Green and Ohio Rivers, and to customers along the Mississippi River and in the Southeastern United States. In 2010, 49.1% of the electricity in our 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
 
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


70


Table of Contents

 
More importantly, the progressive tightening by the EPA of SO2, NOx and other air pollutant emissions standards from coal-fired electricity generation plants is expected to result in additional significant increases in the number of generating stations retrofitted with FGD systems.
 
U.S. Scrubber Market
 
The 1990 amendments to the Clean Air Act imposed progressively stringent regulations on the emissions of SO2 and NOx. Among the coal-fired electricity generation 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 also recently finalized additional rules to further reduce the release of certain combustion by-product emissions from fossil fuel power plants; including the MATS rate published in February 2012, which regulates the emission of mercury and other toxic air pollutants.
 
To comply with the tightening of emissions limitations, operators of coal-fired electricity generation have increasingly invested in FGD, selective and non-selective catalytic reduction systems and other advanced control technologies at their large, base load power plants. 199 gigawatts of the current 316 gigawatts of U.S. coal-fired generation is presently equipped with FGD emissions systems. We believe that with the implementation of the CSAPR and the MATS rule, new FGD systems will likely be installed on additional coal-fired generation increasing the total amount of generation capacity to approximately 70% of all U.S. capacity in the electric sector capacity by 2035. Currently the EIA estimates that approximately 63% of all U.S. coal-fired generation capacity has FGD technology installed or under construction.
 
Today, the number of scrubbers being installed at coal-fired power plants across the United States is growing, and the operating and economic profile of this technology has become well understood and broadly applied. We expect that the continuation of this trend will substantially increase the demand for higher sulfur coal given the competitive cost of Illinois Basin coal, and will expand the competitive reach of our coal and our primary market area.
 
The following table contains Wood 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 units which may position higher sulfur coal from the Illinois Basin to effectively compete for a greater share of supply to these units.
 
                                         
    Projected Affected Tons Due to Announced Scrubbing
    2010
  2011
  2012
  2013
  2014
    Actual   Forecast   Forecast   Forecast   Forecast
    (In millions)
 
MW Scrubbed (U.S. Total)
    37,448       10,629       9,940       11,967       9,121  
Coal Tons Affected (Million Tons)
    120       34       32       38       29  
 
 
Source: Wood Mackenzie Illinois Basin Market Outlook, September 2011
 
Wood Mackenzie forecasts that the U.S. domestic electricity generation coal consumption will grow from a projected 942 million tons in 2012 to 985 million tons by 2015. More importantly, the Wood Mackenzie forecast projects Illinois Basin coal production growth from 130 million tons in 2012 to 167 million tons by 2015 (28% growth) and then to over 200 million tons by 2020.


71


Table of Contents

Long-Term U.S. Thermal Coal Outlook — Fall 2011: Summary Table of Key Data
(tons in millions)
 
                                                                 
    2012     2013     2014     2015     2020     2025     2030        
 
Supply (Mst)
    1,109       1,113       1,108       1,145       1,139       1,179       1,240          
                                                                 
Powder River Basin
    487       483       486       508       481       508       552          
Central Appalachia
    89       76       64       64       46       56       71          
Illinois Basin
    130       144       157       167       204       216       224          
Northern Appalachia
    121       129       134       136       132       125       124          
Metallurgical (not including Thermal Cross Over)
    84       82       69       70       81       87       93          
Imports
    8       5       3       3       5       5       5          
Other (including Refuse or Petcoke)
    190       195       196       197             181       171          
Stockpile Increase (Decrease)
                            190                      
                                                                 
Demand (Mst)
    1,109       1,113       1,108       1,145       1,139       1,179       1,240          
                                                                 
Electricity Generation
    942       942       967       985       954       837       794          
Industrial
    52       51       52       52       53       54       54          
Thermal Export
    32       38       21       38       52       200       299          
Metallurgical Demand (includes Thermal Cross Over)
    84       82       69       70       81       87       93          
 
 
Source: Wood Mackenzie Long Term US Thermal Coal Market Outlook, October 2011
 
Wood Mackenzie estimates that demand for Illinois Basin coal will grow at a compound annual rate of 3.7%, taking total consumption from 117 million tons in 2012 to more than 225 million tons by 2030. This is compared to total U.S. coal production, which Wood Mackenzie estimates will grow at a compound annual rate of 0.6% over the same period. Importantly, Illinois Basin coal production is projected to grow more sharply over the 2012-2020 period (5.8% CAGR) than over the latter part of the 20-year projection period.
 
Conversely, Wood Mackenzie estimates that Central Appalachian thermal coal production has declined from 217 million tons in 2000 to 115 million tons in 2011, while Northern Appalachian coal production has had only minor fluctuations.
 
Global Thermal Coal Markets
 
Global coal production accounted for 30% of global primary energy consumption in 2010, according to BP.
 
2010 Global Primary Energy Consumption by Fuel
 
(PIE CHART)
 
 
Source: BP Statistical Review of World Energy, June 2011


72


Table of Contents

 
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 2017, with Asia accounting for more than 812 million tons of import demand, up from 627 million tons in 2011.
 
In the Atlantic thermal coal market, European Union and other European coal imports are projected to rise from 223 million tons in 2011 to 240 million tons by 2017.
 
We believe the projected robust growth in global thermal coal trade to satisfy growing demand for electricity generation will create substantial opportunities for U.S. coal producers with competitive transportation advantages to profitably export thermal coal.
 
The Illinois Basin coal production region is strategically well positioned with access to the Green, Ohio and Mississippi River systems to deliver coal to New Orleans or Port of Mobile coal export terminals for delivery of coal to growing Atlantic and Pacific import coal consumers.
 
Costs and Pricing Trends
 
Coal prices are influenced by a number of factors and vary materially by region. As a result of these regional characteristics, prices of coal by product type within a given major coal producing region tend to be relatively consistent with each other. The price of coal within a region is influenced by market conditions, coal quality, transportation costs involved in moving coal from the mine to the point of use and mine operating costs. For example, higher carbon and lower ash content generally result in higher prices, and higher sulfur and higher ash content generally result in lower prices within a given geographic region.
 
The cost of coal at the mine is also influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Within a particular geographic region, underground mining is generally more expensive than surface mining. This is due to typically higher capital costs, including costs for construction of extensive ventilation systems, and higher per unit labor costs arising from lower productivity associated with underground mining.
 
During the past decade, the price of coal has fluctuated like any commodity as a result of changes in supply and demand. For example, when coal supplies declined from 2003 to part of 2006 and subsequently for a short time in 2007 and 2008, the prices for coal reached record highs in the United States. The increased worldwide demand for coal is being driven by higher prices for oil, together with overseas economic expansion in countries such as China and India who rely heavily on coal-fired electricity generation. At the same time, infrastructure, weather-related production interruptions and supply restrictions on exports from China and Indonesia have contributed to a tightening of worldwide thermal coal supply, affecting global prices of coal.
 
Coal Characteristics
 
The quality of coal is measured primarily by its heat content in British thermal units per pound (“Btu/lb”). However, sulfur, ash and moisture content, and volatile content and coking characteristics are also important variables in the ranking and marketing of coal. These characteristics help producers determine the best end use of a particular type of coal. The following is a description of these general coal characteristics:
 
Heat Value.  In general, the carbon content of coal supplies most of its heating value, but other factors also influence the amount of energy it contains per unit of weight. Coal with higher heat value is priced higher than coal with lower heat value because less coal is needed to generate the same quantity of electric power. Coal is generally classified into four categories, ranging from lignite, subbituminous, bituminous and anthracite, reflecting the progressive response of individual deposits of coal to increasing heat and pressure. Anthracite is coal with the highest carbon content and, therefore, the highest heat value, nearing 15,000 Btus/


73


Table of Contents

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 “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.


74


Table of Contents

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 centers are Northern and Central Appalachia, the Illinois Basin in the Interior region, and the Powder River Basin in the Western region. The type, quality and characteristics of coal vary by, and within each, region.
 
Appalachian Region.  The Appalachian region is divided into the Northern, Central and Southern regions, with the Northern and Central areas being the largest coal producers in the region. Northern Appalachia includes Ohio, Pennsylvania, Maryland and northern West Virginia. The area includes reserves of bituminous coal with heat content ranging from 10,300 to 13,000 Btu/lb) and sulfur content ranging from 1.0% to 2.0%. Coal produced in Northern Appalachia is marketed primarily to electric utilities, industrial consumers and the export market, with some metallurgical coal marketed to steelmakers.
 
Central Appalachia includes eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The area includes reserves of bituminous coal with a typical heat content of 12,000 Btu/lb or greater and sulfur content ranging from 0.5% to 1.5%. Coal produced in Central Appalachia is marketed primarily to electric utilities, with metallurgical coal marketed to steelmakers. The combination of reserve depletion and increasing regulatory enforcement, mining costs and geologic complexity in Central Appalachia is expected to lead to substantial production declines over the long term. In fact, actual total production has declined from approximately 257 million tons in 2000 to 186 million tons in 2010. In addition, the widespread installation of scrubbers is expected to enable higher sulfur coal from Northern Appalachia and the Illinois Basin to displace coal from Central Appalachia.
 
Interior Region.  The major coal producing center of the Interior region is the Illinois Basin, which includes Illinois, Indiana and western Kentucky. The area includes reserves of bituminous coal with a heat


75


Table of Contents

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.
 
The other underground mining method commonly used in the United States is the longwall mining method. In longwall mining, a rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while it advances through the coal. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Armstrong Energy currently does not, and does not plan to in the near future, produce coal using longwall mining techniques.
 
Surface Mining
 
Surface mining produces the majority of U.S. coal output, accounting for approximately 69% of U.S. production in 2010. Surface mining is generally used when coal is found relatively close to the surface, when multiple seams in close vertical proximity are being mined or when conditions otherwise warrant. Surface mining involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing approximate original counter, vegetation and plant life, and making other improvements that have local community and environmental benefit. Overburden is typically removed at mines using explosives in combination with large, rubber-tired diesel loaders or more efficient draglines. Surface mining can recover nearly 90% of the coal from a reserve deposit.
 
There are four primary surface mining methods in use in Appalachia and the Illinois Basin: area, contour, auger and highwall. Area mines are surface mines that remove shallow coal over a broad area where the land is relatively flat. After the coal has been removed, the overburden is placed back into the pit. Contour mines are surface mines that mine coal in steep, hilly or mountainous terrain. A wedge of overburden is removed along the coal outcrop on the side of a hill, forming a bench at the level of the coal. After the coal is


76


Table of Contents

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.


77


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 65 million tons of coal reserves and, as of March 31, 2012, had a 50.81% undivided interest in approximately 140 million tons of coal reserves owned by Armstrong Energy, all located in Ohio and Muhlenberg Counties in Western Kentucky. Our coal is generally low chlorine, high sulfur coal.


78


Table of Contents

Our outstanding limited partnership interests (“common units”), representing 99.7% of our equity interests, are owned by Yorktown. We are not engaged in the permitting, production or sale of coal, nor in the operation or reclamation of coal mining activity. We are a fee mineral and surface rights owning entity. It is our intention to remain a coal leasing enterprise and not to engage in coal production ourselves.
 
We currently lease all of our reserves to Armstrong Energy, our sole lessee, in exchange for royalty payments in the amount of 7% of the revenue received from coal sold from those reserves. Armstrong Energy is a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin with both surface and underground mines. We are currently deferring those royalty payments. Partially as a result of those deferrals, as of December 31, 2011 we were owed approximately $5.7 million from Armstrong Energy.
 
We intend to use the net proceeds from this offering to purchase an additional estimated 8% to 10% partial undivided interest in the reserves in which we had, as of March 31, 2012, a 50.81% interest as a joint tenant in common with Armstrong Energy. See “Prospectus Summary — Business Developments” and “Certain Relationships and Related Party Transactions — Membership Interest Purchase Agreement.” The actual percentage acquired will depend on the fair value of the reserves at the time of the acquisition and the net proceeds received in this offering. In addition, our interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves could be increased as a result of an additional acquisition through the offset of unpaid deferred royalties owed to us.
 
We are a co-borrower under Armstrong 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 in 2011 and the three months ended March 31, 2012, Armstrong Energy is obligated to pay us $7.2 million and $2.1 million, respectively, for production royalties under our leases for such period. In addition, we earned a credit and collateral support fee as a result of our financing activities in the amount of $1.15 million and $0.3 million in the year ended December 31, 2011 and three months ended March 31, 2012, respectively.
 
We are headquartered in St. Louis, Missouri.


79


Table of Contents

Strategy
 
Our primary business strategy is to enhance unitholder value by executing the following strategies:
 
  •  Continue to grow our joint interest in our coal reserve holdings through additional investments in our existing proven and probable reserves.  We expect that the demand for Illinois Basin coal will rise as a result of an increase in power plants being retrofitted with scrubbers and the construction of new power plants throughout the Illinois Basin market area. Pursuant to the terms of a Royalty Deferment and Option Agreement with our sole lessee, Armstrong Energy, we have the right to acquire additional undivided interests in coal reserves controlled by Armstrong Energy in the event that Armstrong defers cash payment to us for royalties due. We expect that for the foreseeable future all or a substantial portion of our royalty revenues will be used by us to acquire additional coal reserve interests and will not be a source of cash for the payment of dividends or other distributions to our unitholders. Except for distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership, which will be paid, if at all, solely at the discretion of Elk Creek GP, our general partner, we do not anticipate paying any distributions for the foreseeable future.
 
  •  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 eight separate mines, obtained the necessary regulatory permits for the commencement of mining operations at those mines, and developed significant multi-year contractual relationships with large customers in its market area. We believe this resulted from Armstrong 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 December 31, 2011, we either owned or had an interest in approximately 205 million tons of clean recoverable (proven and probable) coal reserves. Our reserves represent underground mineable coal, which, in combination with our 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.


80


Table of Contents

 
  •  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, but assuming conversion of our Series A convertible preferred units and conversion of Armstrong Energy’s Series A preferred stock.
 
(CHART)
 
 
(1) Reserves owned solely by Armstrong Resource Partners. These include the Kronos and Lewis Creek underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners (with a 50.81% undivided interest as of March 31, 2012) and Armstrong Energy (with a 49.19% undivided interest as of March 31, 2012). If this offering and the Concurrent AE Offering and related transactions are completed, the undivided interest of Armstrong Resource Partners will increase, and the undivided interest of Armstrong Energy will decrease, based on the net proceeds of this offering paid to Armstrong Energy and the value of the affected reserves as agreed by Armstrong Resource Partners and Armstrong Energy. See “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Energy.”


81


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 and Lewis Creek underground mines.
 
(2) Reserves controlled jointly by Armstrong Resource Partners and Armstrong Energy. Assuming an offering price of $     per unit, the midpoint of the price range set forth on the front cover page of this prospectus, and an estimated purchase price of $17.5 million for our additional interest in the partially owned reserves, we intend to acquire an additional estimated 8% to 10% partial undivided interest in certain reserves of Armstrong Energy with the net proceeds from this offering. The actual percentage acquired will depend on the fair value of the reserves at the time of the acquisition and the net proceeds received in this offering. In addition, our interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves could be increased as a result of an additional acquisition through the offset of unpaid deferred royalties owed to us.
 
Our Coal Reserves and Production
 
As of December 31, 2011, we had the rights to approximately 65 million tons and rights as joint-tenants-in common with Armstrong Energy to 140 million tons of proven and probable coal reserves located in Ohio and Muhlenberg Counties in Western Kentucky. We lease all of our rights to mine these coal reserves to our


82


Table of Contents

sole lessee, Armstrong Energy. The following table summarizes our coal reserves as of December 31, 2011. All of our reserves are leased to Armstrong Energy.
 
                                                                                 
          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       56,430       8,985       65,415       56,430       8,985       65,415       11,792       4.5       7.6  
Partially Owned Reserves
                                                                               
Reserves in Active Production(5)
                                                                               
Midway
    S       19,377       1,427       20,805       7,644       563       8,207       11,315       4.8       10.0  
Parkway
    U       7,535       5,434       12,969       2,973       2,144       5,116       11,931       4.4       7.1  
East Fork(6)
    S       2,287       550       2,837       902       217       1,119       11,136       7.6       11.2  
Equality Boot
    S       21,841       1,151       22,992 (7)     8,616       454       9,070       11,587       5.7       8.8  
Lewis Creek
    S       6,160       101       6,261       2,430       40       2,470       11,420       4.0       9.5  
Maddox
    S       512             512       202             202       11,315       4.8       10.0  
                                                                                 
Total Partially Owned Reserves in Active Production
            57,712       8,663       66,376       22,767       3,418       26,185                          
Additional Reserves
                                                                               
Ken
    S       17,166       3,854       21,020       6,772       1,520       8,292       11,809       5.0       7.5  
Other
    S/U       40,145       12,016       52,159 (8)     15,837       4,740       20,578       11,300       4.5       8.0  
                                                                                 
Total Additional Reserves
            57,311       15,870       73,179       22,609       6,261       28,870                          
                                                                                 
Total
            171,453       33,518       204,970       101,807       18,663       120,470                          
                                                                                 
 
 
(1) Determined as of December 31, 2011. Gross amounts reflect the combined 100% joint ownership interest of Armstrong Resource Partners and Armstrong Energy in reserves in active production. Net amounts reflect our 39.45% undivided interest in such jointly controlled reserves which were acquired on February 9, 2011. Upon completion of this offering, we intend to use the net proceeds to us to acquire from Armstrong Energy an additional undivided interest in certain of Armstrong 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) We commenced production at the Kronos underground mine in September 2011.
 
(5) Reserves that are in active production as of December 31, 2011.
 
(6) Warden and Kronos surface pits. Production at the Kronos pit ceased in August 2011.
 
(7) Includes approximately 0.3 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.
 
(8) Includes approximately 1.9 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.


83


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
    Net Clean
             
    Recoverable Tons
    Recoverable Tons
    Gross Production(2)     Net Production(2)  
    (Proven and Probable
    (Proven and Probable
    Year Ended
    Year Ended
    Year Ended
    Year Ended
 
    Reserves)(1)     Reserves)(1)     December 31,
    December 31,
    December 31,
    December 31,
 
Reserve
  Owned     Leased     Total     Owned     Leased     Total     2010     2011     2010     2011  
    (In thousands)     (In thousands)     (Tons in thousands)     (Tons in thousands)  
 
Owned
                                                                               
Elk Creek(3)
    61,890       3,525       65,415       61,890       3,525       65,415             (4)            
Partially Owned
                                                                               
Midway
    20,805             20,805       8,207             8,207       1,614.8       1,589.2       637.0       626.9  
Parkway
    2,326       10,643       12,969       918       4,199       5,116       1,485.9       1,491.9       586.2       588.6  
East Fork(5)
    2,193       645       2,837       865       254       1,119       1,641.1       745.9       647.4       294.3  
Equality Boot
    22,992             22,992 (6)     9,070             9,070       330.8       1,916.8       130.5       756.2  
Lewis Creek
    6,261             6,261       2,470             2,470             474.9             187.4  
Maddox
    512             512       202             202             24.9             9.8  
                                                                                 
Total Active
    55,089       11,288       66,376       21,732       4,453       26,185       5,072.6       6,243.6       2,001.1       2,463.1  
Additional Reserves
                                                                               
Ken
    21,020             21,020       8,292             8,292                                  
Other
    35,427       16,732       52,159 (7)     13,977       6,601       20,578       572.1 (8)     398.8 (8)     225.7       157.3  
                                                                                 
Total Additional
    56,447       16,732       73,179       22,269       6,601       28,870                                  
                                                                                 
Total
    173,426       31,545       204,970       105,891       14,579       120,470       5,644.7       6,642.4       2,226.8       2,620.4  
                                                                                 
 
 
(1) For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.
 
(2) Determined as of December 31, 2011. Gross amounts reflect the combined 100% joint ownership interest of Armstrong Resource Partners and Armstrong Energy in reserves in active production. Net production amounts reflect our 39.45% undivided interest in such jointly controlled reserves as if we had this ownership since January 1, 2010. Our actual proportion of sales began in February 2011 and amounted to approximately 2.5 million tons for the year ended December 31, 2011. Upon completion of this offering, we intend to use the net proceeds to acquire from Armstrong Energy an additional undivided interest in certain of Armstrong Energy’s coal reserves. See “Use of Proceeds.”
 
(3) Commenced production at the Kronos mine in September 2011.
 
(4) The Kronos underground mine produced approximately 0.2 million tons of coal in 2011, but the production was capitalized and not included in our results of operations because the mine was still in the developmental phase.
 
(5) Warden and Kronos surface pits. Production at the Kronos pit ceased in August 2011.
 
(6) Includes approximately 0.3 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.
 
(7) Includes approximately 1.9 million tons related to reserves for which Armstrong Energy owns or leases from us only a partial joint interest and royalties on extractions may be payable to other owners.
 
(8) Includes production from the Big Run mine, which ceased operation in October 2011.