As filed with the Securities and Exchange Commission on May 4, 2012

Registration Statement No. 333-177260

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 5
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.

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 4, 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 23 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	$	$

To the extent the underwriters sell more than common units, the underwriters have an option exercisable within 30 days from the date of this prospectus to purchase up to additional common units from us at the public offering price, less the underwriting discount. The common units issuable upon exercise of the underwriters’ over-allotment option have been registered under the registration statement of which this prospectus forms a part.

The underwriters expect to deliver the common units against payment in New York, New York on or about , 2012.


Raymond James	FBR

Stifel Nicolaus Weisel

Prospectus, dated , 2012

TABLE OF CONTENTS


	Page

ABOUT THIS PROSPECTUS		ii
PROSPECTUS SUMMARY		1
RISK FACTORS		23
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS		51
USE OF PROCEEDS		53
CAPITALIZATION		54
DILUTION		55
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		56
UNAUDITED PRO FORMA FINANCIAL INFORMATION		58
SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA		62
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		64
THE COAL INDUSTRY		73
BUSINESS		83
MANAGEMENT		115
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		133
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		135
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		139
DESCRIPTION OF THE COMMON UNITS		144
DESCRIPTION OF INDEBTEDNESS		147
THE PARTNERSHIP AGREEMENT		148
UNITS ELIGIBLE FOR FUTURE SALE		159
MATERIAL TAX CONSEQUENCES		161
CERTAIN ERISA CONSIDERATIONS		181
UNDERWRITING		183
LEGAL MATTERS		189
COAL RESERVES		189
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS		189
CHANGE IN AUDITOR		189
WHERE YOU CAN FIND MORE INFORMATION		190
INDEX TO FINANCIAL STATEMENTS		F-1
EX-1.1
EX-3.4
EX-3.5
EX-5.1
EX-8.1
EX-10.4
EX-10.5
EX-10.7
EX-10.17
EX-10.18
EX-10.19
EX-10.20
EX-10.21
EX-10.22
EX-10.23
EX-10.24
EX-10.25
EX-10.26
EX-10.27
EX-10.28
EX-10.29
EX-10.30
EX-10.31
EX-10.32
EX-10.33
EX-10.34
EX-10.35
EX-10.36
EX-10.37
EX-10.38
EX-10.39
EX-10.40
EX-10.57
EX-10.58
EX-10.59
EX-10.60
EX-10.61
EX-10.62
EX-10.64
EX-10.67
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.

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.

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 23 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 have 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, plus any amount owed to us at the time of the Concurrent AE Offering (see “— Concurrent Offering”) for deferred royalty payments, to purchase an additional partial interest in the reserves in which we currently have a 50.81% interest. See “— Business Developments” and “Certain Relationships and Related Party Transactions — Membership Interest Purchase Agreement.” As a result, following the closing of the transaction, this offering and the Concurrent Offering, we expect to have an approximate 58.54% undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves, which could be increased as a result of an additional acquisition through the offset of unpaid deferred royalties owed to us.

We expect Armstrong Energy to continue to defer royalty payments due to us and we do not plan to pay distributions to any of our unitholders, except for amounts necessary to enable unitholders to pay anticipated income tax liabilities, for the foreseeable future. As a result, we expect to continue to acquire an increasing percentage undivided interest in Armstrong Energy’s coal reserves for the foreseeable future through the offset of deferred royalties owed to us by Armstrong Energy.

We are a co-borrower under Armstrong Energy’s $100.0 million term loan (the “Senior Secured Term Loan”) and a guarantor on the $50.0 million revolving credit facility (the “Senior Secured Revolving Credit Facility,” and together with the Senior Secured Term Loan, the “Senior Secured Credit Facility”) and the Senior Secured Term Loan. Substantially all of our assets and Armstrong Energy’s assets are pledged to secure

borrowings under the Senior Secured Credit Facility. Under the terms of the Senior Secured Credit Facility, without the consent of all lenders (if there are fewer than three lenders at the time of any dividend or distribution) or the lenders having more than 50% of the aggregate commitments (if there are three or more lenders at the time of any dividend or distribution) under that facility, we are currently prohibited from making dividend payments or other distributions to our unitholders in excess of $5.0 million per year and $10.0 million in aggregate, except for dividends or other distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership until February 9, 2016, the date on which the Senior Secured Credit Facility matures. We are not permitted to borrow additional funds under the Senior Secured Credit Facility and as such, it is not a source of liquidity for us.

A wholly owned subsidiary of Armstrong Energy, Inc., Elk Creek GP, LLC (“Elk Creek GP”), is our general partner. Pursuant to our Second Amended and Restated Agreement of Limited Partnership, dated , 2011 (the “Partnership Agreement”), Elk Creek GP has the exclusive authority to conduct, direct and manage all of our activities. By virtue of Armstrong Energy’s control of Elk Creek, GP, our results are consolidated in Armstrong Energy’s historical consolidated financial statements. Pursuant to our existing partnership agreement, effective October 1, 2011 (the “Existing Partnership Agreement”), Yorktown unilaterally may remove Elk Creek GP as our general partner in some circumstances. As a result, Armstrong Energy will no longer consolidate our results in its financial statements (the “Deconsolidation”).

2011 was the first year we recognized revenue under our leases to Armstrong Energy. Based on its coal production during 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


		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,


		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.

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.

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. We currently have a 50.81% undivided interest in certain of the land and mineral reserves of Armstrong Energy.

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


		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


		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.

assuming conversion of our Series A convertible preferred units and conversion of Armstrong Energy’s Series A preferred stock:


(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) and Armstrong Energy (with a 49.19% undivided interest). If this offering and the Concurrent AE Offering and related transactions are completed, the undivided interest of Armstrong Resource Partners will increase, and the undivided interest of Armstrong Energy will decrease, based on the net proceeds of this offering paid to Armstrong Energy and the value of the affected reserves as agreed by Armstrong Resource Partners and Armstrong Energy. See “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Energy.”

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.


(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 58.54% undivided interest) and Armstrong Energy (with a 41.46% undivided interest), assuming an offering price of $ per unit, the midpoint of the price range set forth on the front cover page of this prospectus and an estimated purchase price of $17.5 million for our additional interest in the partially owned reserves.

Partnership Information

Our principal executive offices are located at 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105 and our telephone number is (314) 721-8202. Our corporate website address is www.armstrongresourcepartners.com. Information on, or accessible through, our website is not part of, or incorporated by reference in, this prospectus. We are organized under the laws of the State of Delaware.

Cash Distribution Policy and Restrictions on Dividends

Pursuant to our Partnership Agreement, within 45 days following the end of each quarter, we may, in our sole and exclusive discretion, distribute an amount equal to some or all of our available cash to unitholders of record on the applicable record date. The payment of distributions, if any, is solely within the discretion of Elk Creek GP, our general partner.

However, the Senior Secured Credit Facility restricts our ability to pay distributions. Under the terms of the Senior Secured Credit Facility, without the consent of all lenders (if there are fewer than three lenders at the time of any dividend or distribution) or the lenders having more than 50% of the aggregate commitments (if there are three or more lenders at the time of any dividend or distribution) under that facility, we are currently prohibited from making dividend payments or other distributions to our unitholders in excess of $5.0 million per year and $10.0 million in aggregate, except for dividends or other distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership until February 9, 2016, the date on which the Senior Secured Credit Facility matures.

Our lessee, Armstrong Energy, has historically deferred the payment to us of cash royalties pursuant to a Royalty Deferment and Option Agreement which it has entered into with us, and we expect that Armstrong Energy will continue to make such deferrals for the foreseeable future. Pursuant to the terms of that Agreement, in the event that Armstrong Energy exercises its deferral right, we have the right to acquire additional undivided interests in coal reserves controlled by Armstrong Energy. We expect that for the foreseeable future all or a substantial portion of our royalty revenues will be used by us to acquire such additional coal reserve interests and will not be a source of cash for the payment of dividends or other distributions to our unitholders.

Except for distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership, which will be paid, if at all, solely at the discretion of Elk Creek, GP, our general partner, we do not anticipate paying any distributions for the foreseeable future.

Yorktown Partners LLC

Yorktown was formed in 1991 and has approximately $3.0 billion in assets under management. Yorktown invests exclusively in the energy industry with an emphasis on North American oil and gas production, coal mining and midstream businesses. Yorktown’s investors include university endowments, foundations, families, insurance companies, and other institutional investors.

Yorktown is the largest owner of our limited partnership interests and is also the largest shareholder of Armstrong Energy, Inc. Bryan H. Lawrence, founder and principal of Yorktown Partners LLC, is also a board member of Armstrong Energy. As a result, Yorktown has, and can be expected to have, a significant influence in our operations, in the outcome of stockholder voting concerning the election of directors to Armstrong Energy’s board, the adoption or amendment of provisions in Armstrong Energy’s charter and bylaws, the approval of mergers, and other significant corporate transactions that may affect us because we are managed by Armstrong Energy’s directors and executive officers. See “Risk Factors.”

Conflicts of Interest and Fiduciary Duties

General. Conflicts of interest exist and may arise in the future as a result of the relationships between Armstrong Energy and its affiliates (including our general partner) on the one hand, and our Partnership and our unitholders, on the other hand. The directors and officers of Armstrong Energy have fiduciary duties to manage its affiliates, including our general partner, in a manner beneficial to its owners. At the same time, Armstrong Energy, through control of our general partner, Elk Creek GP, has a fiduciary duty to manage our Partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between Armstrong Energy and its affiliates, on the one hand, and our Partnership or any other partner, on the other, Armstrong Energy will resolve that conflict. Armstrong Energy may, but is not required to, seek approval of such resolution from the conflicts committee of Armstrong Energy’s board of directors. Delaware law provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner or other managing entity to limited partners and the partnership. Our Partnership Agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner and Armstrong Energy to our common unitholders. Our Partnership Agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner or Armstrong Energy. By purchasing a common unit, a unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the Partnership Agreement that might otherwise be considered a breach of fiduciary duty or other duties under applicable state law.

For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner and Armstrong Energy, please read “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

Armstrong Energy will not be in breach of its obligations under the Partnership Agreement or its duties to us or our unitholders if the resolution of the conflict is considered to be fair and reasonable to us. Any resolution is considered to be fair and reasonable to us if that resolution is:


	•	approved by the conflicts committee, although Armstrong Energy is not obligated to seek such approval and Armstrong Energy may adopt a resolution or course of action that has not received approval;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In resolving a conflict, Armstrong Energy, including its conflicts committee, may, unless the resolution is specifically provided for in the Partnership Agreement, consider:


	•	the relative interests of any party to such conflict and the benefits and burdens relating to such interest;

	•	any customary or accepted industry practices or historical dealings with a particular person or entity;

	•	generally accepted accounting practices or principles; and

	•	such additional factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

Conflicts of interest could arise in the situations described below, among others.

Actions taken by Armstrong Energy may affect the amount of cash available for distribution to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of Armstrong Energy regarding such matters as:


	•	the volume of coal production and the royalties generated from our reserves;

	•	the prices at which coal sales are made, and thereby the royalty revenues generated by the leased coal reserves;

	•	the election to defer the payment of any royalties pursuant to the Royalty Deferment and Option Agreement with Western Mineral Development, LLC, our wholly owned subsidiary (“Western Mineral”), (see “Certain Relationships and Related Party Transactions — Royalty Deferment and Option Agreement”);

	•	Armstrong Energy’s agreement with coal customers to defer or reschedule contractually committed coal sales;

	•	decisions by Armstrong Energy to idle or close any operation due to market conditions, force majeure, or for other operating reasons;

	•	amount and timing of asset purchases and sales;

	•	cash expenditures;

	•	borrowings; and

	•	the issuance of additional common units.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by us or Armstrong Energy to the unitholders.

The Partnership Agreement provides that we and our subsidiaries may borrow funds from Armstrong Energy and its affiliates. Armstrong Energy and its affiliates may borrow funds from us or our subsidiaries.

We do not have any officers or employees and rely solely on officers and employees of Armstrong Energy, Inc. and its affiliates.

We do not have any officers or employees and rely solely on officers and employees of Armstrong Energy, Inc. and its affiliates. Affiliates of Armstrong Energy conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to Armstrong Energy. The officers of Armstrong Energy are not required to work full time on our affairs. These officers devote significant time to the affairs of Armstrong Energy and its affiliates and are compensated by these affiliates for the services rendered to them.

Restrictions in or a failure by our lessee to comply with the terms of the Senior Secured Credit Facility, on which we serve as co-borrower with respect to the Senior Secured Term Loan and guarantor with respect to the Senior Secured Revolving Credit Facility and the Senior Secured Term Loan, could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

The Senior Secured Credit Facility limits our ability to, among other things:


	•	incur additional debt;

	•	make distributions on or redeem or repurchase common units;

	•	make certain investments and acquisitions;

	•	incur certain liens or permit them to exist;

	•	enter into certain types of transactions with affiliates;

	•	merge or consolidate with another company; and

	•	transfer or otherwise dispose of assets.

The Senior Secured Credit Facility also contains covenants requiring us to maintain certain financial ratios. Please read “Description of Indebtedness.”

The Senior Secured Credit Facility restricts our ability to pay distributions. Except for distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership, which will be paid, if at all, solely at the discretion of Elk Creek GP, our general partner, we do not anticipate paying any distributions for the foreseeable future. In addition, we are unable to pay distributions until the restrictions on distributions by us to our limited partners imposed by the Senior Secured Credit Facility have been lifted. See “Cash Distribution Policy and Restrictions on Distributions.”

In addition, the provisions of the Senior Secured Credit Facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. A failure to comply with the provisions of the Senior Secured Credit Facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

We are not permitted to borrow additional funds under the Senior Secured Credit Facility and as such, it is not a source of liquidity for us.

We reimburse Armstrong Energy and its affiliates for expenses.

We reimburse Armstrong Energy and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Armstrong Energy determines the expenses that are allocable to us in any reasonable manner determined by Armstrong Energy in its sole discretion.

Armstrong Energy intends to limit its liability regarding our obligations.

Armstrong Energy intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against Armstrong Energy or its assets. The Partnership Agreement 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

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.

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 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

deciding whether to invest in our common units. The following risks are discussed in more detail in “Risk Factors” beginning on page 23:


	•	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.

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.

The following unaudited pro forma consolidated financial data of Armstrong Resource Partners, L.P. at March 31, 2012, for the three months ended March 31, 2012, and for the year ended December 31, 2011 are derived from our unaudited pro forma financial information, which is included elsewhere in this prospectus.

The unaudited pro forma consolidated balance sheet data at March 31, 2012 gives effect to the issuance of common units in this offering and the application of the net proceeds therefrom as described in “Use of Proceeds,” as if it had occurred on March 31, 2012. The unaudited pro forma consolidated financial data for the three months ended March 31, 2012 and the fiscal year ended December 31, 2011 gives effect to the financial impact for the acquisition of additional reserves from Armstrong Energy with the proceeds from this offering and the subsequent leasing of those reserves back to Armstrong Energy, as if each had occurred on January 1, 2011.

Historical results and unaudited pro forma consolidated financial information are for illustrative and informational purposes only and are not necessarily indicative of results we expect in future periods. You should read the following summary and unaudited pro forma financial data in conjunction with “Selected Historical Consolidated Financial and Operating Data,” “Unaudited Pro Forma Financial Information” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus.


																Pro Forma
																Year
										Three Months						Ended			Three Months
	Year Ended December 31,									Ended March 31,						December 31,			Ended March 31,
	2009			2010			2011			2011			2012			2011			2012
										(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands, except per unit amounts)

Results of Operations Data
Total revenue	$	—		$	—		$	7,789		$	1,238		$	3,081		$	9,148		$	3,449
Costs and expenses		330			817			7,605			802			4,717			8,633			4,999

Operating income (loss)		(330	)		(817	)		184			436			(1,636	)		515			(1,550	)
Interest expense		(1,723	)		—			—			—			—			—			—
Interest income		161			4,209			1,009			1,009			—			1,009			—
Other income (expense), net		(2	)		(60	)		1,148			162			256			1,148			256

Net income (loss)	$	(1,894	)	$	3,332		$	2,341		$	1,607		$	(1,380	)	$	2,672		$	(1,294	)

Earnings (loss) per limited partner unit, basic, without giving effect to the unit split	$	(2.62	)	$	2.96		$	1.74		$	1.20		$	(1.02	)	$	1.65		$	(0.80	)

Earnings (loss) per limited partner unit, diluted, without giving effect to the unit split	$	(2.62	)	$	2.96		$	1.73		$	1.20		$	(1.02	)	$	1.65		$	(0.80	)

Earnings (loss) per limited partner unit, basic and diluted, assuming unit split(1)	$	(0.34	)	$	0.39		$	0.23		$	1.60		$	(0.13	)	$	0.22		$	(0.10	)

Balance Sheet Data (at period end)
Total assets	$	91,097		$	137,929		$	167,559		$	144,623		$	166,037		$	185,059		$	183,537
Working capital		215			155			619			155			651			619			651
Total debt		—			—			—			—			—			—			—
Total partners’ capital		89,497			125,929			156,181			132,536			155,278			173,681			172,778
Other Data
Royalty coal tons sold by lessee (unaudited)		—			—			2,717			458			1,012			3,199			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			9,444			3,454
EBITDA is calculated as follows (unaudited):
Net income (loss)	$	(1,894	)	$	3,332		$	2,341		$	1,607		$	(1,380	)	$	2,673		$	(1,294	)
Depletion		—			—			3,841			614			1,555			4,869			1,837
Unit compensation expense		—			—			2,911			—			2,911			2,911			2,911
Interest, net		1,562			(4,209	)		(1,009	)		(1,009	)		—			(1,009	)		—

	$	(332	)	$	(877	)	$	8,084		$	1,212		$	3,086		$	9,444		$	3,454


(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.

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.

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.

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

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

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.

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

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

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

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.

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.”

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.

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.”

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

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.

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.”

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

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.

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

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.”

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.

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

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

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;


	•	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.

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;


	•	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.

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,

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

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.”

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

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.

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;


	•	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.”

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 he 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 partial undivided interest in substantially all of the coal reserves and real property owned by Armstrong Energy previously subject to options exercised by us on February 9, 2011. If this offering is completed and the net proceeds are applied in this manner, we expect to have a 58.54% undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves, excluding the Union/Webster Counties reserves. See “Certain Relationships and Related Party Transactions — Western Diamond and Western Land Coal Reserves Sale Agreement.” Armstrong Energy intends to use the proceeds of the sale of the partial undivided interest to us to repay a portion of Armstrong Energy’s outstanding borrowings under the Senior Secured Revolving Credit Facility.

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 and the application of the net proceeds from this offering as described under “Use of Proceeds”.

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Selected Historical Consolidated Financial and Operating Data,” “Unaudited Pro Forma Financial Information,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	As of March 31, 2012
			Pro-Forma As
	Actual		Adjusted(1)(2)
	(unaudited)
	(In thousands)

Cash and cash equivalents	$	155	$	155

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).

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 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 (all unit and per unit amounts give effect to an assumed 7.6047-to-1 unit split to be effected prior to the effectiveness of the registration statement of which this prospectus forms a part):


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.

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.

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).

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma consolidated financial statements of Armstrong Resource Partners, L.P. at March 31, 2012, for the year ended December 31, 2011, and the three months ended March 31, 2012, are based on the historical consolidated financial statements of Armstrong Resource Partners, L.P., which are included elsewhere in this prospectus.

The unaudited pro forma consolidated balance sheet at March 31, 2012 gives effect to the issuance of common units in this offering, the conversion of the 200,000 units of the Series A convertible preferred units into 1,068,376 common units, and the application of the net proceeds therefrom as described in “Use of Proceeds,” as if each had occurred on March 31, 2012. The unaudited pro forma consolidated statements of operations for the fiscal year ended December 31, 2011 and the three months ended March 31, 2012 give effect to the financial impact for the acquisition of additional reserves from Armstrong Energy with the proceeds from this offering, the subsequent leasing of those reserves back to Armstrong Energy, and, the conversion of the 200,000 units of the Series A convertible preferred units into 1,068,376 common units, as if each had occurred on January 1, 2011.

The unaudited pro forma financial statements of Armstrong Resource Partners, L.P. exclude all federal and state income taxes as income taxes will be the responsibility of the unitholders and not of Armstrong Resource Partners, L.P.

This unaudited pro forma consolidated financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes related to those consolidated financial statements included elsewhere in this prospectus.

Our unaudited pro forma adjustments are based on available information and certain assumptions that we believe are reasonable. Presentation of our unaudited pro forma consolidated financial and operating data is prepared in conformity with Article 11 of Regulation S-X. The unaudited pro forma consolidated financial and operating data is included for illustrative and informational purposes only and is not necessarily indicative of results we expect in future periods.

Unaudited Pro Forma Consolidated Statement of Operations
For the Year Ended December 31, 2011


	As Reported
	for the Year					Pro Forma
	Ended		Adjustments			for the Year
	December 31,		Related to this			Ended
	2011		Offering			December 31, 2011
	(Dollars in thousands, except per unit amounts)

Revenue	$	7,789	$	1,359	(A)	$	9,148
Costs and expenses:
Legal, accounting, and other professional services		133		—			133
Related-party service expense		720		—			720
Depletion		3,841		1,028	(B)		4,869
Unit compensation expense		2,911		—			2,911

Operating income		184		331			515
Other income (expense)
Interest income		1,009		—			1,009
Interest expense		—		—			—
Other income		1,148		—			1,148

Net income	$	2,341	$	331		$	2,672

Net income attributable to:
General partner	$	9	$	1		$	10

Limited partners	$	2,332	$	330		$	2,662

Pro forma net income per limited partner unit
Basic						$	0.22

Diluted						$	0.22

Pro forma weighted average number of units outstanding
Basic							12,251

Diluted							12,297


(A)		Relates to royalty revenue earned for the year ended December 31, 2011 on the 6.84% interest in the reserves of Armstrong Energy acquired from proceeds from this offering and subsequently leased back to Armstrong Energy.


(B)		Relates to depletion expense for the year ended December 31, 2011 on the 6.84% interest in the reserves of Armstrong Energy acquired from the proceeds from this offering.

Unaudited Pro Forma Condensed Consolidated Balance Sheet
As of March 31, 2012


						Adjustments
						Related to
	As Reported		Adjustments			the Series A			Pro Forma
	as of March 31,		Related to the			Convertible			as of March 31,
	2012		Offering			Preferred Stock			2012
	(Dollars in thousands)

Assets
Current assets:

Cash and cash equivalents	$	155	$	—		$	—		$	155
Other assets		496		—			—			496

Total current assets		651		—			—			651
Property, plant, equipment, and mine development, net		165,386		17,500	(C)		—			182,886
Related party notes receivable		—		—			—			—
Related party other receivables, net		—		—			—			—

Total assets	$	166,037	$	17,500		$	—		$	183,537

Liabilities and partners’ capital
Other non-current liabilities	$	10,420	$	—		$	—		$	10,420
Related party other payables, net		339		—			—			339

Total liabilities		10,759		—			—			10,759
Partners’ capital:
Series A Preferred Units		20,000		—			(20,000	)(E)		—
Limited partners’ capital		134,877		17,500	(D)		20,000	(E)		172,377
General partners’ capital		401		—			—			401

Total partners’ capital		155,278		17,500			—			172,778

Total liabilities and partners’ capital	$	166,037	$	17,500		$	—		$	183,537


(C)		Relates to a 7.73% undivided interest in land and mineral reserves acquired from Armstrong Energy with the proceeds from this offering.


(D)		Reflects the adjustments to limited partners’ capital for the public offering of the Partnership’s common units as follows (dollars in thousands):


Proceeds from this offering(1)	$	20,000
Less: estimated fees and expense related with this offering		(2,500	)

Net proceeds from this offering	$	17,500


(1)		To reflect the issuance of of the Partnership’s common units offered hereby at an assumed initial public offering price of $ per unit (the midpoint of the range set forth on the cover of this prospectus).


(E)		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).

Unaudited Pro Forma Consolidated Statement of Operations
For the Three Months Ended March 31, 2012


	As Reported for the			Adjustments			Pro Forma for the
	Year Ended			Related to			Year Ended
	March 31, 2012			the Offering			March 31, 2012
	(Dollars in thousands, except per unit amounts)

Revenue	$	3,081		$	368	(F)	$	3,449
Costs and Expenses:
Depletion		1,555			282	(G)		1,837
Related-party service expense		188			—			188
Other operating, general, and administrative costs		63			—			63
Unit-based compensation expense		2,911			—			2,911

Operating income		(1,636	)		86			(1,550	)
Other Income (Expense)
Interest income		—			—			—
Interest expense		—			—			—
Other income, net		256			—			256

Net income	$	(1,380	)	$	86		$	(1,294	)

Net income attributable to:
General partner	$	(5	)	$	—		$	(5	)

Limited partners	$	(1,375	)	$	86		$	(1,289	)

Pro forma net income per limited partner unit
Basic							$	(0.10	)

Diluted							$	(0.10	)

Pro forma weighted average number of units outstanding
Basic								12,274

Diluted								12,274


(F)		Relates to royalty revenue earned for the three months ended March 31, 2012 on the 6.84% interest in the reserves of Armstrong Energy acquired from proceeds from this offering and subsequently leased back to Armstrong Energy.


(G)		Relates to depletion expense for the three ended months ended March 31, 2012 on the 6.84% interest in the reserves of Armstrong Energy acquired from the proceeds from this offering.

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	)
Depreciation, depletion and amortization		—			—			—			3,841			614			1,555
Unit 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.


(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.

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.

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.

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.

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.

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.

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.

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.

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

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 50.81% undivided interest in the reserves of Armstrong Energy.

Seasonality

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 68% of global coal consumption (2008) while industrial consumption accounts for nearly 36% of global coal production. Thermal coal’s abundance and relatively wide in-situ global resource distribution have contributed to its relative ease of availability and competitive cost versus other electricity generating fuels. Global thermal coal trade is expected to grow to 1.1 billion annual tons in 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 86% 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.

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.


	•	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.

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 935 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

Effective

Utility Name

Plant Name

State

County

Region

Nameplate

Year

Virginia Electric & Power Co.

Virginia City Hybrid Energy Center

Wise

RFC

585

2012

Duke Energy Carolinas LLC

Cliffside

Cleveland

SERC

800

2011

Duke Energy Indiana Inc.

Edwardsport (IGCC)

Knox

RFC

618

2011

Cash Creek Generating LLC

Cash Creek (Coal Gasification)

Henderson

SERC

640

2011

GenPower

Longview Power LLC

Monongalia

RFC

695

2011

Louisiana Gas & Electric

Trimble County

Trimble

SERC

834

2010

City Utilities of Springfield

Southwest Power Station

Greene

SERC

300

2010

Dynegy Services Plum Point Inc.

Plum Point Energy Station

Mississippi

SERC

665

2010

Source: EIA

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.

Long-Term U.S. Thermal Coal Outlook — Fall 2011: Summary Table of Key Data
(tons in millions)


	2012		2013		2014		2015		2020		2025		2030

Supply (Mst)		1,109		1,113		1,108		1,145		1,139		1,179		1,240

Powder River Basin		487		483		486		508		481		508		552
Central Appalachia		89		76		64		64		46		56		71
Illinois Basin		130		144		157		167		204		216		224
Northern Appalachia		121		129		134		136		132		125		124
Metallurgical (not including Thermal Cross Over)		84		82		69		70		81		87		93
Imports		8		5		3		3		5		5		5
Other (including Refuse or Petcoke)		190		195		196		197		—		181		171
Stockpile Increase (Decrease)		—		—		—		—		190		—		—

Demand (Mst)		1,109		1,113		1,108		1,145		1,139		1,179		1,240

Electricity Generation		942		942		967		985		954		837		794
Industrial		52		51		52		52		53		54		54
Thermal Export		32		38		21		38		52		200		299
Metallurgical Demand (includes Thermal Cross Over)		84		82		69		70		81		87		93

Source: Wood Mackenzie Long Term US Thermal Coal Market Outlook, October 2011

Wood Mackenzie estimates that demand for Illinois Basin coal will grow at a compound annual rate of 3.7%, taking total consumption from 117 million tons in 2012 to more than 225 million tons by 2030. This is compared to total U.S. coal production, which Wood Mackenzie estimates will grow at a compound annual rate of 0.6% over the same period. Importantly, Illinois Basin coal production is projected to grow more sharply over the 2012-2020 period (5.8% CAGR) than over the latter part of the 20-year projection period.

Conversely, Wood Mackenzie estimates that Central Appalachian thermal coal production has declined from 217 million tons in 2000 to 115 million tons in 2011, while Northern Appalachian coal production has had only minor fluctuations.

Global Thermal Coal Markets

Global coal production accounted for 30% of global primary energy consumption in 2010, according to BP.

2010 Global Primary Energy Consumption by Fuel

Source: BP Statistical Review of World Energy, June 2011

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/

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.

U.S. Coal Producing Regions

Coal is mined from coal basins throughout the United States, with the major production centers located in three regions: Appalachia, the Interior and the Western region. Within those three regions, the major producing centers are Northern and Central Appalachia, the Illinois Basin in the Interior region, and the Powder River Basin in the Western region. The type, quality and characteristics of coal vary by, and within each, region.

Appalachian Region. The Appalachian region is divided into the Northern, Central and Southern regions, with the Northern and Central areas being the largest coal producers in the region. Northern Appalachia includes Ohio, Pennsylvania, Maryland and northern West Virginia. The area includes reserves of bituminous coal with heat content ranging from 10,300 to 13,000 Btu/lb) and sulfur content ranging from 1.0% to 2.0%. Coal produced in Northern Appalachia is marketed primarily to electric utilities, industrial consumers and the export market, with some metallurgical coal marketed to steelmakers.

Central Appalachia includes eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The area includes reserves of bituminous coal with a typical heat content of 12,000 Btu/lb or greater and sulfur content ranging from 0.5% to 1.5%. Coal produced in Central Appalachia is marketed primarily to electric utilities, with metallurgical coal marketed to steelmakers. The combination of reserve depletion and increasing regulatory enforcement, mining costs and geologic complexity in Central Appalachia is expected to lead to substantial production declines over the long term. In fact, actual total production has declined from approximately 257 million tons in 2000 to 186 million tons in 2010. In addition, the widespread installation of scrubbers is expected to enable higher sulfur coal from Northern Appalachia and the Illinois Basin to displace coal from Central Appalachia.

Interior Region. The major coal producing center of the Interior region is the Illinois Basin, which includes Illinois, Indiana and western Kentucky. The area includes reserves of bituminous coal with a heat

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

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.

BUSINESS

Overview

Royalty Business

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.

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.

About the Partnership

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, plus any amount owed to us at the time of the Concurrent AE Offering (see “— Concurrent Offering”) for deferred royalty payments, to purchase an additional interest in the reserves in which we currently have a 50.81% interest. See “Prospectus Summary — Business Developments” and “Certain Relationships and Related Party Transactions — Membership Interest Purchase Agreement.” As a result, following the closing of this offering and the Concurrent Offering, we expect to have an approximate 58.54% undivided interest as a joint tenant in common with Armstrong Energy in the majority of Armstrong Energy’s coal reserves which could be increased as a result of an additional acquisition through the offset of unpaid deferred royalties owed to us.

We are a co-borrower under Armstrong Energy’s $100.0 million Senior Secured Term Loan and a guarantor on the $50.0 million Senior Secured Revolving Credit Facility and the Senior Secured Term Loan. Substantially all of our assets and Armstrong Energy’s assets are pledged to secure borrowings under the Senior Secured Credit Facility. Under the terms of the Senior Secured Credit Facility, without the consent of all lenders (if there are fewer than three lenders at the time of any dividend or distribution) or the lenders having more than 50% of the aggregate commitments (if there are three or more lenders at the time of any dividend or distribution) under that facility, we are currently prohibited from making dividend payments or other distributions to our unitholders in excess of $5.0 million per year and $10.0 million in aggregate, except for dividends or other distributions in amounts necessary to enable unitholders to pay anticipated income tax liabilities arising from their ownership interests in the Partnership until February 9, 2016, the date on which the Senior Secured Credit Facility matures. We are not permitted to borrow additional funds under the Senior Secured Credit Facility and as such, it is not a source of liquidity for us.

We expect Armstrong Energy to continue to defer royalty payments from Armstrong Energy and not pay distributions to any of our unitholders, except for amounts necessary to enable unitholders to pay anticipated income tax liabilities, which will be paid, if at all, solely at the discretion of Elk Creek, GP, our general partner, for the foreseeable future. As a result, we will continue to accrue an increasing percentage undivided interest in Armstrong Energy’s coal reserves for the foreseeable future.

A wholly owned subsidiary of Armstrong Energy, Inc., Elk Creek GP, is our general partner. Pursuant to our Partnership Agreement, Elk Creek GP has the exclusive authority to conduct, direct and manage all of our activities. By virtue of Armstrong Energy’s control of Elk Creek, GP, our results are consolidated in Armstrong Energy’s historical consolidated financial statements. Pursuant to our Existing Partnership Agreement, effective October 1, 2011, Yorktown unilaterally may remove Elk Creek GP as our general partner in some circumstances. As a result, Armstrong Energy will no longer consolidate our results in its financial statements (the “Deconsolidation”).

2011 was the first year production occurred under our leases to Armstrong Energy. Based on its coal production 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.

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.


	•	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.


(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) and Armstrong Energy (with a 49.19% undivided interest). If this offering and the Concurrent AE Offering and related transactions are completed, the undivided interest of Armstrong Resource Partners will increase, and the undivided interest of Armstrong Energy will decrease, based on the net proceeds of this offering paid to Armstrong Energy and the value of the affected reserves as agreed by Armstrong Resource Partners and Armstrong Energy. See “Certain Relationships and Related Party Transactions — Concurrent Transactions with Armstrong Energy.”

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.


(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 58.54% undivided interest) and Armstrong Energy (with a 41.46% undivided interest), assuming an offering price of $ per unit, the midpoint of the price range set forth on the front cover page of this prospectus and an estimated purchase price of $17.5 million for our additional interest in the partially owned reserves.

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

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.

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.

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 March 31, 2012, of Armstrong Energy, Inc.’s total controlled reserves of 326 million tons, 65 million tons (20%) are wholly owned by us, and 140 million tons (43%) are held by Armstrong Energy and us as joint tenants-in-common with 49.19% and 50.81% interests, respectively, and the balance of the reserves Armstrong Energy controls are leased by Armstrong Energy from a third party, but are not included in Armstrong Resource Partners’ option to purchase an additional interest.

Armstrong Energy markets its coal primarily to electric utility companies as fuel for their steam-powered generators. Based on 2011 production, Armstrong Energy is the sixth largest producer in the Illinois Basin and the second largest in Western Kentucky. It commenced production in the second quarter of 2008 and currently operates seven mines, including five surface and two underground mines. In addition, Armstrong Energy is seeking permits for three additional mines. Permit applications for the Hickory Ridge surface mine have been submitted to the Corps and the State of Kentucky but have yet to be issued. Armstrong Energy is also in the process of preparing permit applications relating to Ken surface mine and the Lewis Creek underground mine. Armstrong Energy intends to submit those permit applications to the Corps and the State of Kentucky beginning in the spring of 2012. Since beginning operations in 2007, Armstrong Energy’s revenue has grown to $299.3 million in 2011. During the year ended December 31, 2011, it produced 6.6 million tons of coal, with seven mines in operation, and currently expects a significant increase in its production for 2012 compared to 2011. The majority of the foregoing production is derived from coal reserves in which we obtained an undivided interest during 2011 and that Armstrong Energy now leases from us.

Business Developments

On February 9, 2011, Armstrong Energy entered into lease agreements with us pursuant to which we granted Armstrong Energy leases to our 39.45% undivided interest in the mining properties described above and licenses to mine coal on those properties. The initial term of each such agreement is ten years, and will automatically extend for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or such agreement is terminated upon proper

notice. Armstrong Energy is obligated to pay us a production royalty equal to 7% of the sales price of the coal which Armstrong Energy mines from our properties. Under the terms of these agreements, we retain surface rights to use the properties containing these reserves for non-mining purposes. Events of default under the lease agreements include the failure by Armstrong Energy to pay royalty payments to us when due and a default by Armstrong Energy under any agreement, indenture or other obligation to any creditor that, in our opinion, may have a material adverse effect on Armstrong Energy’s ability to meet its obligations under the lease agreements. If any event of default occurs and is not cured by Armstrong Energy, then we can terminate one or more of the lease agreements. In addition, Armstrong Energy has agreed to indemnify us from and against any and all claims, damages, demands, expenses, fines, liabilities, taxes and any other losses related in any way to Armstrong Energy’s mining operations on such premises, and to reclaim the surface lands on such premises in accordance with applicable federal, state and local laws.

Effective February 9, 2011, Armstrong Energy entered into an agreement with us pursuant to which we granted Armstrong Energy the option to defer payment of the 7% production royalty described above. In consideration for the granting of the option to defer these payments, Armstrong Energy granted us the option to acquire an additional partial undivided interest in certain of the coal reserves held by Armstrong Energy in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which Armstrong Energy would satisfy payment of any deferred fees by selling to us part of its interest in the aforementioned coal reserves to us at fair market value for such reserves determined a the time of the exercise of such option.

Based upon Armstrong Energy’s current estimates of production for 2012 and 2013, we anticipate that Armstrong Energy will owe us royalties under the above-mentioned license and lease arrangements of approximately $14.8 million and $20.0 million in 2012 and 2013, respectively, of which collectively, $11.4 million will be recoupable against the advance royalty payment referred to above.

In December 2011, we sold 200,000 Series A convertible preferred units of limited partner interest to Yorktown in exchange for $20.0 million. Also in December 2011, we entered into a Membership Interest Purchase Agreement with Armstrong Energy pursuant to which Armstrong Energy agreed to sell to us, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of its membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. In exchange for Armstrong 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 Armstrong Resource Partners. We agreed to lease the newly transferred mineral reserves to Armstrong Energy on the same terms as the February 2011 lease.

Our Lessee’s Mining Operations

Armstrong Energy currently operates seven active mines, all of which relate to our coal reserves and are located in the Illinois Basin coal region in western Kentucky. Its operations are composed of five surface

mines and two underground mines, with three preparation plants serving these operations. In addition, Armstrong Energy is seeking permits for three additional mines. Permit applications for the Hickory Ridge surface mine have been submitted to the Corps and the State of Kentucky but have yet to be issued. Armstrong Energy is also in the process of preparing permit applications relating to Ken surface mine and the Lewis Creek underground mine. Armstrong Energy intends to submit those permit applications to the Corps and the State of Kentucky beginning in the spring of 2012. In 2011, approximately 72% of the coal that Armstrong Energy produced came from its surface mining operations.

Armstrong Energy’s current operating mines are all located in Muhlenberg and Ohio Counties, Kentucky. The Western Kentucky Parkway crosses its properties from Southwest to Northeast, and the Green River separates its properties in Ohio and Muhlenberg Counties. Armstrong Energy’s barge loading facility on the Green River is located near the town of Kirtley, Kentucky. In addition, it has a network of off-highway truck haul roads, which connect the majority of its active mines and provide access to its barge loading and rail loadout facilities.

The following map shows the locations of Armstrong Energy’s mining operations and coal reserves:

In general, Armstrong Energy has developed its mines and preparation plants at strategic locations in close proximity to rail or barge shipping facilities. Coal is transported from its mines to customers by means of railroads, trucks, and barge lines. Armstrong Energy currently owns or leases under long-term arrangements a substantial portion of the equipment utilized in its mining operations. Armstrong Energy employs sophisticated preventative maintenance and rebuild programs and upgrades its equipment to ensure that it is productive, well-maintained and cost-competitive. Its maintenance programs also employ procedures designed to enhance the efficiencies of its operations.

We currently wholly own approximately 65 million tons of coal reserves and have a 50.81% undivided interest in approximately 140 million tons of coal reserves, all located in Ohio and Muhlenberg Counties in Western Kentucky.

Armstrong Energy has entered into leases with Western Mineral, our wholly owned subsidiary, and Western Land Company, LLC (“Western Land”) and Western Diamond, LLC (“Western Diamond”), each of which is a wholly-owned subsidiary of Armstrong Energy, for the reserves described above, excluding the Elk Creek Reserves. Those leases are for a term of ten years but can be renewed for an additional ten-year term or

until all of the mineable and merchantable coal has been mined. The leases provide for a 7% production royalty payment to be paid by Armstrong Energy to the lessors.

Effective February 9, 2011, Armstrong Energy, Western Diamond and Western Land entered into a Royalty Deferment and Option Agreement with Western Mineral. Pursuant to this agreement, Western Mineral agreed to grant to Armstrong Energy and its affiliates the option to defer payment of Western Mineral’s pro rata share of the 7% production royalty described under “— Lease Agreements” below. In consideration for Western Mineral’s granting of the option to defer these payments, Armstrong Energy and its affiliates granted to Western Mineral the option to acquire an additional partial undivided interest in certain of the coal reserves held by Armstrong Energy in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which Armstrong Energy and its affiliates would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves.

On October 11, 2011, Western Diamond and Western Land (together, the “Sellers”) entered into an agreement with Western Mineral pursuant to which the Sellers agreed to sell an additional partial undivided interest in substantially all of the coal reserves and real property owned by the Sellers previously subject to the options exercised by Armstrong Resource Partners on February 9, 2011 (see “Certain Relationships and Related Party Transactions — Sale of Coal Reserves”), other than any of Sellers’ real property and related mining rights associated with the Parkway mine. Such interest shall be equal to a fraction, the numerator of which shall be equal to the amount of net proceeds received by Western Mineral and/or its parents or affiliates from this offering, and the denominator of which is a dollar amount the parties agree represents the aggregate fair market value of the property. The closing of the sale, which is conditioned on the closing of this offering, shall occur on or before 90 days after Western Mineral and/or its parents or affiliates receives the net proceeds of this offering.

We also lease the Elk Creek Reserves to Armstrong Energy, and the terms of that lease mirror the leases described above. The Elk Creek Reserves lease also recognizes and permits Armstrong Energy to recoup $12.0 million in previously paid advance royalties against production royalties as they come due, subject to certain limitations.

Big Run Mine. The Big Run mine was an underground mine located near Centertown, Kentucky that was previously operated by Peabody Energy. In October 2011, production at the Big Run mine ceased and the equipment that had been used to extract thermal coal from the West Kentucky #9 seam was relocated to the Kronos mine. The Big Run mine produced approximately 0.4 million clean tons of coal in 2011, which was processed at Armstrong Energy’s Midway Preparation Plant.

Midway Mine. The Midway mine is a surface mine located two miles southeast of Centertown, Kentucky in Ohio County and is west of and adjacent to the Midway Preparation Plant. The Midway mine commenced production in April 2008 and extracts thermal coal from the West Kentucky #13a, #13, and #11 seams. Stripping ratios for coal that has not undergone any processing, or “run-of-mine” coal, at the Midway mine are favorable and averaged approximately 11-to-1 in 2011. The Midway mine produced approximately 1.6 million tons of clean coal in 2011 and is currently equipped with one dragline (45 yard bucket) and a spread of surface mining equipment, including power shovels, excavators, loaders and haul trucks. Our reserve studies have indicated that the Midway mine has approximately 21 million tons of proven and probable reserves. Coal from the Midway mine is transported less than one mile to the Midway Preparation Plant for processing, where it is then shipped to customers via truck, rail or barge.

Parkway Mine. The Parkway mine is an underground mine located northeast of Central City, Kentucky in Muhlenberg County that extracts thermal coal primarily from the West Kentucky #9 seam and accesses that seam from an older surface mining pit that was abandoned prior to our acquisition of Parkway. The Parkway mine consists of two working super sections, and each section is currently equipped with two continuous miners that operate concurrently. The Parkway mine produced approximately 1.5 million tons of clean coal in 2011. As a result of a reserve acquisition in December 2011, the Parkway mine currently has approximately 13.0 million tons of proven and probable reserves. See “— Business Developments.” The majority of the coal from the Parkway mine is transported to the surface stockpile where it is processed at the Parkway Preparation Plant and trucked to a single customer via a seven mile private haul road.

East Fork Mine. The East Fork mine is a surface mine located three miles west of Centertown, Kentucky. The East Fork complex consists of two pits, the Warden and Kronos pits, which extract thermal coal from the West Kentucky #14 seam. The Kronos pit commenced operations in June 2009, and the Warden pit commenced operations in August 2009. The East Fork mine produced approximately 0.7 million tons of clean coal in 2011, and there were approximately 2.8 million tons of proven and probable reserves at the East Fork mine at December 2011. Production at the Kronos pit ceased in August 2011. East Fork run-of-mine coal is trucked 3.6 miles to the Armstrong Dock Preparation Plant via a private haul road where it is processed, blended and shipped to customers.

Equality Boot Mine. The Equality Boot mine is a surface mining operation located eight miles southwest of Centertown, Kentucky, which commenced operations in September 2010. The Equality Boot mine extracts thermal coal from the West Kentucky #14, #13, #12 and #11 seams and produced approximately 1.9 million tons of coal in 2011. The Equality Boot mine uses two draglines equipped with 45 yard buckets and a spread of surface equipment, including power shovels, excavators, loaders and haul trucks to remove overburden and interburden and construct the dragline bench. Run-of-mine stripping ratios at the Equality Boot mine averaged approximately 13.5-to-1 in 2011. The Equality Boot mine has approximately 23 million tons of proven and probable reserves. Coal from the Equality Boot mine is transported less than one mile by truck to the Equality Boot run-of-mine facility, where a 4,400 foot overland conveyor system is used to transport the coal to the 2,500 tons per hour barge loadout facility located on the Green River. The coal is then loaded onto barges and transported approximately 5 miles to the Armstrong Dock Preparation Plant where it is unloaded, processed, reloaded onto barges and then shipped to its customers.

Lewis Creek Mine. The Lewis Creek mine is a surface mine located approximately five miles south of Centertown, Kentucky and approximately 3.5 miles from the Midway Preparation Plant. Production commenced in June 2011 at the Lewis Creek mine, and thermal coal is being mined from the West Kentucky

seams #13A and #13. The Lewis Creek mine produced approximately 0.5 million tons of clean coal in 2011. A dragline equipped with a 20 yard bucket is used in conjunction with mobile mining equipment to remove overburden and construct the dragline bench at Lewis Creek. There are approximately 6 million tons of proven and probable reserves at the Lewis Creek surface mine. Coal mined at the Lewis Creek mine is transported by truck to the Midway Preparation Plant for processing and subsequent delivery to our customers.

Kronos Mine. The Kronos mine, which commenced operations in September 2011, is an underground mine located approximately three miles southwest of Centertown, Kentucky. It extracted thermal coal from the West Kentucky #9 seam. While the Kronos mine produced approximately 0.2 million tons of coal in 2011 that production was capitalized and not included in our results of operations because the mine was still in the developmental phase. The mine currently utilizes three continuous miner super sections, but we expect to increase to four super sections in mid-2012. At that time, we expect that the mine’s annual production will be 2.3 million tons. There are approximately 22 million tons of proven and probable reserves at the Kronos mine. Coal mined at Kronos is transported by truck to the Midway Preparation Plan and the Armstrong Dock Preparation Plant for processing and delivery.

Maddox Mine. The Maddox mine is a surface mine located two miles southeast of Centertown, Kentucky, in Ohio County. The Maddox mine commenced production in November 2011 and extracts thermal coal from the West Kentucky #13a, #13 and #11 seams. The Maddox mine produced approximately 25,000 tons of clean coal in 2011 and is currently equipped with a spread of surface mining equipment. Our reserve studies have indicated that the Maddox mine has approximately 0.5 million tons of proven and probable reserves. Coal from the Maddox mine is transported to the Midway Preparation Plant for processing, where it is then shipped to customers via truck, rail or barge.

Future Underground Mine. Armstrong Energy anticipates opening the Lewis Creek underground mine in 2013, assuming that it receives all necessary permits for operation of that mine. The Lewis Creek mine will produce coal from the West Kentucky #9 seam utilizing two continuous miner super sections operating concurrently. Once fully operational, the Lewis Creek underground mine is projected to produce approximately 1.3 million tons of clean coal per year. There are approximately 22 million tons of proven and probable reserves at the Lewis Creek reserves.

Future Surface Mines. Armstrong Energy anticipates opening the Hickory Ridge and Ken surface mines in 2013 and 2014. These surface mines will produce thermal coal from primarily the West Kentucky #14, #13, #13A and #11 seams. Conventional truck-and-shovel operations are anticipated to be used at all of the mines. The Hickory Ridge and Ken surface mines have approximately 23 million tons in the aggregate of proven and probable reserves.

Coal Preparation Facilities

The majority of coal from each of Armstrong Energy’s mining operations is processed at a coal preparation plant located near the mine or connected to the mine by an overland conveyor system. Currently, Armstrong Energy has three preparation plants, Midway, Parkway and Armstrong Dock. These coal preparation plants allow Armstrong Energy to treat the coal it extracts from our reserves to ensure a consistent quality and to enhance its suitability for particular end-users. In 2011, Armstrong Energy’s preparation plants processed approximately 99% of the raw coal Armstrong Energy produced. In addition, depending on coal quality and customer requirements, Armstrong Energy may blend coal mined from different locations in order to achieve a more suitable product. At the current time, our lessee’s preparation plants do not process coal from other companies, and Armstrong Energy does not have any present intention to do so.

The following chart provides information regarding Armstrong Energy’s preparation plants:


	Midway	Parkway	Armstrong Dock

Location:	Centertown, Kentucky	Central City, Kentucky	Centertown, Kentucky
Inception:	July 2008	April 2009	March 2010
Mines Serviced:	Midway, Maddox, Lewis Creek	Parkway	East Fork, Equality Boot, Kronos
Tons Per Hour:	600 — Expandable to 1,200	400	1,200
Loadout Tons Per Hour:	2,500 (Rail)	—	2,500 (Barge)
Transportation:	Rail, Truck	Truck	Barge

The Midway Plant is 600 tons-per-hour (“TPH”) raw coal feed, heavy media preparation plant that was constructed in 2008. The plant is connected to the P&L Railroad via a newly-constructed unit train railroad “loop” extension of approximately 16,000 feet, and also includes a coal handling system similar to that present at the Armstrong Dock Plant that permits the loading of coal into railcars or trucks. With additional capital expenditures, the Midway Plant is currently being expanded to 1,200 TPH. We expect the expansion to be completed by summer 2012.

The Parkway Preparation Plant is located adjacent to the Parkway mine and has a run-of-mine capacity of 400 TPH. Clean coal from the preparation plant is placed in a 60,000 ton capacity stockpile and subsequently loaded into trucks for delivery to customers.

The Armstrong Dock Plant is a 1200 TPH raw coal feed, heavy media preparation plant that was constructed in 2008. The plant is connected to a newly-refurbished 10,000 ton “donut” storage stockpile and an extensive conveyor handling system. The Armstrong Dock Plant has a coal handling system that permits the loading of coal into barges adjacent to the dock conveyor or into trucks adjacent to the plant itself.

The treatments Armstrong Energy employs at its preparation plants depend on the size of the raw coal. For coarse material, the separation process relies on the difference in the density between coal and waste rock where, for the very fine fractions, the separation process relies on the difference in surface chemical properties between coal and the waste minerals. To remove impurities, Armstrong Energy crushes raw coal and classifies it into various sizes. For the largest size fractions, Armstrong Energy uses dense media vessel separation techniques in which it floats coal in a tank containing a liquid of a pre-determined specific gravity. Since coal is lighter than its impurities, it floats, and can be separated from rock and shale. Armstrong Energy treats intermediate sized particles with dense medium cyclones, in which a liquid is spun at high speeds to separate coal from rock. Fine coal is treated in spirals, in which the differences in density between coal and rock allow them, when suspended in water, to be separated. Ultra fine coal is recovered in column flotation cells utilizing the differences in surface chemistry between coal and rock. By injecting stable air bubbles through a suspension of ultra fine coal and rock, the coal particles adhere to the bubbles and rise to the surface of the column where they are removed. To minimize the moisture content in coal, Armstrong Energy processes most coal sizes through centrifuges. A centrifuge spins coal very quickly, causing water accompanying the coal to separate. Coarse refuse from Armstrong Energy’s preparation plants is back-hauled and disposed of in its mining pits or other locations in accordance with applicable regulations and permits.

Our Coal Leases and Royalty Revenues

We earn our coal royalty revenues under multi-year leases that generally require our lessee to make payments to us currently based on 7% of the gross sales price of the aggregate tons of coal sold. Currently, we lease all of our coal reserves to Armstrong Energy. Each of our leases with Armstrong Energy is identical, save for the specific property being leased, except for the Elk Creek lease. For a description of the terms of our leases, see “Business — Overview — Royalty Business” and “— Coal Leases.”

In Muhlenberg County, we have four leases with Armstrong Energy, each dated February 9, 2011, which concern the following general reserve areas: (a) Jacob’s Creek, Sunnyside (part), Hillside, Cypress Creek and

Nelson Creek (part); (b) Nelson Creek (part) and Sunnyside (part); (c) Parkway (part); and (d) Vogue (part), Game Preserve and Paradise #9.

In Ohio County, we have eleven leases with Armstrong Energy, each dated February 9, 2011, which concern the following general reserve areas: (a) Rockport (part); (b) Fish & Wildlife; (c) McHenry Spur and Church Properties; (d) Terteling/Highview; (e) Rockport (part) and Lewis Creek (part); (f) West Ford, Midway (part), Ben’s Lick, Central Grove, McHenry, Rockport (part) and Ken Wye; (g) Warden (part); (h) Armstrong Dock; (i) Big Run, East Fork/Kronos, Lewis Creek, and Midway (part); (j) Centertown; (k) Elk Creek; and (m) Equality Boot.

2011 was the first year we recognized revenue under our leases to Armstrong Energy. The following table sets forth actual coal royalty revenues we have received with respect to each of our reserves. Revenues in the table set forth below reflect revenues actually recognized during the year ended December 31, 2011 and three months ended March 31, 2012.


	Royalty Revenue
	Year Ended		Three Months Ended
Reserves	December 31, 2011		March 31, 2012
	(In thousands)

Elk Creek Reserves	$	622	$	958
Armstrong Energy Reserves(1)		7,167		2,123

Total	$	7,789	$	3,081


(1)		Represents royalty revenue earned on Armstrong Resource Partners 39.45% undivided interest in certain reserves owned by Armstrong Energy.

Our Lessee

Our lessee, Armstrong Energy, is a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin with both surface and underground mines. Armstrong Energy markets its coal primarily to electric utility companies as fuel for their steam-powered generators. Based on 2011 production, Armstrong Energy is the sixth largest producer in the Illinois Basin and the second largest in Western Kentucky. Armstrong Energy was formed in 2006 to acquire and develop a large coal reserve holding. Armstrong Energy commenced production in the second quarter of 2008 and currently operates seven mines, including five surface and two underground, and is seeking permits for three additional mines. Armstrong Energy controls approximately 326 million tons of proven and probable coal reserves, which includes approximately 121 million tons of coal reserves that it leases from an unaffiliated third party. Its reserves and operations are located in the Western Kentucky counties of Ohio, Muhlenberg, Union and Webster. Armstrong Energy also owns and operates three coal processing plants which support its mining operations. The location of our coal reserves and Armstrong Energy’s operations, adjacent to the Green and Ohio Rivers, together with Armstrong Energy’s river dock coal handling and rail loadout facilities, allow it to optimize coal blending and handling, and provide its customers with rail, barge, and truck transportation options. From Armstrong Energy’s reserves, it mines coal from multiple seams, which, in combination with its coal processing facilities, enhances its ability to meet customer requirements for blends of coal with different characteristics.

For the year ended December 31, 2011, Armstrong Energy produced 6.6 million tons of coal, with seven mines in operation, and currently expects a significant increase in its production for 2012 compared to 2011. For the three months ended March 31, 2012, Armstrong Energy produced 2.2 million tons of coal, with seven mines in operation. Armstrong Energy is contractually committed to sell 8.3 million tons of coal in 2012 and 7.1 million tons of coal in 2013, which represents 95% and 71% of its expected total coal sales in 2012 and 2013, respectively.

Our Lessee’s Multi-Year Coal Supply Agreements

As is customary in the coal industry, Armstrong Energy enters into multi-year coal supply agreements with many of its customers. Multi-year coal supply agreements usually have specific and possibly different volume and pricing arrangements for each year of the agreement. These agreements allow customers to secure a supply for their future needs and provide us and our lessee with greater predictability of sales volume and

sales prices. In 2011, Armstrong Energy sold approximately 89% of its coal under multi-year coal supply agreements. The majority of its multi-year coal supply agreements include a fixed price for the term of the agreement or a pre-determined escalation in price for each year. Some of Armstrong Energy’s multi-year coal supply agreements may include a variable pricing system. While most of its multi-year coal supply agreements are for terms of one to five years, some spot agreements and purchase orders provide for deliveries for as little as one month, and other agreements have terms up to 10.5 years. At March 31, 2012, Armstrong Energy had 10 multi-year coal supply agreements with terms ranging from one to seven years.

Armstrong Energy typically enters into multi-year coal supply agreements through a “request-for-proposal” process and after competitive bidding and negotiations. Therefore, the terms of these agreements vary by customer. Its multi-year coal supply agreements typically contain provisions to adjust the base price due to new laws and regulations that affect its costs. Additionally, some of Armstrong Energy’s agreements contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities.

The price of coal sold under certain of Armstrong Energy’s agreements is subject to fluctuation. For example, some of its agreements include index provisions that change the price based on changes in market-based indices and/or changes in economic indices. Other agreements contain price re-opener provisions that may allow a party to renegotiate pricing at a set time. Price re-opener provisions may automatically set a new price based on then-current market prices or require our lessee to negotiate a new price. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to terminate the agreement. In addition, certain of our lessee’s agreements contain clauses that may allow customers to terminate the agreement in the event of certain changes in environmental laws and regulations that impact their operations.

The coal supply agreements establish the quality and volume of coal to be sold. Most of Armstrong Energy’s agreements fix annual pricing and volume obligations, though, in certain instances, the volume obligations may change depending on the customer’s needs. Most of its coal supply agreements contain provisions requiring Armstrong Energy to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash and moisture content, as well as others. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments, or termination of the agreements.

Armstrong Energy’s coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by it or its customers in the event that circumstances beyond the control of the affected party occur, including events such as strikes, adverse mining conditions, mine closures, or serious transportation problems that affect our lessee or unanticipated plant outages that may affect the buyer. Armstrong Energy’s agreements also generally provide that in the event a force majeure event exceeds a certain time period, the unaffected party may have the option to terminate the purchase or sale in whole or in part.

Customers of Our Lessee

The following map identifies current or planned scrubbed power plants to which Armstrong Energy presently sells coal or to which Illinois Basin coal could be sold in the future.

Armstrong Energy’s primary customers are electric utilities. It may also sell coal to industrial companies, brokers and other coal producers. For the year ended December 31, 2011 and three months ended March 31, 2012, substantially all of Armstrong Energy’s coal revenues related to sales to electric utilities. The majority

of Armstrong Energy’s electric utility customers purchase coal for terms of one to five years, but our lessee also supplies coal on a spot basis for some of its customers.

In 2011, Armstrong Energy sold coal to 14 domestic customers with operations located in numerous states. The majority of those customers operate power plants in the Midwestern and Southern regions of the United States. For the year ended December 31, 2011, Armstrong Energy derived approximately 63% of its total coal revenues from sales to its two largest customers — LGE and TVA. For the fiscal year ended December 31, 2011, coal sales to LGE and TVA constituted approximately 35% and 28% of Armstrong Energy’s total coal revenues, respectively.

Our lessee currently has two multi-year coal supply agreements with LGE for the sale of coal. The first agreement was entered into in 2008, as amended, and expires in 2016. It calls for 2.1 million tons annually through 2015 and 0.9 million tons in 2016. Pricing ranges from $28.19 to $30.25 per ton over the term of the agreement subject to certain additional quality related adjustments that are typical of the industry. There is no price reopener provision in this agreement. The agreement with LGE that was entered into in 2009 calls for annual delivery of 1.25 million tons from 2011 through 2013 and 0.75 million tons from 2014 through 2016. In addition to typical quality adjustments, the price ranges from $42.00 to $45.00 per ton from 2011 through 2013. The agreement then provides that either party may elect at its sole option to reopen the agreement for negotiations with respect to price and/or other terms as it concerns all coal to be delivered in 2014 and beyond. Should either party seek to reopen the agreement (which must be done no later than April 1, 2013) and the parties be unable to reach a mutually acceptable agreement as to those terms being renegotiated, the agreement will terminate as of December 31, 2013.

Our lessee also has two multi-year coal supply agreements with TVA for the sale of coal. The agreement with TVA that was entered into in 2007, as amended, calls for the delivery of 1.0 million tons in 2012 and 2012 and 2.0 million tons annually from 2013 through 2018. The price ranges from $40.57 to $41.68 per ton in 2011 and 2012. The agreement then provides that either party may elect at its sole option to reopen the agreement for negotiations with respect to price and/or other terms as it concerns all coal to be delivered in 2013 and beyond and pursuant thereto TVA has exercised its right to reopen the agreement. If the parties are unable to reach a mutually acceptable agreement as to those terms being renegotiated by July 1, 2012, the agreement will terminate as of December 31, 2012. The agreement also provides for typical quality adjustments. In addition, commencing on July 1, 2011, TVA has the unilateral right to terminate the agreement upon 60 days written notice, in which case TVA is required to pay us a termination fee equal to 10% of the base price multiplied by the remaining number of tons to be delivered under the agreement.

The agreement with TVA that was entered into in 2008 calls for delivery of between 0.9 million and 1.1 million tons annually from 2009-2013. The price ranges from $56.00 to $58.00 per ton between 2011 and 2013. The agreement then provides that either party may elect at its sole option to reopen the agreement for negotiations with respect to price and/or other terms as it concerns all coal to be delivered in 2012 and 2013. TVA exercised its option under the agreement. As a result the parties reached an agreement to reprice the coal to be delivered in 2012 and 2013 with pricing from $54.25 to $55.88 per ton.

Transportation

Armstrong Energy ships its coal to domestic customers by means of railcars, barges or trucks, or a combination of these means of transportation. It generally sells coal free on board at the mine or nearest loading facility. Customers normally bear the costs of transporting coal by rail or barge. Historically, most domestic electricity generators have arranged long-term shipping agreements with rail or barge companies to assure stable delivery costs. Approximately 47% of Armstrong Energy’s coal shipped in 2011 was delivered by barge, which is generally less expensive than transporting coal by truck or rail. The Armstrong Dock, which is located on the Green River, can load up to six million tons of coal annually for shipment on inland waterways. For the year ended December 31, 2011, 28% and 25% of Armstrong Energy’s coal sales tonnage also was shipped by truck and rail, respectively.

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Competition

The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States, and Armstrong Energy competes with many of these producers. Armstrong Energy’s main competitors include Alliance Resource Partners, L.P., Patriot Coal Corp., Peabody Energy, Inc., the Cline Group’s Foresight Energy LLC, Oxford Resource Partners, LP and Murray Energy, all of which are companies mining in the Illinois Basin. Many of these coal producers have greater financial resources and more proven and probable reserves than Armstrong Energy does. Based on MSHA data, Armstrong Energy was the sixth largest producer of Illinois Basin coal in fiscal 2011, producing approximately 6% of the total Illinois Basin coal. As the price of domestic coal increases, our lessee also competes with companies that produce coal from one or more foreign countries, such as Colombia, Indonesia and Venezuela.

The most important factors on which Armstrong Energy competes are price, quality and characteristics, transportation costs and reliability of supply. The demand for Armstrong Energy’s coal and the prices that Armstrong Energy will be able to obtain for its coal are closely related to coal consumption patterns of the U.S. electric generation industry and international consumers. The patterns of coal consumption are affected by various factors beyond our control, including economic conditions, temperatures in the United States, government regulation, technological developments and the location, quality, price and availability of competing sources of fuel such as natural gas, oil and nuclear sources, and alternative energy sources such as hydroelectric power and wind.

Employees

We do not have any employees. Pursuant to the Administrative Services Agreement among the Partnership, Elk Creek GP and Armstrong Energy, Armstrong Energy provides us with general administrative and management services. This includes the use of Armstrong Energy’s employees in exchange for a monthly fee. See “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

Seasonality

Legal Proceedings

From time to time, we may be involved in litigation and claims arising out of our business in the normal course of business. At this time, we do not believe that we are a party to any litigation that will have a material adverse impact on our financial condition or results of operations. We are not aware of any significant and material legal or governmental proceedings against us, or contemplated to be brought against us. We maintain insurance policies in amounts and with coverage and deductibles that we believe are reasonable and appropriate. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

Regulation and Laws

Federal, state, and local authorities regulate the U.S. coal mining industry with respect to matters such as:


	•	employee health and safety;

	•	permitting and licensing requirements;

	•	air quality standards;

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	•	water pollution;

	•	storage, treatment and disposal of wastes;

	•	protection of plant life and wildlife, including endangered or threatened species;

	•	reclamation and restoration of mining properties after mining is completed;

	•	remediation of contaminated soil and groundwater;

	•	surface subsidence from underground mining;

	•	the effects of mining on surface and groundwater quality and availability; and

	•	competing uses of adjacent, overlying or underlying lands, pipelines, roads, and public facilities.

In addition, many of our lessee’s customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal.

The costs of compliance with these laws and regulations have been and are expected to continue to be significant. Future laws, regulations, or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may substantially increase equipment and operating costs, result in delays and disrupt operations or termination of operations, the extent of which cannot be predicted with any degree of certainty. Changes in applicable laws or the adoption of new laws relating to energy production may cause coal to become a less attractive source of energy. For example, if emissions rates or caps on greenhouse gases are enacted or a tax on carbon is imposed, the market share of coal as fuel used to generate electricity would be expected to decrease. Thus, future laws, regulations, or enforcement priorities may adversely affect our lessee’s mining operations, cost structure, or the demand for coal. Because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. Violations, including violations of any permit or approval, can result in substantial civil and criminal fines and penalties for our lessee, including revocation or suspension of mining permits. None of the violations our lessee has experienced to date has had a material impact on our operations or financial condition.

Mining Permits and Approvals

Numerous governmental permits and approvals are required for our lessee’s coal mining operations. Applicants, including our lessee, are required to assess the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization and permitting requirements imposed by governmental authorities are costly and may delay or prevent commencement or continuation of mining operations in certain locations. These requirements may also be supplemented, modified, or re-interpreted from time to time. Past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

In order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators or applicants must submit a reclamation plan for restoring the mined land to its prior productive use, better condition or other approved use. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all, particularly those permits involving the Clean Water Act. Specifically, issuance of Corps permits allowing placement of material in valleys or streams has been slowed in recent years due to ongoing disputes over the requirements for obtaining such permits. While our lessee does not engage in mountaintop mining, it is required to obtain permits from the Corps, and its mining operations under our leases do impact bodies of water regulated by the Corps. The application review process takes longer to complete and permit applications are increasingly being challenged by environmental and other advocacy groups, although we are not aware of any such challenges to any of our pending permit applications. Our lessee may experience difficulty or delays in obtaining mining permits or other necessary approvals in the future, or even face denials of permits altogether.

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Violations of federal, state, and local laws, regulations, or any permit or approval issued under such authorization can result in substantial fines and penalties, including revocation or suspension of mining permits and, in certain circumstances, criminal sanctions.

Surface Mining Control and Reclamation Act

The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement within the Department of the Interior (“OSM”), establishes operational, reclamation, and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. Mining operators must obtain SMCRA permits and permit renewals from the OSM or from the applicable state agency if the state has obtained primacy. A state may achieve primacy if it develops a regulatory program that is no less stringent than the federal program and is approved by OSM. SMCRA stipulates compliance with many other major environmental statutes, including the federal Clean Air Act, Clean Water Act, Resource Conservation and Recovery Act (“RCRA”), and Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”). Our lessee’s mines are located in Kentucky, which has primacy to administer the SMCRA program.

SMCRA permit provisions include a complex set of requirements, which include, among other things, coal exploration, mine plan development, topsoil or a topsoil removal alternative, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, disposal of excess spoil, protection of the hydrologic balance, subsidence control for underground mines, surface runoff and drainage control, mine drainage and mine discharge control and treatment, establishment of suitable post mining land uses, and re-vegetation. Our lessee’s preparation of a mining permit application begins by collecting baseline data to adequately characterize the pre-mining environmental conditions of the permit area. This work is typically conducted by third-party consultants with specialized expertise and typically includes surveys or assessments of the following: cultural and historical resources, geology, soils, vegetation, aquatic organisms, wildlife, potential for threatened, endangered or other special status species, surface and groundwater hydrology, climatology, riverine and riparian habitat, and wetlands. The geologic data and information derived from the surveys or assessments are used to develop the mining and reclamation plans presented in the permit application. The mining and reclamation plans address the provisions and performance standards of the state’s equivalent SMCRA regulatory program and are also used to support applications for other authorizations or permits required to conduct coal mining activities. Also included in the permit application is information used for documenting surface and mineral ownership, variance requests, public road use, bonding information, mining methods, mining phases, other agreements that may relate to coal, other minerals, oil and gas rights, water rights, permitted areas, and ownership and control information required to determine compliance with OSM’s Applicant Violator System, including the mining and compliance history of officers, directors, and principal owners of the permitting entity and its affiliates.

Some SMCRA mine permits take our lessee over a year to prepare, depending on the size and complexity of the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for this process to take from a year to several years for a SMCRA mine permit to be issued. This variability in time frame for permitting is a function of the discretion vested in the various regulatory authorities’ handling of comments and objections relating to the project that may be received from the governmental agencies involved and the general public. The public also has the right to comment on and otherwise engage in the permitting process, including at the public hearing and through judicial challenges to an issued permit.

Federal laws and regulations also provide that a mining permit or modification can be delayed, refused, or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors, or other entities) of the applicant have, or are affiliated with another entity that has, outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being “permit blocked” under the federal Applicant Violator Systems. Thus, non-compliance with SMCRA can

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provide the bases to deny the issuance of new mining permits or modifications of existing mining permits. We know of no basis for our lessee to be, and our lessee is not, permit-blocked.

In 1983, the OSM adopted the “stream buffer zone rule” (the “SBZ Rule”), which prohibited mining disturbances within 100 feet of streams if there would be a negative effect on water quality. In December 2008, the OSM finalized a revised SBZ Rule, which purported to clarify certain aspects of the 1983 SBZ Rule. Several organizations challenged the 2008 revision to the SBZ Rule in two related actions filed in the U.S. District Court for the District of Columbia. In June 2009, the Interior Department and the U.S. Army entered into a memorandum of understanding on how to protect waterways from degradation if the revised SBZ Rule were vacated due to the litigation. In August 2009, the District Court concluded that the revised SBZ Rule could not be vacated without following the Administrative Procedure Act and other related requirements. In November 2009, the OSM published an advanced notice of proposed rulemaking to further revise the SBZ Rule. In a March 2010 settlement with the litigation parties, OSM agreed to use its best efforts to adopt a final rule by June 2012. The revised SBZ Rule, when adopted, may be stricter than the SBZ Rule promulgated in December 2008 in order to further protect streams from the impacts of surface mining, and may adversely affect our lessee’s business and operations. In addition, legislation has been introduced in Congress in the past, and may be introduced in the future, in an attempt to preclude placing any fill material in streams. Implementation of new requirements or enactment of such legislation could negatively impact our future ability to conduct certain types of mining activities.

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund (“AML”), which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The current fee is $0.315 per ton of coal produced from surface mines and $0.135 per ton on deep-mined coal from 2008 to 2012, with reductions to $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from 2013 to 2021. In 2011, our lessee recorded approximately $1.8 million of expense related to these reclamation fees.

Surety Bonds

Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. The cost of surety bonds has fluctuated in recent years, and the market terms of these bonds have generally become more unfavorable to mine operators. For example, in connection with our lessee’s current bonds, it is required to post substantial security in the form of cash collateral. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. Some mine operators have therefore used letters of credit to secure the performance of a portion of our lessee’s reclamation obligations. Many of these bonds are renewable on a yearly basis. We cannot predict our lessee’s ability to obtain bonds, or other approved forms of performance security, or the cost of such security, in the future. As of March 31, 2012, our lessee had approximately $18.3 million in surety bonds outstanding to secure the performance of our lessee’s reclamation obligations, which are collateralized by cash deposits of 25% of the value of the bonds.

Mine Safety and Health

Stringent health and safety standards have been in effect since the enactment of the Federal Coal Mine Health and Safety Act of 1969. The Mine Act provided for MSHA and significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. For example, it requires periodic inspections of surface and underground coal mines and requires the issuance of citations or orders for the violation of a mandatory health and safety standard. A civil penalty must be assessed for each citation or order issued. Serious violations of mandatory health and safety standards may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators who knowingly or willfully violate a mandatory health and safety standard or order and provides that civil and criminal penalties may be assessed against individual agents, officers, and

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directors who knowingly or willfully violate a mandatory health and safety standard or order. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards. In addition to federal regulatory programs, the State of Kentucky in which our lessee operates, also has programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. Such regulation has a significant effect on our lessee’s operating costs.

In 2006, in response to underground mine accidents, Congress enacted the MINER Act. Among other things, it (i) imposed additional obligations on coal operators related to (a) developing new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training, and communication with local emergency response personnel, (b) establishing additional requirements for mine rescue teams, and (c) promptly notifying federal authorities of incidents that pose a reasonable risk of death and (ii) increased penalties for violations of applicable federal laws and regulations. In addition, in October 2010, MSHA published a proposed rule to reduce the permissible concentration of respirable dust in underground coal mines from the current standard of 2.0 milligrams per cubic meter of air to 1.0 milligram per cubic meter. We believe MSHA is also likely to adopt new safety standards for proximity protection for miners that will require certain underground mining equipment to be equipped with devices that will shut the equipment down if a person is too close to the equipment to avoid injuries where individuals are caught between equipment and blocks of unmined coal. Various states also have enacted their own new laws and regulations addressing many of these same subjects. In the wake of several recent underground mine accidents, enforcement scrutiny has also increased, including more inspection hours at mine sites, increased numbers of inspections, and increased issuance of the number and the severity of enforcement actions.

After the MINER Act, Illinois, Kentucky, Pennsylvania and West Virginia enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Additionally, in 2010, the 111th U.S. Congress introduced federal legislation seeking to impose extensive additional safety and health requirements on coal mining. While the legislation was passed by the House of Representatives, the legislation was not voted on in the Senate and did not become law. In January 2011, a similar bill was reintroduced in the 112th U.S. Congress. Our lessee’s compliance with current or future mine health and safety regulations could increase its mining costs. At this time, it is not possible to predict the full effect that the new or proposed statutes, regulations, and policies will have on its operating costs, but they will increase these costs and those of our lessee’s competitors. Some, but not all, of these additional costs may be passed on to customers and negatively impact our royalty revenues.

Our lessee is required to compensate employees for work-related injuries under various state workers’ compensation laws. Our lessee’s costs will vary based on the number of accidents that occur at its mines and other facilities, and its costs of addressing these claims. Our lessee provides benefits to its employees by being insured through state-sponsored programs or an insurance carrier where there is no state-sponsored program.

Clean Air Act

The federal Clean Air Act and the amendments thereto and state laws that regulate air emissions both directly and indirectly affect coal mining operations. Direct impacts on our lessee’s coal mining and processing operations include Clean Air Act permitting requirements and control requirements for particulate matter, which includes fugitive dust from roadways, parking lots, and equipment such as conveyors and storage piles. Our lessee’s customers also are subject to extensive air emissions requirements, including those applicable to the air emissions of SO₂, NOx, particulates, mercury, and other compounds from coal-fired electricity generating plants and industrial facilities that burn coal. These requirements are complex, and are generally becoming increasingly stringent as new regulations or revisions to existing regulations are adopted. In addition, legal challenges by environmental advocacy groups, affected members of the regulated community, and others to regulations may impact their content and the timing of their implementation.

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More stringent air emissions requirements in future years may increase the cost of producing and consuming coal and impact the demand for coal. These requirements may result in an upward pressure on the price of lower sulfur eastern coal, and more demand for western coal, as coal-fired power plants continue to comply with the more stringent restrictions initially focused on SO₂ emissions. As utilities continue to invest the capital to add scrubbers and other devices to address emissions of NOx, mercury, and other hazardous air pollutants, demand for lower sulfur coal may drop. However, we cannot predict these impacts with certainty.

In June 2010, several environmental groups petitioned the EPA to list coal mines as a source of air pollution and establish emissions standards under the Clean Air Act for several pollutants, including particulate matter, NOx, volatile organic compounds, and methane. Petitioners further requested that the EPA regulate other emissions from mining operations, including dust and clouds of NOx associated with blasting operations. If the petitioners are successful, emissions of these or other materials associated with our lessee’s mining operations could become subject to further regulation pursuant to existing laws such as the Clean Air Act. In that event, our lessee might be required to install additional emissions control equipment or take other steps to lower emissions associated with its operations, thereby adversely affecting its operations and potentially decreasing our royalty revenues.

The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, SO₂, NOx, carbon monoxide, ozone, mercury, and other compounds emitted by coal-fired power plants, which are the largest end users of the coal mined from our reserves. In addition to developments directed at limiting greenhouse gas emissions, which are discussed separately further below, air emission control programs that affect our lessee’s operations, directly or indirectly, include, but are not limited to, the following:


	•	Acid Rain. Title IV of the Clean Air Act requires reductions of SO₂ and NOx emissions by electric utilities regulated under the Acid Rain Program (“ARP”). The ARP was designed to reduce the electric power sector emissions of SO₂ and NOx and was implemented in two phases, Phase II of which commenced in 2000 for both SO₂ and NOx. SO₂ emissions were controlled through the development of a national market-based cap and trade system applicable to all coal-fired power plants with a capacity of more than 25 megawatts, among other sources. Under the ARP, a cap on annual SO₂emissions is established and then EPA issues allowances to regulated entities up to the cap using defined formulas. A small percentage of the allowances are retained for auctions. Each power plant must have enough allowances to cover all of its annual SO₂ emissions or pay penalties. The electric power plant can choose to reduce emissions and sell or bank the surplus allowances or purchase allowances. Power plants are allowed to choose to emit or control emissions, and emission reductions are encouraged by requiring an allowance to be retired every year for each ton of SO₂ emitted. Affected power plants have sought to reduce SO₂ emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels, or purchasing or trading SO₂ emissions allowances. The ARP makes it more costly to operate coal-fired power plants and could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

	•	New National Ambient Air Quality Standards. The federal Clean Air Act requires the EPA to determine and, where appropriate, from time to time update ambient air quality standards applicable nationwide, known as national ambient air quality standards (“NAAQSs”) for six common air pollutants. Such standards can have significant impacts on sources of such air pollutants, particularly after such standards are tightened. Although the NAAQSs do not apply directly to sources of such pollutants, NAAQSs can result in sources having to meet substantially stricter emissions limitations for such pollutants upon renewal of their air permits, which commonly are issued for five-year terms. Where an air quality management district has not attained the NAAQS for such a pollutant (a “non-attainment area”), sources may face more onerous requirements regarding such a pollutant. Coal combustion generates or affects several pollutants subject to NAAQSs, including SO₂, NO₂, ozone, and particulate matter, so when any such standard is made stricter, it may indirectly affect our lessee’s customers’ current or anticipated future costs of using coal. In addition, NAAQSs for particulate matter may affect aspects of our lessee’s operations, which can generate such emissions. The EPA has revised and/or proposed to revise a number of such NAAQSs in recent years. For example, in June 2010, the

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		EPA issued a stricter NAAQS for SO₂ emissions which, among other things, establishes a new 1-hour standard at a level of 75 parts per billion to protect against short-term exposure and minimize health-based risks, revokes the previous 24-hour and annual standard for SO_2,and imposes requirements for monitoring and reporting SO₂ concentrations. In February 2010, the EPA issued a stricter NAAQS for NOx and in January 2010 also proposed a revised, stricter ground-level ozone NAAQS. In addition, in 2006 the EPA issued stricter NAAQSs for particulate matter and subsequently has been implementing, and reviewing state implementation of, those standards. While aspects of the EPA’s rules promulgating some of these standards or predecessor standards have been, and in some instances remain, the subject of litigation by industry representatives, environmental advocacy groups, and others, and while EPA is reviewing aspects of some of these NAAQSs, in important respects these NAAQSs and/or their implementation have become stricter, and may become more so due to ongoing developments.


	•	Cross-State Air Pollution Rule. In July 2011, the EPA promulgated the CSAPR, which replaces the EPA’s Clean Air Interstate Rule (“CAIR”), issued in 2005. A decision in July 2008 by the U.S. Court of Appeals for the District of Columbia Circuit concluded that CAIR should be vacated and directed the EPA to develop a replacement. The CSAPR, including a related proposed rulemaking that would revise the CSAPR by subjecting six additional states to NOx emission limits, requires additional reductions in SO₂ and NOx emissions from power plants in 27 states and severely limits interstate emissions trading as a compliance option. The CSAPR may result in many coal-fired sources installing additional pollution control equipment for NOx and SO₂, which we believe could lead plants with these controls to become less sensitive to the sulfur-content of coal and more sensitive to delivered price, thereby making high sulfur coal more competitive. In December 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued a ruling to stay the CSAPR pending judicial review.


	•	Mercury. In February 2012, the EPA published its final rule to establish a national standard to reduce mercury and other toxic air pollutants from coal and oil-fired power plants, sometimes referred to as the EPA’s MATS. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has also been proposed from time to time. In addition, in March 2011, EPA issued new MACT determinations for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury; in May the effective date of these rules for major sources was delayed for reconsideration of certain aspects of the rule and in December 2011, the EPA published a reconsideration proposal for public comment.


	•	Regional Haze. In 1999, the EPA issued a rule in an effort to meet Clean Air Act requirements regarding a nationwide regional haze program designed to protect and improve visibility at and around 156 federal areas such as national parks, national wilderness areas and international parks; this rule was revised by another EPA rule issued in 2005. This program may result in additional restrictions on emissions from new coal-fired power plants whose operation may impair visibility at and near such federally protected areas. This program may also require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as SO₂, NOx, ozone and particulate matter. Insofar as this program results in limitations on coal combustion in addition to those that are otherwise applicable, it could also affect the future market for coal, although we are unable to predict the extent of any such impacts with any reasonable degree of certainty.

	•	New Source Review. A number of enforcement actions in recent years are affecting the impact of the EPA’s New Source Review (“NSR”) program as applied to some existing sources, including certain coal-fired power plants. The NSR program requires existing coal-fired power plants, when undertaking certain modifications, to install the same air emissions control equipment as new plants. Enforcement proceedings alleging that such modifications were made without implementing the required control equipment have resulted in a number of settlements involving commitments, including those by coal-fired power plants, to incur extensive air emissions controls involving substantial expenses. Such enforcement, and other changes affecting the scope or interpretation of aspects of the NSR program,

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		may impact demand for coal, but we are unable to predict the magnitude of any such impact on us with any reasonable degree of certainty.

Climate Change

CO₂ is one of the “greenhouse gases,” the man-made emissions which are of major concern under any regulatory framework intended to control what is sometimes referred to as “global warming” or, due to other possible impacts on climate that many policy-makers and scientists believe such warming may have, “climate change.” CO₂ is a major by-product of the combustion process within coal-fired power plants. Methane, which must be expelled from our lessee’s underground coal mines for mining safety reasons, also is classified as a greenhouse gas; although estimates may vary, it is generally considered to have a greenhouse gas impact many times that of an equivalent amount of CO₂.

Considerable and increasing government attention in the United States and other countries is being paid to reducing greenhouse gas emissions, including CO₂ from coal-fired power plants and methane emissions from mining operations. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (the “UNFCCC”), which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. To date, the U.S. has not ratified the Kyoto Protocol, which was scheduled to expire in 2012, but was extended for five years at the UNFCCC Conference of Parties in Durban, South Africa in December 2011. The United States is participating in international discussions currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. A replacement treaty or other international arrangement requiring additional reductions in greenhouse gas emissions could have a potentially significant impact on the demand for coal, particularly if the United States were to adopt it but, depending on the requirements it imposes and the extent to which other nations adopt it, even if the United States does not adopt it.

Future regulation of greenhouse gases in the United States could occur pursuant to, for example, future U.S. treaty commitments; new domestic legislation that imposes a tax on greenhouse gas emissions, a greenhouse gas cap-and-trade program or other programs aimed at greenhouse gas reduction; or regulatory programs that may be established by the EPA under its existing authority. Congress has actively considered various proposals to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power, promote the use of clean energy and require energy efficiency measures. In June 2009, the House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act, and the Senate has considered similar legislation that would, among other things, impose a nationwide cap on greenhouse gas emissions and require major sources, including coal-fired power plants, to obtain “allowances” to meet that cap. Passage of such comprehensive climate change or energy legislation could impact the demand for coal. Any reduction in the demand for coal by North American electric power generators could reduce the price of coal that we mine and sell and thereby reduce our revenues, which could have a material adverse affect on our business and the results of our operations.

Even in the absence of new federal legislation, greenhouse gas emissions may be regulated in the future by the EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. Environmental Protection Agency that the EPA has authority to regulate greenhouse gas emissions under the Clean Air Act, the EPA has taken several steps towards implementing regulations regarding greenhouse gas emissions. In December 2009, the EPA issued a finding that CO₂ and certain other greenhouse gases emitted by motor vehicles endanger public health and the environment. This finding allows the EPA to begin regulating greenhouse gas emissions under existing provisions of the Clean Air Act. In October 2009, the EPA published a final rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their greenhouse gas emissions to the EPA beginning in 2011 for emissions occurring in 2010. In May 2010, the EPA issued a final “tailoring rule” that determines which stationary sources of greenhouse emissions need to obtain a construction or operating permit, and install best available control technology for greenhouse gas emissions, under the Clean Air Act’s Prevention of Significant Deterioration or Title V programs when such facilities are built or significantly modified. Without the tailoring rule, permits would have been required for stationary sources with emissions that exceed either 100 or 250

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tons per year (depending on the type of source), which the EPA considered not feasible. The tailoring rule substantially increases this threshold for greenhouse gas emissions to 75,000 tons per year beginning in January 2011, and further modifies the threshold after July 2011; the EPA has stated that the rule will be limited to the largest greenhouse gas emitters in the United States, primarily power plants, refineries, and cement production facilities that the EPA estimates are responsible for nearly 70% of greenhouse gas emissions from the country’s stationary sources. The tailoring rule also commits the EPA to undertake and complete another rulemaking by no later than July 2012 to, among other things, consider expanding permitting requirements to sources with greenhouse gas emissions greater than 50,000 tons per year; in March 2012, the EPA proposed to continue using the current threshold rather than expand the permitting requirements at this point. A number of lawsuits have been filed challenging the tailoring rule. The final outcome of federal legislative action on greenhouse gas emissions may change one or more of the foregoing final or proposed EPA findings and regulations. If the EPA were to set emission limits or impose additional permitting requirements for CO₂ from coal-fired power plants, the amount of coal our customers purchase from us could decrease.

On March 27, 2012, the EPA proposed new emission standards seeking to limit the amount of CO₂ emissions from new fossil fuel-fired electric utility generating power plants. The proposed rule would require new plants greater than 25 megawatts electric to meet an output based standard of 1000 pounds of CO₂ per megawatt hour, based on the performance of natural gas combined cycle technology. New coal-fired power plants could meet the standard either by employing carbon capture and storage technology at start up or through later application of such technologies provided that the aforementioned output standard was met on average over a 30-year period. Public comments concerning the proposed rule must be received within 60 days after the date of publication of such rule, and future public hearings will be scheduled to discuss the proposal. If adopted, the proposed rules could negatively impact the price of coal such that it would be less attractive to utilities and ratepayers. Moreover, there is currently no large-scale use of carbon capture and storage technologies in domestic coal-fired power plants, and as a result, there is a risk that such technology may not be commercially practical for use in limiting emissions as otherwise required by the proposed rule.

Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities. For example, beginning in January 2009, the Regional Greenhouse Gas Initiative (“RGGI”), a regional greenhouse gas cap-and-trade program, began its first control period, operating with ten Northeastern and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont). The RGGI program has had several emission allowances auctions and will enter its second three-year control period in 2012. The RGGI program calls for signatory states to stabilize CO₂ emissions to current levels from 2009 to 2015, followed by a 2.5% reduction each year from 2015 through 2018. Since RGGI was first proposed, the states formally participating and observing have varied somewhat; recently politicians in several states have taken formal steps (including an announcement by New Jersey’s governor, and a bill passed by New Hampshire’s legislature but vetoed by its governor) to withdraw from RGGI. RGGI has been holding quarterly CO₂ allowance auctions for its initial three-year compliance period from January 1, 2009 to December 31, 2011 to allow utilities to buy allowances to cover their CO₂ emissions. Midwestern states and Canadian provinces have also adopted initiatives to reduce and monitor greenhouse gas emissions. In November 2007, Illinois, Iowa, Kansas, Michigan, Minnesota, South Dakota and Wisconsin signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions; also, Indiana, Ohio and Manitoba signed as observers. Draft recommendations were released in June 2009, although they have not been finalized. Climate change initiatives are also being considered or enacted in some western states.

Also, litigation to address climate change impacts is being pursued against major emitters of greenhouse gases. A federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of CO₂; while the United States Supreme Court recently reversed the appeals court, it did not reach the question whether state common law is available for such claims because that question had not been addressed by the lower court. A second federal appeals court had earlier dismissed a case seeking damages allegedly caused by

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climate change that had been filed against scores of large corporate defendants, including a number of electrical power generating companies and coal companies, but the dismissal was on procedural grounds; the case has since been re-filed. Claims seeking remedies to address conditions or losses allegedly caused by climate change that in turn allegedly has resulted from greenhouse gas-generating conduct by the defendants remain pending in the courts. Such claims could continue to be asserted against our lessee’s customers in the future, and might also be asserted against our lessee; accordingly, such claims could adversely affect us.

In addition to direct regulation of greenhouse gases, over 30 states have adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Several other states have renewable portfolio standard goals that are not yet legal requirements. Additional states may adopt similar goals or requirements, and federal legislation has been repeatedly proposed in this area although no bills imposing such requirements have been enacted into law to date. To the extent these requirements affect our lessee’s current and prospective customers, their demand for coal-fueled power may decline, which may reduce long-term demand for our coal.

These and other current or future climate change rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to switch from coal to lower greenhouse gas emitting fuels or to shut down coal-fired power plants. There can be no assurance at this time that a greenhouse gas cap-and-trade program, a greenhouse gas tax or other regulatory regime, if implemented by the states in which our lessee’s customers operate or at the federal level, or future court orders or other legally enforceable mechanisms, will not affect the future market for coal in those regions. The permitting of new coal-fired power plants has also recently been contested by some state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal. If mandatory restrictions on greenhouse gas emissions are imposed, the ability to capture and store large volumes of CO₂ emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage (“CCS”) technology have been proposed or enacted. For example, the U.S. Department of Energy announced in May 2009 that it would provide $2.4 billion of federal stimulus funds under the American Recovery and Reinvestment Act of 2009 to expand and accelerate the commercial deployment of large-scaled CCS technology. However, there can be no assurances that cost-effective CCS technology will become commercially feasible in the near future, or at all.

Clean Water Act

The Clean Water Act of 1972 (“CWA”) and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including the discharge of dredged or fill materials, into waters of the United States. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges, and changes in implementation. Recent court decisions, regulatory actions, and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease our lessee’s costs and time spent on CWA compliance.

CWA requirements that may directly or indirectly affect our lessee’s operations include the following:


	•	Wastewater Discharge. Section 402 of the CWA regulates the discharge of “pollutants” into navigable waters of the United States. The National Pollutant Discharge Elimination System (“NPDES”) requires a permit for any such discharges and entails regular monitoring, reporting, and compliance with performance standards, all of which are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. Failures to comply with the CWA or the NPDES permits can lead to the imposition of penalties, compliance costs, and delays in coal production. The CWA and corresponding state laws also protect waters that states have designated for special

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		protections including those designated as: impaired (i.e., as not meeting present water quality standards) through Total Maximum Daily Load (“TMDL”) regulations and “high quality/exceptional use” streams through anti-degradation regulations which restrict or prohibit discharges which result in degradation. Likewise, when water quality in a receiving stream is better than required, states are required to adopt an “anti-degradation policy” by which further “degradation” of the existing water quality is reviewed and possibly limited. In the case of both the TMDL and anti-degradation review, the limits in our lessee’s NPDES discharge permits could become more stringent, thereby potentially increasing treatment costs and making it more difficult to obtain new surface mining permits. Other requirements may result in obligations to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium, and dissolved solids; and to take measures intended to protect streams, wetlands, other regulated water sources, and associated riparian lands from surface mining and/or the surface impacts of underground mining. Individually and collectively, these requirements may cause our lessee to incur significant additional costs that could adversely affect our royalty revenues.


	•	Dredge and Fill Permits. Many mining activities, including the development of settling ponds and other impoundments, may require a Section 404 permit from the Corps, prior to conducting such mining activities where they involve discharges of “fill” into navigable waters of the United States. The Corps is empowered to issue “nationwide” permits for specific categories of filling activities that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404 of the CWA. Using this authority, the Corps issued NWP 21, which authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Individual Section 404 permits are required for activities determined to have more significant impacts to waters of the United States.

Since 2003, environmental groups have pursued litigation primarily in West Virginia and Kentucky challenging the validity of NWP 21 and various individual Section 404 permits authorizing valley fills associated with surface coal mining operations (primarily mountain-top removal operations). This litigation has resulted in delays in obtaining these permits and has increased permitting costs. The most recent major decision in this line of litigation is the opinion of the U.S. Court of Appeals for the Fourth Circuit in Ohio Valley Environmental Council v. Aracoma Coal Company, 556 F.3d 177 (2009) (Aracoma), issued in February 2009. In Aracoma, the Court rejected all of the substantive challenges to the Section 404 permits involved in the case primarily by deferring to the expertise of the Corps in review of the permit applications. After this decision was published, however, the EPA undertook several initiatives to address the issuance of Section 404 permits for coal mining activities in the Eastern U.S. First, the EPA began to comment on Section 404 permit applications pending before the Corps raising many of the same issues decided in favor of the coal industry in Aracoma. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. These letters have created regulatory uncertainty regarding the issuance of Section 404 permits for coal mining operations and have substantially expanded the time required for issuance of these permits, particularly in the Appalachian region.

In June 2009, the Corps, the EPA, and the Department of the Interior announced an interagency action plan for “enhanced coordination procedures” in reviewing any project that requires both a SMCRA and a CWA permit, designed to reduce the harmful environmental consequences of mountain-top mining in the Appalachian region. As part of this interagency memorandum of understanding, the Corps proposed to suspend and modify NWP 21 in the Appalachian region of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia to prohibit its use to authorize discharges of fill material into waters of the United States for mountain-top mining.

In June 2010, the Corps announced the suspension of the NWP 21 permitting process in the Appalachian region of the six states referred to above until the Corps takes further action on NWP 21, or until NWP 21 expires on March 18, 2012. The Corps has since reissued NWP 21 in February 2012, but has added a number of conditions to provide more extensive stream protection than before.

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The EPA is also taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia, and announced in September 2009 that it was delaying the issuance of 74 Section 404 permits in central Appalachia. This is especially true in West Virginia, where the EPA plans to review all applications for NPDES permits even though the State of West Virginia is authorized to issue NPDES permits in West Virginia. In addition, in April 2010, the EPA issued an interim guidance document on water quality requirements for coal mines in Appalachia. This guidance follows up on the June 2009 enhanced coordination procedures memorandum for the issuance of Section 404 permits whereby the EPA undertook a new level of review of Section 404 permits than it had previously undertaken. Ultimately, the EPA identified 79 coal-related applications for Section 404 permits that would need to go through that process. The EPA’s actions in issuing the enhanced coordination procedures memorandum and the guidance are being challenged in a lawsuit pending before the U.S. District Court of the District of Columbia in a case captioned National Mining Assoc. v. U.S. Environmental Protection Agency. In a ruling issued in January 2011, the District Court held that these measures “are legislative rules that were adopted in violation of notice and comment requirements.” The court would not grant the motion for a preliminary injunction to enjoin further use of these measures but also refused to dismiss the Complaint as the EPA had sought. In July 2011, after a notice and comment process, the EPA issued final guidance on review of Appalachian surface coal mining operations that replaced the interim guidance it had issued in April 2010.

In January 2011 the EPA exercised its “veto” power under Section 404(c) of the CWA to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action is the first time that such power was exercised with regard to a previously permitted coal mining project. These initiatives have extended the time required for operations affected by them to obtain permits for coal mining, and the costs associated with obtaining and complying with those permits may increase substantially. Additionally, while it is unknown precisely what other future changes will be implemented as a result of the interagency action plan, any future changes could further restrict our lessee’s ability to obtain other new permits or to maintain existing permits.

Other Regulations on Stream Impacts

Federal and state laws and regulations can also impose measures to be taken to minimize and/or avoid altogether stream impacts caused by both surface and underground mining. Temporary stream impacts from mining are not uncommon, but when such impacts occur there are procedures our lessee follows to mitigate or remedy any such impacts. These procedures have generally been effective and our lessee work closely with applicable agencies to implement them. Our lessee’s inability to mitigate or remedy any temporary stream impacts in the future, and the application of existing or new laws and regulations to disallow any stream impacts, could adversely affect its operations and our coal royalty revenues.

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Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act (“RCRA”) was enacted in 1976 to establish requirements for the management of hazardous wastes from the point of generation through treatment and disposal. RCRA does not apply to certain wastes generated at coal mines, such as overburden and coal cleaning wastes, because they are not considered hazardous wastes as the EPA applies that term. Only a small portion of the wastes generated at a mine are regulated as hazardous wastes.

Although RCRA has the potential to apply to wastes from the combustion of coal, the EPA determined in 1993 with respect to certain coal combustion wastes, and in May 2000 with respect to others, that coal combustion wastes do not warrant regulation as hazardous wastes under RCRA. Most state solid waste laws also regulate coal combustion wastes as non-hazardous wastes. In May 2010, the EPA issued proposed regulations governing management and disposal of coal ash from coal-fired power plants. The EPA sought public comment on two regulatory options. Under the more stringent option, the EPA would regulate coal ash as a “special waste” subject to hazardous waste standards when disposed in landfills or surface impoundments, which would be subject to stringent design, permitting, closure and corrective action requirements. Alternatively, coal ash would be regulated as non-hazardous waste under RCRA subtitle D, with national minimum criteria for disposal but no federal permitting or enforcement. Under both options, the EPA would establish dam safety requirements to address the structural integrity of surface impoundments to prevent catastrophic releases. The EPA did not address in the proposed regulations the use of coal combustion wastes as minefill, but indicated that it would separately work with the Office of Surface Mining in order to develop effective federal regulations ensuring that such placement is adequately controlled. If coal ash from coal-fired power plants is re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. If coal ash is regulated under RCRA subtitle D, it could also adversely affect our customers and potentially reduce the desirability of coal for them. In addition, contamination caused by the past disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal and therefore, also our royalty revenues. The EPA had been expected to issue a final decision by the end of 2011, but did not. It was sued in federal court in April 2012 by environmental and health advocacy groups to compel agency action.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”), and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we own or lease. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our mine sites. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we own surface rights.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (“USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. A number of species indigenous to the areas in which our lessee’s mines are located are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or delaying our lessee from

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obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building, and other mining or agricultural activities in areas containing the affected species or their habitats. Should more stringent protective measures be applied, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures, which could adversely affect Armstrong Energy’s operations and our coal royalty revenues.

Other Environmental Laws and Matters

We, our lessee, and its customers are subject to and are required to comply with numerous other federal, state, and local environmental laws and regulations, in addition to those previously discussed, which place stringent requirements on coal mining and other operations as well as the ability of our lessee’s customers to use coal. Federal, state, and local regulations also require regular monitoring of our lessee’s mines and other facilities to ensure compliance with these many laws and regulations. Some of these additional laws and regulations include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act.

Other Facilities

Pursuant to the Administrative Services Agreement effective as of January 1, 2011 among Armstrong Resource Partners, Elk Creek GP and Armstrong Energy, Armstrong Energy provides Armstrong Resource Partners with general administrative and management services, including, but not limited to, human resources, information technology, financial and accounting services and legal services. As consideration for the use of Armstrong Energy’s employees and services and for certain shared fixed costs, including, but not limited to, office lease, telephone and office equipment leases, Armstrong Resource Partners pays Armstrong Energy a monthly fee equal to $60,000 per month until December 31, 2011. See “Certain Relationships and Related Party Transactions — Administrative Services Agreement.” We believe our properties are sufficient for our current needs.

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MANAGEMENT

We do not, and will not, have any officers or directors. We will be managed by the directors of our general partner, EIK Creek GP, and the officers of Armstrong Energy, Inc., the owner of our general partner. Unitholders will not directly or indirectly participate in our management or operation. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders are not entitled to elect our general partner’s directors or indirectly participate in our management or operations. Our general partner owes certain fiduciary duties to our unitholders, but our Partnership Agreement contains various provisions modifying and restricting such fiduciary duties. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner may cause us to incur indebtedness or other obligations that are nonrecourse to it, and we expect that it will do so.

We expect that our general partner will have seven directors, four of whom will be independent as defined under the Nasdaq independence standards. Three members of the board of directors of Armstrong Energy serve on a conflicts committee that reviews specific matters that the board believes may involve conflicts of interest between us and Armstrong Energy. The conflicts committee will determine whether the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee must meet the independence standards to serve on an audit committee of a board of directors established by Nasdaq and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by Armstrong Energy or our general partner of any duties they may owe to us or our unitholders.

In addition, we expect that three members of our general partner’s board of directors will serve on an audit committee which will review our external financial reporting, recommend engagement of our independent auditors, and review procedures for the adequacy of our internal accounting controls. The members of our general partner’s audit committee will have been appointed prior to the date our common units first trade on Nasdaq.

Nasdaq does not require a publicly traded limited partnership, like us, to establish a compensation committee or a nominating committee. Three members of the Armstrong Energy board of directors serve on a nominating, corporate governance and risk management committee, which recommends nominees to serve on our general partner’s and Armstrong Energy’s boards of directors, and monitors and evaluates corporate governance issues and trends. Three members of the Armstrong Energy board of directors also serve on a compensation committee, which oversees compensation decisions for the officers of Armstrong Energy and the directors of our general partner and of Armstrong Energy, including the compensation plans described below.

Some officers of Armstrong Energy may spend a substantial amount of time managing the business and affairs of Armstrong Energy and its affiliates other than us. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Armstrong Energy. Armstrong Energy intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Board of Directors

We will be managed by the board of directors of our general partner. We expect that the general partner’s board of directors will consist of the seven individuals who serve as directors of Armstrong Energy. Of these seven directors, the board has determined that Messrs. Beard, Crain, Ford and Walker each meet the independence standards as established by the rules and regulations of Nasdaq and the SEC, including the heightened independence standards for audit committee members.

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Executive Officers and Directors

As discussed above, we will be managed by the executive officers of Armstrong Energy and our general partner’s board of directors. Set forth below, as of May 1, 2012, is certain information relating to the Armstrong Energy executive officers and the directors of our general partner upon consummation of this offering. All directors are elected for a term of three years and serve until their successors are elected and qualified. All executive officers hold office until their successors are elected and qualified. The term of our Class I directors expires in 2012, the term of our Class II directors expires in 2013, and the term of our Class III directors expires in 2014.


Name	Age		Position

J. Hord Armstrong, III		71	Chairman (Class II) of EIK Creek GP and Chief Executive Officer of Armstrong Energy
Martin D. Wilson		50	President of Armstrong Energy and Director (Class I) of EIK Creek GP
Kenneth E. Allen		65	Executive Vice President of Operations of Armstrong Energy
David R. Cobb, P.E.		64	Executive Vice President of Business Development of Armstrong Energy
J. Richard Gist		55	Senior Vice President, Finance and Administration and Chief Financial Officer of Armstrong Energy
Brian G. Landry		56	Vice President, Information Technology of Armstrong Energy
Anson M. Beard, Jr.		76	Director (Class I) of EIK Creek GP
James C. Crain		63	Director (Class III) of EIK Creek GP
Richard F. Ford		75	Director (Class III) of EIK Creek GP
Bryan H. Lawrence		69	Director (Class III) of EIK Creek GP
Greg A. Walker		56	Director (Class II) of EIK Creek GP

The term of our Class I directors expires in 2012, the term of our Class II directors expires in 2013, and the term of our Class III directors expires in 2014.

J. Hord Armstrong, III — Mr. Armstrong served as the Chairman and Chief Executive Officer of Armstrong Energy’s predecessor entity (the “Predecessor”), and as a member of the Predecessor’s board of managers, from its formation in 2006 until the reorganization of Armstrong Energy (the “Reorganization”) in October 2011. Since the Reorganization, Mr. Armstrong has been the Chairman and Chief Executive Officer of Armstrong Energy. Mr. Armstrong will be appointed as chairman of our general partner prior to consummation of this offering. Previously, Mr. Armstrong worked for the Morgan Guaranty Trust Company and was elected Assistant Treasurer in 1967. He subsequently spent 10 years with White Weld & Company as First Vice President until the firm was acquired by Merrill Lynch in 1978. Mr. Armstrong then joined Arch Mineral Corporation, St. Louis, as Treasurer (1978-1981), and ultimately became its Vice President and Chief Financial Officer (1981-1987). Mr. Armstrong left Arch Mineral in 1987, when he founded D&K Healthcare Resources. Mr. Armstrong served as D&K’s Chief Executive Officer from 1987 to 2005. D&K Healthcare Resources became a public company in 1992 and was acquired by McKesson Corporation in 2005. Mr. Armstrong served for 10 years as a member of the Board of Trustees of the St. Louis College of Pharmacy, as well as a Director of Jones Pharma Incorporated. He was formerly Chairman of the Board of Trustees of the Pilot Fund, a registered investment company. He was also formerly a Director of BHA, Inc. of Kansas City, Missouri, and a Director of GeoMet, Inc. of Houston, Texas. He currently serves as Advisory Director of US Bancorp. The board selected Mr. Armstrong to serve as a director because of his extensive experience in the coal industry and public company management, as well as his previous tenure with Armstrong Energy. The board believes his prior experiences afford him unique insights into Armstrong Energy’s strategies, challenges and opportunities.

Martin D. Wilson — Mr. Wilson served as the Predecessor’s President, and as a member of the Predecessor’s board of managers, from its formation in 2006 until the Reorganization in October 2011. Since

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the Reorganization, Mr. Wilson has been the President of Armstrong Energy. Mr. Wilson will be appointed as a member of our general partner’s board of directors prior to consummation of this offering. From 1985 to 1988, Mr. Wilson was employed by KPMG Peat Marwick. From 1988 until 2005, Mr. Wilson served as President and Chief Operating Officer of D&K Healthcare Resources. Mr. Wilson currently serves on the Board of Trustees of the St. Louis College of Pharmacy and is a former member of the Board of Directors of Healthcare Distribution Management Association (HDMA). The board selected Mr. Wilson to serve as a director because of his experience in public company management, finance and administration, as well as for his in-depth knowledge of Armstrong Energy.

Kenneth E. Allen — Mr. Allen served as the Predecessor’s Vice President of Operations from 2007 until the Reorganization in October 2011. Since the Reorganization, Mr. Allen has been Armstrong Energy’s Executive Vice President of Operations. He started his career with Peabody Coal Company in 1967 and has over 40 years of experience in the coal industry. In 1971, he moved into a supervisory position and continued to hold various supervisory and management positions, including Chief Electrical Engineer, Mine Superintendent, General Manager, Operations Manager, Vice President Resource Development and Conservancy. Prior to joining Armstrong Energy in 2007, Mr. Allen held the position of President and Operations Manager of Bluegrass Coal Company, a subsidiary of Peabody Energy. Mr. Allen is Chairman of the Upper Pond River Conservancy District, Chairman of Cedar West Inc., and member of the Madisonville Community College Energy Advisory Committee. He is a past member of the Kentucky Coal Counsel, the Kentucky Governors Finance Committee, and Kentucky Consortium for Energy and the Environment. He is past Chairman and current member of the Executive Boards of the Kentucky Coal Association and the Western Kentucky Coal Association.

David R. Cobb, P.E. — Mr. Cobb served as the Predecessor’s Vice President of Business Development from its inception in 2006 until the Reorganization in October 2011. Since the Reorganization, Mr. Cobb has been Armstrong Energy’s Executive Vice President of Business Development. He has over 40 years of experience in the coal business, beginning with AMAX Coal Company, where he served as a Resident Mine Engineer, Administrative Engineer, and Southern Division Engineer. In 1975, he joined Danco Engineering, a mine consulting firm located in Western Kentucky, serving as a Principal Engineer and later becoming its owner and President. Danco was acquired by Associated Engineers, Inc. in 2005. Mr. Cobb stayed on as the Director of Mining Services until joining Armstrong Energy in 2006. Mr. Cobb is registered in the fields of Civil and Mining Engineering and is licensed as a Professional Engineer in Kentucky, Indiana, and Illinois along with being a Certified Fire and Explosion Investigator. Mr. Cobb is a member of the Society of Mining Engineers, the National and Kentucky Societies of Professional Engineers, the American Society of Civil Engineers, the American Society of Surface Mining and Reclamation, and the National Association of Fire Investigators.

J. Richard Gist — Mr. Gist served as the Predecessor’s Vice President and Controller from 2009 until the Reorganization in October 2011. Since the Reorganization, Mr. Gist has been Armstrong Energy’s Senior Vice President, Finance and Administration and Chief Financial Officer. Mr. Gist began his career with Arthur Andersen in 1978 and subsequently held a number of positions at St. Joe Minerals, an entity which owned part of Massey Energy, NERCO, Ziegler Coal and Peabody Energy. From 2000 until its purchase by McKesson Corporation in 2005, Mr. Gist was the Vice President and Controller of D&K Healthcare Resources. From 2005 until 2006, Mr. Gist worked as part of the transition team with McKesson. From 2006 until 2009, he served as Vice President — Marketing Administration of Arch Coal. Mr. Gist is a Certified Public Accountant.

Brian G. Landry — Mr. Landry served as the Predecessor’s Vice President, Information Technology from 2010 until the Reorganization in October 2011. Since the Reorganization, Mr. Landry has been our Vice President, Information Technology. From 2007 until 2010, Mr. Landry served as Senior Vice President of Information Technology of H.D. Smith Drug Company. Prior to that, Mr. Landry spent 10 years with D&K Healthcare Resources, Inc., ultimately serving as its Senior Vice President of Operations and Chief Information Officer.

Anson M. Beard, Jr. — Mr. Beard was appointed to Armstrong Energy’s board in October 2011, and will be appointed as a member of our general partner’s board of directors prior to consummation of this offering. He joined Morgan Stanley & Co. as a Vice President to found Private Client Services in 1977. He was

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promoted to Principal in 1979 and Managing Director in 1980. In January 1981, he was put in charge of the Firm’s Equity Division, responsible for sales and trading relationships with institutional and individual investors of all equity and related products worldwide. In 1987, he was elected to the Firm’s Management Committee and the Board of Directors of Morgan Stanley Group. Mr. Beard was also the former Chairman of Morgan Stanley Security Services, Inc., a subsidiary of Morgan Stanley Group, which engaged in stock borrowing/lending, customer and dealer clearance, international settlements and custody. He previously served as a Trustee of the Morgan Stanley Foundation, Vice Chairman of the National Association of Securities Dealers, and Chairman of its NASDAQ, Inc. subsidiary. In February 1994, Mr. Beard retired and became an Advisory Director of Morgan Stanley. He continues to serve in this capacity. Mr. Beard was selected for board membership because of his past board and committee experience and his knowledge of securities markets and publicly traded companies.

James C. Crain — Mr. Crain was appointed to Armstrong Energy’s board of directors in October 2011, and will be appointed as a member of our general partner’s board of directors prior to consummation of this offering. Mr. Crain has been in the energy industry for over 30 years, both as an attorney and as an executive officer. Since 1984, Mr. Crain has been an officer of Marsh Operating Company, an investment management company focusing on energy investing, including his current position as president, which he has held since 1989. Mr. Crain has served as general partner of Valmora Partners, L.P., a private investment partnership that invests in the oil and gas sector, among others, since 1997. Before joining Marsh in 1984, Mr. Crain was a partner in the law firm of Jenkens & Gilchrist, where he headed the firm’s energy section. Mr. Crain is a director of Crosstex Energy, Inc., a midstream natural gas company, GeoMet, Inc., a natural gas exploration and production company, and Approach Resources, Inc., an independent oil and natural gas company. During the past five years, Mr. Crain has also been a director of Crosstex Energy, GP, LLC, the general partner of a midstream natural gas company, and Crusader Energy Group Inc., an oil and gas exploration and production company. The board selected Mr. Crain to serve as a director because of his extensive legal, investment and transactional experience, as well as his public company board experience.

Richard F. Ford — Mr. Ford was appointed to Armstrong Energy’s board in October 2011, and will be appointed as a member of our general partner’s board of directors prior to consummation of this offering. Mr. Ford is the retired general partner of Gateway Associates, L.P., a venture capital management firm that he formed in 1984. Mr. Ford serves as a member of the board of directors and a member of the audit committees of each of Barry-Wehmiller Company and Stifel Financial Corp. Mr. Ford also serves as a member of the board of directors and chair of the audit committee of Spartan Light Metal Products, Inc., a privately-held company. He currently serves on the board of directors of Washington University in St. Louis, Missouri. The board selected Mr. Ford to serve as a director because of his substantial experience in the financial services industry. He also has considerable board and committee leadership experience at other publicly held and large private companies.

Bryan H. Lawrence — Mr. Lawrence served as a member of the Predecessor’s board of managers from its formation in 2006 until the Reorganization. He was appointed to Armstrong Energy’s board of directors in October 2011, and will be appointed as a member of our general partner’s board of directors prior to consummation of this offering. He is a founder and principal of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co., Inc. where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence serves as a director of Crosstex Energy, Inc., Crosstex Energy GP, LLC, Hallador Energy Company, Star Gas Partners, L.P., and Approach Resources, Inc. (each a United States publicly traded company) and Winstar Resources, Ltd., (a Canadian public company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence serves on Armstrong Energy’s board of directors because of his significant knowledge of all aspects of the energy industry.

Greg A. Walker — Mr. Walker was appointed to Armstrong Energy’s board of directors in October 2011, and will be appointed as a member of our general partner’s board of directors prior to consummation of this offering. From 2009 to January 2011, he served as a Senior Vice President of Alpha Natural Resources, Inc., assisting with integration issues after the merger of Alpha Natural Resources, Inc. and Foundation Coal

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Holdings, Inc. From 2004 to 2009, Mr. Walker served as the Senior Vice President, General Counsel and Secretary of Foundation Coal Holdings, Inc. From 1999 to 2004, he served as the Senior Vice President, General Counsel and Secretary of RAG American Coal Holdings, Inc., which was the predecessor entity to Foundation Coal Holdings, Inc. From 1989 through 1999, he served in various capacities in the law department of Cyprus Amax Minerals Company. He spent three years in private law practice in Denver, Colorado from 1986 to 1989, and from 1981 through 1986 he held various positions within the law department of Mobil Oil Corporation. He has been a member of the board of directors since 2005, and Chairman in 2008, of the FutureGen Industrial Alliance, Inc., a not-for-profit entity whose global members are working with the United States Department of Energy to build and operate a commercial scale carbon dioxide sequestration project. He currently also serves as the Treasurer and Secretary of FutureGen. From 2007 through 2010, he served as an appointee from the United States to the Coal Industry Advisory Board, an international advisory panel to the International Energy Administration with respect to matters regarding the production, use and demand for coal on a global basis. The board selected Mr. Walker to serve as a director because of his specialized knowledge of the coal and energy industry and applicable regulations, as well as his experience in public company management.

Board of Directors and Board Committees

We anticipate that our general partner’s board will consist of seven directors and that it will establish an audit committee. In addition, the following committees of Armstrong Energy’s board will manage us, as well as Armstrong Energy: a compensation committee, a nominating, corporate governance and risk management committee and a conflicts committee. The composition and responsibilities of each committee are described below. Members serve on these committees until their resignation or until otherwise determined by the board.

The majority of our general partner’s board members will be independent at the time of listing with Nasdaq. We expect that the board will determine that each of Messrs. Beard, Crain, Ford and Walker is an independent director pursuant to the requirements

Armstrong Resource Partners, L.P. S-1/A