Armstrong Logistics Services 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)
Registration Nos. 333-191182

PROSPECTUS

Armstrong Energy, Inc.

OFFER TO EXCHANGE

All Outstanding Unregistered 11.75% Senior Secured Notes Due 2019

($200,000,000 Aggregate Principal Amount) (CUSIP No. 042380 AA3)

For

11.75% Senior Secured Notes Due 2019 ($200,000,000 Aggregate Principal Amount)

that Have Been Registered under the Securities Act of 1933

This exchange offer will expire at 5:00 p.m., New York City time,

on November 13, 2013, unless extended

We are offering to exchange, upon the terms and subject to the conditions set forth in this prospectus and the accompanying letter of transmittal, all of our outstanding unregistered $200,000,000 aggregate principal amount of 11.75% Senior Secured Notes due 2019 (CUSIP No. 042380 AA3) (the “Outstanding Notes”), for an equal amount of 11.75% Senior Secured Notes due 2019 that have been registered (the “Exchange Notes” and collectively with the Outstanding Notes, the “Notes”) under the Securities Act of 1933, as amended (the “Securities Act”). The Exchange Notes will be fully and unconditionally guaranteed on a senior secured basis by substantially all of our existing and future domestic restricted subsidiaries, subject to certain customary release provisions. See “Description of Exchange Notes—Note Guarantees.” The Outstanding Notes have certain transfer restrictions. The Exchange Notes will be freely transferable.

The principal features of the exchange offer, the Exchange Notes and the resales of Exchange Notes are as follows:

The Exchange Offer

• We will exchange all Outstanding Notes that are validly tendered and not validly withdrawn for an equal principal amount of Exchange Notes.

• You may withdraw tenders of Outstanding Notes at any time prior to the expiration of the exchange offer.

• The exchange offer expires at 5:00 p.m., New York City time, on November 13, 2013, unless extended. We do not currently intend to extend the exchange offer.

• The exchange of Outstanding Notes for Exchange Notes in the exchange offer will not constitute a taxable event for United States federal income tax purposes.

• We will not receive any proceeds from the exchange offer.

The Exchange Notes

• The Exchange Notes are being offered in order to satisfy certain of our obligations under the registration rights agreement entered into in connection with the placement of the Outstanding Notes.

• The terms of the Exchange Notes to be issued in the exchange offer are substantially identical to the Outstanding Notes, except that the Exchange Notes will be freely tradable, except in the limited circumstances described herein.

Resales of the Exchange Notes

• The Exchange Notes may be sold in the over-the-counter market, in negotiated transactions or through a combination of such methods. We do not plan to list the Exchange Notes on an exchange or national market.

All untendered Outstanding Notes will continue to be subject to the restrictions on transfer set forth in the Outstanding Notes and in the indenture. In general, the Outstanding Notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offer, we do not currently anticipate that we will register the Outstanding Notes under the Securities Act.

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer, where such Outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Outstanding Notes where the Outstanding Notes were acquired as a result of market-making activities or other trading activities. We will make this prospectus available to any broker-dealer for use in connection with any such resales until 180 days after the date of the consummation of this exchange offer. The accompanying letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. See “Plan of Distribution.”

We are an “emerging growth company,” as such term is defined in Section 2(a)(19) of the Securities Act.

You should carefully consider theRisk Factors beginning on page 17 of this prospectus before participating in this exchange offer.

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.

The date of this prospectus is October 15, 2013

Each holder of an unregistered Note wishing to accept the exchange offer must deliver the unregistered Note to be exchanged, together with the accompanying letter of transmittal and any other required documentation, to the exchange agent identified herein. Alternatively, you may effect a tender of unregistered Notes by book-entry transfer into the exchange agent’s account at The Depository Trust Company (“DTC”). All deliveries are at the risk of the holder. See “The Exchange Offer.”

You should rely only on the information contained in this prospectus. We have not authorized any person to provide you with any information or represent anything about us or this exchange offer that is different from or not contained in this prospectus. If given or made, any such other information or representation should not be relied upon as having been authorized by us. We are not making an offer to sell securities or soliciting an offer to buy securities in any jurisdiction where an offer or sale is not permitted.

This prospectus incorporates business and financial information about Armstrong Energy, Inc. that is not included or delivered with this prospectus. This information is available without charge to security holders upon written or oral request.You may request business and financial information incorporated but not included in this prospectus by writing to us at Armstrong Energy, Inc., 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105, Attention: Senior Vice President, Finance and Administration and Chief Financial Officer, or telephoning us at (314)721-8202. To obtain timely delivery, holders of Outstanding Notes must request the information no later than five business days before November 13, 2013, the date they must make their investment decision.

TABLE OF CONTENTS

	Page
NON-GAAP FINANCIAL MEASURES		i
INDUSTRY AND MARKET DATA		i
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS		ii
PROSPECTUS SUMMARY		1
RISK FACTORS		17
RATIO OF EARNINGS TO FIXED CHARGES		45
USE OF PROCEEDS		46
SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA		47
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		50
THE COAL INDUSTRY		78
BUSINESS		87
MANAGEMENT		119
EXECUTIVE OFFICER COMPENSATION		125
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		136
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		137
DESCRIPTION OF OTHER INDEBTEDNESS		143
THE EXCHANGE OFFER		144
DESCRIPTION OF EXCHANGE NOTES		153
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS		207
CERTAIN ERISA CONSIDERATIONS		208
PLAN OF DISTRIBUTION		209
LEGAL MATTERS		209
COAL RESERVES		209
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		210
WHERE YOU CAN FIND MORE INFORMATION		210
INDEX TO FINANCIAL STATEMENTS		F-1

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 exchange 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.

In this prospectus, unless the context otherwise requires, “Company”, “we”, “us”, and “our” refer to Armstrong Energy, Inc. and its subsidiaries, “Armstrong Resource Partners” refers to Armstrong Resource Partners, L.P. and its subsidiaries taken as a whole, and the term “Yorktown” collectively refers to Yorktown Partners LLC and/or certain investment funds managed by Yorktown Partners LLC.

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA, as presented in this prospectus, is a supplemental measure of our performance that is not required by, or presented in accordance with, accounting principles generally accepted in the United States (“GAAP”). It is not a measurement of our financial performance under GAAP and should not be considered as an alternative to net income or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as measures of our liquidity.

We define “Adjusted EBITDA” as net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, non-cash production royalty for related party, loss on settlement of interest rate swap, loss on deferment of equity offering, gain on settlement of asset retirement obligations, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt. We caution investors that amounts presented in accordance with our definition of Adjusted EBITDA may not be comparable to similar measures disclosed by other issuers, because not all issuers and analysts calculate Adjusted EBITDA in the same manner. We present Adjusted EBITDA because we consider it an important supplemental measure of our performance and believe it is useful to an investor in evaluating our company, as more fully discussed under “Prospectus Summary—Summary Historical Consolidated Financial and Operating Data.” Adjusted EBITDA has several limitations that are discussed under “Prospectus Summary—Summary Historical Consolidated Financial and Operating Data,” where we also include a quantitative reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial performance measure, which is net income.

The Securities and Exchange Commission (the “SEC”) has adopted rules to regulate the use in filings with the SEC and public disclosures and press releases of non-GAAP financial measures, such as Adjusted EBITDA, that are derived on the basis of methodologies other than in accordance with GAAP. The non-GAAP financial measures presented in this prospectus may not comply with these rules.

INDUSTRY AND MARKET DATA

We are responsible for the disclosure in this prospectus. However, this prospectus includes industry data that we obtained from periodic industry publications, as well as from research reports prepared for other purposes. Industry publications generally state that the information contained therein has been obtained from sources believed to be reliable. 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, 2012. In addition, we pay a subscription fee to Wood Mackenzie to obtain access

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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.

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 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;

• the continued weakness in global economic conditions or in any industry in which our customers operate, or sustained uncertainty in financial markets, which may cause conditions we cannot predict;

• the disruption of rail, barge and other systems that deliver our coal;

• coal users switching to other fuels in order to comply with various environmental standards related to coal combustion;

• volatility in the capital and credit markets;

• availability of skilled employees and other workforce factors;

• disruptions in the quantities of coal produced at our operations as a consequence of weather or equipment or mine failures;

• our ability to collect payments from our customers;

• defects in title or the loss of a leasehold interest;

• railroad, barge, truck and other transportation performance and costs;

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• our ability to secure new coal supply arrangements or to renew existing coal supply arrangements;

• our relationships with, and other conditions affecting, our customers;

• the deferral of contracted shipments of coal by our customers;

• our ability to service our outstanding indebtedness;

• our ability to comply with the restrictions imposed by our Revolving Credit Facility, the indenture governing the Notes and other financing arrangements;

• the availability and cost of surety bonds;

• terrorist attacks, military action or war;

• our ability to obtain and renew various permits, including permits authorizing the disposition of certain mining waste;

• existing and future legislation and regulations affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxide, nitrogen oxides, toxic gases, such as hydrogen chloride, particulate matter or greenhouse gases;

• the accuracy of our estimates of reclamation and other mine closure obligations;

• customers’ ability to meet existing or new regulatory requirements and associated costs, including disposal of coal combustion waste material;

• our ability to attract/retain key management personnel;

• efforts to organize our workforce for representation under a collective bargaining agreement; and

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

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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 17 of this prospectus and the financial statements and related notes thereto included elsewhere in this prospectus.

Company Overview

We are a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin, with both surface and underground mines. We market our coal primarily to proximate and investment grade electric utility companies as fuel for their steam-powered generators. Based on 2012 production, we are the fifth largest producer in the Illinois Basin and the second largest in Western Kentucky. We were formed in 2006 to acquire and develop a large coal reserve holding. We commenced production in the second quarter of 2008 and currently operate seven mines, including four surface and three underground, and are seeking permits for three additional mines. We control approximately 322 million tons of proven and probable coal reserves. We also own and operate three coal processing plants which support our mining operations. From our reserves, we mine coal from multiple seams that, in combination with our coal processing facilities, enhance our ability to meet customer requirements for blends of coal with different characteristics. The locations of our coal reserves and operations, adjacent to the Green River, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling, and provide our customers with rail, barge and truck transportation options.

Our revenue has increased from zero in 2007 to $382.1 million for the year ended December 31, 2012 and our net loss and Adjusted EBITDA totaled $18.0 million and $50.9 million, respectively, for 2012.

For the year ended December 31, 2012, we produced 8.8 million tons of coal. As of August 31, 2013, we are contractually committed to sell 9.2 million tons of coal in 2013 and 8.2 million tons of coal in 2014, which represent 98% and 84% of our expected total coal sales in 2013 and 2014, respectively. The following table summarizes our mines, our production and our coal reserves for the periods indicated:

			Clean Recoverable Coal (Proven and Probable Reserves)(1)							Production						Quality Specifications (As Received)(2)
Mines (Commenced Operations)	Mining Method(3)		Proven Reserves		Probable Reserves		Total			Year Ended December 31, 2012			Six Months Ended June 30, 2013			Heat Value (Btu/ Lb)		SO2 Content (Lbs/ MMBtu)
	(Tons in thousands)
Active mines
Midway (July 2008)		S		16,440		2,122		18,562	(4)		1,518			697			11,112		4.6
Parkway (April 2009)		U		6,933		4,747		11,680			1,558			729			11,925		4.3
East Fork (June 2009)(5)		S		2,604		543		3,147	(4)		41			—			11,078		7.8
Equality Boot (September 2010)		S		19,656		826		20,482	(6)		2,868			1,327			11,401		5.6
Lewis Creek (June 2011)		S		5,140		97		5,237	(4)		942			446			11,198		4.9
Kronos (September 2011)		U		16,775		2,395		19,170	(7)		1,842			1,313			11,793		4.5
Lewis Creek (March 2013)		U		18,676		2,666		21,342	(7)		—			165			11,793		4.5
Total active mines				86,224		13,396		99,620			8,769	(8)		4,677	(9)
Additional reserves
Ken		S		17,166		3,854		21,020	(4)		—			—			11,809		5.0
Union/Webster		U		47,281		80,187		127,468			—			—			12,435		4.4
Other		S/U		58,807		14,681		73,488	(10)		—			—			11,688		5.1
Total additional reserves				123,254		98,722		221,976			—			—
Total				209,478		112,118		321,596			8,769	(8)		4,677	(9)
Other inferred recoverable resources(11)								104,356

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(1) As of December 31, 2012. For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.

(2) Quality specifications displayed on an “as received” basis. If derived from multiple seams, data represents an average.

(3) U = Underground; S = Surface.

(4) Of these reserves, 50.81% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2012.

(5) Warden and Kronos pits. Production at the Kronos pit ceased in August 2011 and the Warden pit was temporarily idled in March 2012.

(6) Of these reserves, 50.81% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2012. Includes approximately 0.3 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.

(7) Based on internal estimates, recoverable reserves are split among the three mines that will produce coal from the underground properties and coal reserves located in Ohio County, Kentucky that are owned by Armstrong Resource Partners and leased to Armstrong Energy (the “Elk Creek Reserves”).

(8) Of this amount, 76 tons and 31 tons of production from the Kronos and Lewis Creek underground mines, respectively, was capitalized because they were in the developmental phase.

(9) Of this amount, 156 tons and 28 tons of production from the Lewis Creek underground and surface mines, respectively, was capitalized because they were in the developmental phase.

(10) Of these reserves, excluding an estimated 21.3 million tons of Elk Creek Reserves, 50.81% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2012. Includes approximately 1.9 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.

(11) Other inferred resources includes tonnage for which tonnage, grade and mineral content can be estimated with a low level of confidence. It is inferred from geological evidence and assumed but not verified geological/or grade continuity. Inferred resources are computed by projecting data from available seam measurements to distances beyond those used for the probable classification. These numbers are based on information gathered through appropriate techniques from location such as outcrops, trenches, pits, workings and drill holes which may be of limited or uncertain quality and reliability.

Our Credit Strengths

We have a demonstrated track record of successfully completing reserve acquisitions, developing new mines, securing required permits and producing coal. Since our formation in 2006, we have successfully completed a series of reserve acquisitions totaling approximately $261 million, with acquisition sizes ranging from $9.0 million to $75.6 million. We have also opened nine 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 investment-grade customers in our market area. We believe this resulted from our deep management experience and disciplined approach to the development of our operations as well as our focus on providing competitively priced Illinois Basin coal to customers. We believe this will enable us to continue to maintain our current, and grow our future, customer base, production, revenues and profitability.

We have multi-year supply agreements with investment grade customers.As of August 31, 2013, we had approximately 9.2 million and 8.2 million tons of coal committed under long-term contracts for calendar years2013 and 2014, respectively. These committed amounts represent 98% and 84% of our expected total coal sales in 2013 and 2014, respectively. We believe that our committed and priced position relative to anticipatedproduction is amongst the highest of any coal producer in the United States, based on publicly available information. We intend to continue to opportunistically grow our production commensurate with long-term sales. Our coal is shipped to 14 different power plants owned and run by primarily investment grade electric utility companies.

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Our proven and probable reserves have a long reserve life and attractive characteristics.As of December 31, 2012, we had approximately 322 million tons of clean recoverable (proven and probable) coal reserves and approximately 104 million tons of additional contiguous inferred recoverable resources. Our reserves include both surface and underground mineable coal residing in multiple seams that, in combination with our coal processing facilities, enhance our ability to meet customer requirements for blends of coal with different characteristics. Further, the comparatively low chlorine content of our coal relative to other Illinois Basin coal provides us with an additional competitive advantage in meeting the desired coal fuel profile of our customers.

Our mines are conveniently located in close proximity to our existing and potential customers and have access to multiple transportation options for delivery. Our active mines are located adjacent to the Green River and near our preparation, loading and transportation facilities, providing our customers with rail, barge and truck transportation options and resulting in low delivered cost. We believe this also enables us to sell our coal in both the domestic and export markets. Recently, we purchased an equity interest in, and upon development will have access to, a Mississippi River coal export terminal project in Plaquemines Parish, Louisiana,approximately 10 miles downstream of New Orleans. We intend to oversee the initial design, build-out and operation of this export coal terminal to facilitate the anticipated sale of a portion of our coal to international customers.

Our liquidity position is strong and supports our business strategy.We had $44.7 million in cash and cash equivalents as of June 30, 2013. In addition, under our $50.0 million revolving credit facility (the “Revolving Credit Facility”), we had no borrowings and $19.7 million of undrawn availability as of June 30, 2013. We believe that cash on hand, cash generated from operations and availability under our Revolving Credit Facility will be sufficient to meet working capital requirements, fund anticipated capital expenditures and opportunistic acquisitions, and service outstanding indebtedness.

We have a highly productive, non-union workforce and our business is unencumbered by legacy liabilities.Our highly skilled, non-union workforce uses efficient mining practices that take advantage of economies of scale and reduce operating costs in both surface and underground mining. We believe we are among a small number of operators of large scale dragline surface production in the eastern United States, and our continuous miner underground mining operations are designed to provide operating flexibility to meet production requirements and to fulfill our coal contract specifications. Additionally, our business has minimal exposure to legacy liabilities such as pension benefit obligations and retiree healthcare benefits.

We have a highly experienced management team with a long history of acquiring, building and operating coal businesses.The members of our senior management team have a demonstrated track record of acquiring, building and operating coal businesses profitably and safely. In addition, members of our senior management team have significant experience managing the financial and organizational growth of businesses, including public companies.

Our Business Strategy

Maintain safe mining operations and comply with environmental standards.We consider safety to be our greatest operational priority. We have won numerous awards for our safety record since 2008 recognizing our low injury and incident rates. We intend to maintain programs and policies designed to enable us to remainamong the safest coal operators in the industry. We also intend to continue to implement responsible, effective environmental practices throughout our operations and reclamation activities.

Increase and diversify coal sales to utilities with base load scrubbed power plants in our primary market area and pursue export opportunities. We expect that the demand for Illinois Basin coal will rise as a result of an increase in power plants being retrofitted with flue gas desulfurization (“FGD”) units, or scrubbers. We intend to

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continue to focus our marketing efforts principally on power plants in the Mid-Atlantic, Southeastern and Midwestern states that we expect will become consumers of Illinois Basin coal and to seek to diversify our customer base through a combination of multi-year coal supply agreements and sales in the spot market. As of August 31, 2013, we are contractually committed to sell 9.2 million tons of coal in 2013 and 8.2 million tons of coal in 2014, which represent 98% and 84% of our expected total coal sales in 2013 and 2014, respectively. In addition, we believe that the relative heat, ash, sulfur content and cost of our coal, combined with the accessibility of our coal mines and coal processing facilities to the Mississippi River and to rail connecting to Louisiana export terminals, will provide opportunities to export our coal to overseas customers.

Continue to grow our production opportunistically.We intend to continue to increase our coal production opportunistically in the coming years as the market environment allows and commensurate with our ability to secure supply agreements in support of this growth. We also intend to continue to make opportunistic contiguous reserve acquisitions in amounts approximately consistent with our acquisition experience. We believe our disciplined growth will be supported by an increasing demand for Illinois Basin coal. We will seek to support production growth by executing mining plans for our existing undeveloped reserves and by opportunistically acquiring additional coal reserves that are located near our current mining operations or otherwise offer the potential for efficient and economical development of low-cost production to serve our primary market area.

Maximize profitability by maintaining low-cost mining operations.We operate our mines in a manner aimed at keeping our product quality high while maintaining low production costs. We seek to maximize our coal production and control our costs by continuing to improve our operating efficiency. Our efficiency is, in part, a function of the overburden ratios (the amount of surface material needed to be removed to extract coal) that exist at our surface coal mines. Our efficiency is also enhanced by our fleet of mobile mining equipment, our use of what we believe to be the only draglines in Kentucky, our utilization of river coal movement, our information technology systems and our coordinated equipment utilization and maintenance management functions. We also believe that our highly experienced operating management and well-trained workforce will continue to help in identifying and implementing cost containment initiatives, such as near-term operating synergies from any potential future reserve acquisitions.

Coal Industry Overview

According to the U.S. Department of Energy’s Energy Information Administration (“EIA”), the U.S. coal industry produced approximately 1.0 billion tons of coal in 2012, 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.

• Increasing demand for coal produced in the Illinois Basin. We believe the increasing demand for coal produced in the Illinois Basin is due to a combination of factors including:

• Significant expansion of scrubbed coal-fired electricity generating capacity. The EIA forecasts a 22% increase in FGD installed on the coal-fired generation fleet by 2040 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. This represents an increase from 192 gigawatts in 2011 to 235 gigawatts, or 86% of all U.S. coal-fired capacity in the electric sector. The EIA estimates that in 2011, approximately 61% of all U.S. coal-fired generation operating or under construction had FGD technology installed. 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

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operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.

• Declines in Central Appalachian thermal coal production. Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 84 million tons in 2013 to 49 million tons in 2015, due to reserve depletion, regulatory-driven decreases in surface production and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.

• Growing demand for seaborne thermal coal. Global thermal coal exports are projected to rise from 890 million tons in 2012 to 1.1 billion tons by 2018. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to both the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.

• Stable long-term outlook for U.S. thermal coal market. According to the EIA, coal-fired electricity generation accounted for approximately 37% of all electricity generation in the United States in 2012. 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 2040, at 35% of total generation.

Recent Developments

In July 2013, our Lewis Creek underground mine came out of development and was placed in active production. Lewis Creek is a two unit mine that extracts coal from the West Kentucky #9 coal seam.

On June 28, 2013, Thoroughbred Resources, LLC (“Thoroughbred”), an entity wholly owned by Yorktown, acquired approximately 65 million tons of fee-owned underground coal reserves and 40 million tons of leased underground coal reserves from Peabody Energy, Inc. and certain of its affiliates (“Peabody”). The acquired coal reserves are located in Muhlenberg and McLean Counties of Kentucky, contiguous to Armstrong Energy’s reserves. It is intended that these reserves will be leased to us in exchange for a production royalty.

In connection with Thoroughbred’s acquisition of these reserves, we loaned Thoroughbred $17.5 million, which was repaid in July 2013. The proceeds of the loan, which was evidenced by a promissory note, were used to make a portion of the down payment to Peabody for the reserves.

Corporate Information

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

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Corporate Structure

The following chart shows a summary of the corporate structure of Armstrong Energy, Inc. and certain of its relationships.

(1) A portion of our reserves are controlled jointly by our affiliate, Armstrong Resource Partners (with a 53.4% undivided interest as of June 30, 2013), and Armstrong Energy (with a 46.6% undivided interest as of June 30, 2013) and certain of our remaining reserves are owned solely by Armstrong Resource Partners, with whom we have a long-term leasehold interest. See “Business—About Armstrong Resource Partners” and “Certain Relationships and Related Party Transactions—Lease Agreements.” These reserves include the Kronos and Lewis Creek underground mines.

Emerging Growth Company Status

We are an “emerging growth company,” as defined in Section 2(a)(19) of 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 and proxy statements, and exemptions from the requirements of holding a non-binding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We have not made a decision whether to take advantage of any or all 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, and delay compliance with new or revised accounting standards until those standards are applicable to private companies. However, we intend 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

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provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

We could be an emerging growth company until the last day of the first fiscal year following the fifth anniversary of our first common equity offering, although circumstances could cause us to lose that status earlier if our annual revenues exceed $1.0 billion, if we issue more than $1.0 billion in non-convertible debt in any three-year period or if we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Yorktown Partners LLC

We are majority-owned by Yorktown. 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.

After giving effect to this exchange offer, we will continue to be majority-owned by Yorktown. In addition, Yorktown is represented on our board by Bryan H. Lawrence, founder and principal of Yorktown Partners LLC. As a result, Yorktown has, and can be expected to have, a significant influence in our operations, in the outcome of stockholder voting concerning the election of directors, the adoption or amendment of provisions in our charter and bylaws, the approval of mergers, and other significant corporate transactions.

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The Exchange Offer

On December 21, 2012, we completed a private offering of the Outstanding Notes. Concurrently with the private offering, we entered into a registration rights agreement with the initial purchasers. Pursuant to the registration rights agreement, we agreed, among other things, to file the registration statement of which this prospectus is a part. The following is a summary of the exchange offer. Certain of the terms and conditions described below are subject to important limitations and exceptions. “The Exchange Offer,” beginning on page 17 of this prospectus, contains a more detailed description of the terms and conditions of the exchange offer. In this section, the “Company” refers to Armstrong Energy, Inc. only and not any of its subsidiaries.

General The form and terms of the Exchange Notes are substantially the same as the form and terms of the Outstanding Notes except that:

• The issuance and sale of the Exchange Notes have been registered pursuant to a registration statement under the Securities Act; and

• The holders of the Exchange Notes will not be entitled to registration rights or the liquidated damages provision of the registration rights agreement, which permits an increase in the interest rate on the Outstanding Notes in some circumstances relating to the timing of the exchange offer. See “The Exchange Offer.”

The Exchange Offer We are offering to exchange $200,000,000 aggregate principal amount of 11.75% Senior Secured Notes due 2019 that have been registered under the Securities Act for all of our outstanding unregistered 11.75% Senior Secured Notes due 2019.

The exchange offer will remain in effect for a limited time. We will accept any and all Outstanding Notes validly tendered and not validly withdrawn prior to 5:00 p.m., New York City time, on November 13, 2013. Holders may tender some or all of their Outstanding Notes pursuant to the exchange offer. Outstanding Notes, however, may be tendered only in a denomination equal to $2,000 and integral multiples of $1,000 in excess thereof.

Resale Based upon interpretations by the staff of the SEC set forth in no-action letters issued to unrelated third-parties, we believe that the Exchange Notes may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery requirements of the Securities Act, unless you:

• are an “affiliate” of ours within the meaning of Rule 405 under the Securities Act;

• are a broker-dealer that purchased the Outstanding Notes directly from us for resale under Rule 144A, Regulation S or any other available exemption under the Securities Act;

• acquired the Exchange Notes other than in the ordinary course of your business;

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• have an arrangement with any person to engage in the distribution of the Exchange Notes; or

• are prohibited by law or policy of the SEC from participating in the exchange offer.

However, we have not obtained a no-action letter, and there can be no assurance that the SEC will make a similar determination with respect to the exchange offer. Furthermore, in order to participate in the exchange offer, you must make the representations set forth in the letter of transmittal that we are sending you with this prospectus.

Expiration Date The exchange offer will expire at 5:00 p.m., New York City time, on November 13, 2013.

Conditions to the Exchange Offer The exchange offer is subject to certain customary conditions, some of which may be waived by us. See “The Exchange Offer—Conditions to the Exchange Offer.”

Procedures for Tendering Outstanding Notes To participate in the exchange offer, you must properly complete and duly execute a letter of transmittal, which accompanies this prospectus, and transmit it, along with all other documents required by such letter of transmittal, to the exchange agent on or before the expiration date at the address provided on the cover page of the letter of transmittal.

In the alternative, you can tender your Outstanding Notes by following the automated tender offer program (“ATOP”) procedures established by DTC for tendering Notes held in book-entry form, as described in this prospectus, whereby you will agree to be bound by the letter of transmittal and we may enforce the letter of transmittal against you.

If a holder of Outstanding Notes desires to tender such Notes and the holder’s Outstanding Notes are not immediately available, or time will not permit the holder’s Outstanding Notes or other required documents to reach the exchange agent before the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected pursuant to the guaranteed delivery procedures described in this prospectus. For more details, please read “The Exchange Offer—Procedures for Tendering,” “The Exchange Offer—Book-Entry Delivery Procedures” and “The Exchange Offer—Guaranteed Delivery Procedures.”

Special Procedures for Beneficial Owners If you are a beneficial owner of Outstanding Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender those Outstanding Notes in the exchange offer, you should contact the registered holder promptly and instruct the registered holder to tender those Outstanding Notes on

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your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Notes, either make appropriate arrangements to register ownership of the Outstanding Notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration date.

Withdrawal Rights You may withdraw your tender of Outstanding Notes at any time prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please read “The Exchange Offer—Withdrawal of Tenders.”

Acceptance of Outstanding Notes and Delivery of Exchange Notes Subject to customary conditions, we will accept Outstanding Notes that are properly tendered in the exchange offer and not validly withdrawn prior to 5:00 p.m., New York City time, on the expiration date. The Exchange Notes will be delivered promptly following the expiration date. We will return any Outstanding Notes that we do not accept for exchange promptly after expiration or termination of the exchange offer.

Consequences of Failure to Exchange Outstanding Notes If you do not exchange your Outstanding Notes in the exchange offer, you will no longer be able to require us to register the Outstanding Notes under the Securities Act, except in the limited circumstances provided under the registration rights agreement, and will not be entitled to the liquidated damages provision of the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the Outstanding Notes unless we have registered the Outstanding Notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

Interest on the Exchange Notes and the Outstanding Notes The Exchange Notes will bear interest from the most recent interest payment date on which interest has been paid on the Outstanding Notes. Holders whose Outstanding Notes are accepted for exchange will be deemed to have waived the right to receive interest accrued on the Outstanding Notes.

Broker-Dealers Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer, where such Outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. See “Plan of Distribution.”

Risk Factors You should consider carefully all of the information set forth in this prospectus and, in particular, you should evaluate the specific factors

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under the section entitled “Risk Factors” in this prospectus before deciding to invest in the Exchange Notes.

Certain Federal Income Tax Considerations Neither the registration of the Outstanding Notes pursuant to our obligations under the registration rights agreement nor the holder’s receipt of Exchange Notes in exchange for Outstanding Notes will constitute a taxable event for U.S. federal income tax purposes. Please read “Certain U.S. Federal Income Tax Considerations.”

Exchange Agent Wells Fargo Bank, National Association, the trustee and collateral agent under the indenture governing the Notes, is serving as exchange agent in connection with the exchange offer.

Use of Proceeds The issuance of the Exchange Notes will not provide us with any new proceeds. We are making the exchange offer solely to satisfy certain of our obligations under the registration rights agreement.

Fees and Expenses We will bear all expenses related to the exchange offer. Please read “The Exchange Offer—Fees and Expenses.”

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THE EXCHANGE NOTES

The following is a brief summary of some of the principal terms of the Exchange Notes and is not intended to be complete. You should carefully review the “Description of Exchange Notes” section of this prospectus, which contains a detailed description of the terms and conditions of the Exchange Notes.

Issuer Armstrong Energy, Inc.

Exchange Notes Offered $200,000,000 aggregate principal amount of 11.75% senior secured notes due 2019 which are registered under the Securities Act.

Maturity Date December 15, 2019.

Issue Price 96.567%.

Original Issue Discount Because the principal amount of the Exchange Notes exceeds their issue price by an amount that is equal to or greater than a statutoryde minimis amount, the Exchange Notes will be treated as issued with original issue discount (“OID”) for U.S. federal income tax purposes in an amount equal to such difference. U.S. holders of such Exchange Notes generally must include the OID in gross income over the term of the Exchange Notes on a constant-yield basis in advance of the receipt of cash attributable to such income.

Interest Interest on the Exchange Notes will accrue at a rate of 11.75% per annum and be payable semi-annually in cash in arrears on June 15 and December 15 of each year, commencing December 15, 2013.

Guarantees The Exchange Notes will be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by the Company and substantially all of its future domestic restricted subsidiaries, subject to certain customary release provisions. See “Description of Exchange Notes—Note Guarantees.” The Exchange Notes and the guarantees will be effectively subordinated to indebtedness under our Revolving Credit Facility to the extent of the value of the collateral securing our Revolving Credit Facility on a first-priority basis.

Security Interest The Exchange Notes and the guarantees will be secured, subject to certain exceptions and permitted liens, on a first-priority basis by our and the guarantors’ existing and after-acquired owned and leased real property, coal mines, reserves, stock of subsidiaries and substantially all of our and the guarantors other assets that do not secure our Revolving Credit Facility on a first-priority basis (the “Exchange Notes Priority Collateral”). Subject to certain exceptions and permitted liens, the Exchange Notes and the guarantees will also be secured on a second-priority basis by a lien on the assets securing our obligations under our Revolving Credit Facility on a first-priority basis, including present and future receivables, inventory and certain other assets and the proceeds thereof (the “Revolver Collateral” and, together with the Exchange Notes Priority Collateral, the “Collateral”). See “Description of Exchange Notes—Security.”

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Ranking The Exchange Notes will be our and the guarantors’ senior secured obligations and will:

• rank equal in right of payment with our and the guarantors’ existing and future senior indebtedness;

• rank senior in right of payment to all of our and the guarantors’ existing and future subordinated indebtedness;

• be effectively junior to our and the guarantors’ indebtedness and obligations under our Revolving Credit Facility to the extent of the value of the Revolver Collateral;

• be effectively senior to our and the guarantors’ indebtedness and obligations under our Revolving Credit Facility to the extent of the value of the Exchange Notes Collateral;

• be effectively senior to all existing and future senior unsecured debt to the extent of the value of the Collateral; and

• be structurally subordinated to all indebtedness and other liabilities of each of our future non-guarantor subsidiaries.

As of June 30, 2013, excluding $104.9 million of certain long-term obligations to Armstrong Resource Partners that are characterized as financing transactions, we had $211.0 million of indebtedness outstanding, consisting of the Notes, capital leases and other long-term debt.

Intercreditor Agreement The trustee and the administrative agent under the Revolving Credit Facility are parties to an intercreditor agreement as to the relative priorities of their respective security interests in the assets securing the Exchange Notes and the guarantees and borrowings under the Revolving Credit Facility and certain other matters relating to the administration of security interests. See “Description of Exchange Notes—Intercreditor Agreement.”

Optional Redemption On or after December 15, 2016, we may redeem some or all of the Notes at any time at the redemption prices described in the section “Description of Exchange Notes—Optional Redemption.” Prior to such date, we may redeem some or all of the Exchange Notes at a redemption price of 100% of the principal amount plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium.

In addition, we may redeem up to 35% of the aggregate principal amount of the Exchange Notes before December 15, 2015 with the proceeds of certain equity offerings at a redemption price of 111.75% plus accrued and unpaid interest, if any, to the redemption date.

Change of Control Offer If a Change of Control occurs, each holder of Exchange Notes may require us to repurchase all or a portion of its Exchange Notes at a purchase price equal to 101% of the principal amount of the

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Exchange Notes, plus accrued interest. See “Description of Exchange Notes—Repurchase of Notes upon a Change of Control.”

Certain Covenants The indenture governing the Exchange Notes contains covenants limiting the ability of the Company and its restricted subsidiaries to:

• incur additional indebtedness and issue preferred equity;

• pay dividends or distributions on or purchase our stock or our restricted subsidiaries’ stock;

• make certain investments;

• use assets as security in other transactions;

• create guarantees of indebtedness by restricted subsidiaries;

• enter into agreements that restrict dividends, distributions, or other payments by restricted subsidiaries;

• sell certain assets or merge with or into other companies; and

• enter into transactions with affiliates.

These covenants are subject to a number of important limitations and exceptions. See “Description of Exchange Notes.”

Absence of an Established Market for the Notes The Exchange Notes will be a new class of securities for which there is currently no market. Accordingly, we cannot assure you that a liquid market for the Exchange Notes will develop or be maintained. We do not intend to apply for listing of the Exchange Notes on any securities exchange or for the inclusion of the Exchange Notes in any automated quotation system.

Risk Factors See “Risk Factors” and the other information in this prospectus for a discussion of factors you should carefully consider before deciding to exchange your Outstanding Notes.

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Summary Historical Consolidated Financial and Operating Data

The following table presents our summary historical consolidated financial and operating data for the periods indicated for Armstrong Energy, Inc. and its subsidiaries and Armstrong Energy, Inc.’s predecessor, Armstrong Land Company, LLC, and its subsidiaries (our “Predecessor”). The summary historical financial data for the years ended December 31, 2010, 2011 and 2012 and the balance sheet data as of December 31, 2010, 2011 and 2012 are derived from the audited financial statements of Armstrong Energy and our Predecessor. The summary historical financial data for the six months ended June 30, 2012 and 2013 and the balance sheet data as of June 30, 2012 and 2013 are derived from the unaudited financial statements included herein.

As of October 1, 2011, we no longer consolidate the results of operations of Armstrong Resource Partners in our consolidated financial statements and we account for our ownership in Armstrong Resource Partners under the equity method of accounting. As a result, our financial results for the year ended December 31, 2010 are not directly comparable to our financial results for the years ended December 31, 2011 or 2012. For more information, please see Note 3, “Deconsolidation of Armstrong Resource Partners,” to our audited financial statements included in this prospectus.

Historical consolidated financial and operating information is included for illustrative and informational purposes only and is not necessarily indicative of results we expect in future periods. You should read the following summary financial data in conjunction with “Selected Historical Consolidated Financial and Operating Data” 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.

	Predecessor
	Year Ended December 31,									Six Months Ended June 30,
	2010			2011			2012			2012			2013
										(Unaudited)
Results of Operations Data
Total revenues	$	220,625		$	299,270		$	382,109		$	193,173		$	202,466
Costs and expenses:
Operating costs and expenses, exclusive of items shown separately below		151,838			221,597			282,569			137,794			146,606
Production royalty to related party		—			578			5,695			2,363			4,017
Depreciation, depletion, and amortization		18,892			27,661			33,066			16,119			17,765
Asset retirement obligation expenses		3,087			4,005			3,977			2,140			1,165
Selling, general, and administrative expenses		27,656			37,494			50,154			25,324			26,975
Operating income		19,152			7,935			6,648			9,433			5,938
Interest expense		(11,070	)		(10,839	)		(19,268	)		(9,050	)		(17,242	)
Other income (expense), net		87			278			(1,466	)		393			275
(Loss) gain on extinguishment of debt		—			6,954			(3,953	)		—			—
Income (loss) before income taxes		8,169			4,328			(18,039	)		776			(11,029	)
Income tax provision		—			(856	)		—			—			—
Net income (loss)	$	8,169		$	3,472		$	(18,039	)	$	776		$	(11,029	)
Balance Sheet Data (at period end)
Total assets	$	478,038		$	507,908		$	560,309		$	504,502		$	571,122
Working capital		2,905			(30,629	)		48,873			(33,181	)		39,120
Total long-term debt(1)		123,996			159,709			203,896			125,761			203,366
Total stockholders’ equity		296,681			168,138			182,662			199,475			171,069

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	Predecessor
	Year Ended December 31,						Six Months Ended June 30,
	2010		2011		2012		2012		2013
							(Unaudited)
Other Data
Tons sold (unaudited)		5,387		7,030		8,521		4,263		4,454
Tons produced (unaudited)		5,645		6,642		8,769		4,454		4,677
Sales price per ton (unaudited)	$	40.96	$	42.57	$	44.84	$	45.32	$	45.45
Operating cost per ton (unaudited)	$	28.19	$	31.52	$	33.16	$	32.33	$	32.91
Adjusted EBITDA per ton (unaudited)	$	7.63	$	5.92	$	5.97	$	7.22	$	6.59
Investments in property, plant, equipment and mine development		41,755		73,627		46,464		29,778		23,372
Adjusted EBITDA (unaudited)(2)		41,099		41,601		50,854		30,764		29,330

(1) Does not include certain long-term obligations to Armstrong Resource Partners of $71.0 million and $98.4 million as of December 31, 2011 and 2012, respectively, and $96.8 million and $104.9 million as of June 30, 2012 and 2013, respectively, that are characterized as financing transactions due to our continuing involvement in the lease of the related land and mineral reserves.

(2) Adjusted EBITDA is a non-GAAP financial measure, and when analyzing our operating performance, investors should use Adjusted EBITDA in addition to, and not as an alternative for, operating income and net income (loss) (each as determined in accordance with GAAP). Adjusted EBITDA is defined as net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, non-cash production royalty to related party, loss on settlement of interest rate swap, loss on deferment of equity offering, gain on settlement of asset retirement obligations, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt. The following is a reconciliation of Adjusted EBITDA to net income (loss) the most directly comparable GAAP measure:

	Predecessor
	Year Ended December 31,								Six Months Ended June 30,
	2010		2011			2012			2012		2013
Net income (loss)	$	8,169	$	3,472		$	(18,039	)	$	776	$	(11,029	)
Income tax provision		—		856			—			—		—
Depreciation, depletion and amortization		21,979		31,666			37,043			18,259		18,930
Non-cash production royalty to related party		—		578			5,695			2,363		4,017
Interest expense, net		10,872		10,694			19,200			9,016		17,212
Non-cash stock compensation expense		79		1,383			697			350		290
Loss on settlement of interest rate swap		—		—			1,409			—		—
Loss on deferment of equity offering		—		—			1,130			—		—
Gain on settlement of asset retirement obligations		—		—			(234	)		—		(90	)
(Gain) loss on extinguishment of debt		—		(6,954	)		3,953			—		—
Non-cash charge related to non-recourse notes		—		217			—			—		—
Gain on deconsolidation		—		(311	)		—			—		—
	$	41,099	$	41,601		$	50,854		$	30,764	$	29,330

Adjusted EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies, and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.

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RISK FACTORS

An investment in the Exchange Notes involves significant risks. In addition to matters described elsewhere in this prospectus, you should carefully consider the following risks involved with an investment in the Exchange Notes. You are urged to consult your own legal, tax or financial counsel for advice before making a decision to participate in the exchange offer. The occurrence of any one or more of the following could materially adversely affect an investment in the Exchange Notes or our business and operating results. If that occurs, you could lose some or all of your investment in, or fail to achieve the expected return on, the Exchange Notes.

Risks Related to Our Business

Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our profitability and the value of our coal reserves.

Our profitability and the value of our coal reserves depend upon the prices we receive for our coal. The contract prices we may receive in the future for coal depend upon factors beyond our control, including the following:

• the domestic and foreign supply and demand for coal;

• the demand for electricity;

• 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.

A substantial or extended decline in the prices we receive for our future coal sales contracts or on the spot market could materially and adversely affect us by decreasing our profitability and the value of operating our coal reserves.

Our business requires substantial capital expenditures and we may not have access to the capital required to reach full productive capacity at our mines.

Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations require substantial capital expenditures. While a significant amount of the capital expenditures required to build-out our mines has been spent, we must continue to invest capital to maintain our production. Decisions to increase our production could also affect our capital needs. We

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cannot assure you that we will be able to maintain our production levels or generate sufficient cash flow, or that we will have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels and on our current or projected timelines and we may be required to defer all or a portion of our capital expenditures. Our results of operations, business and financial condition, as well as our ability to satisfy our obligations under the Notes, may be materially adversely affected if we cannot make such capital expenditures.

Our coal mining operations are subject to operating risks that are beyond our control, which could result in materially increased operating expenses and decreased production levels and could materially and adversely affect our profitability.

We mine coal both at underground and at surface mining operations. Certain factors beyond our control, including those listed below, could disrupt our coal mining operations, adversely affect production and shipments and increase our operating costs:

• 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 our operating areas, such as coalbed methane extraction or oil and gas development.

If any of these conditions or events occurs, we could experience a delay or halt of production or shipments or our operating costs could increase significantly.

Competition within the coal industry could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.

We compete with numerous other coal producers in the Illinois Basin and in other coal producing regions of the United States, primarily Central Appalachia and the Powder River Basin. The most important factors on which we compete 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 our customers either directly or indirectly);

• coal quality characteristics (primarily heat, sulfur, ash and moisture content); and

• reliability of supply.

Our competitors may have, among other things, greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures, partnerships with transportation companies or more effective risk management policies and procedures. Our failure to compete successfully could have a material adverse effect on our business, financial condition or results of operations.

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International demand for U.S. coal also affects competition within our industry. The demand for U.S. coal exports depends upon a number of factors outside our control, including the overall demand for electricity in foreign markets, currency exchange rates, ocean freight rates, port and shipping capacity, the demand for foreign-priced steel, both in foreign markets and in the U.S. market, general economic conditions in foreign countries, technological developments and environmental and other governmental regulations in both U.S. and foreign markets. Foreign demand for U.S. coal has increased in recent periods. If foreign demand for U.S. coal were to decline, this decline could cause competition among coal producers for the sale of coal in the United States to intensify, potentially resulting in significant downward pressure on domestic coal prices.

Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect coal prices and materially and adversely affect our results of operations.

Our coal is used primarily as fuel for electricity generation. Overall economic activity and the associated demand for power by industrial users can have significant effects on overall electricity demand. An economic slowdown can significantly slow the growth of electrical demand and could result in contraction of demand for coal. Declines in international prices for coal generally will impact U.S. prices for coal. During the past several years, international demand for coal has been driven, in significant part, by increases in demand due to economic growth in emerging markets, including China and India. Significant declines in the rates of economic growth in these regions could materially affect international demand for U.S. coal, which may have an adverse effect on U.S. coal prices.

Our business is closely linked to domestic demand for electricity and any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. In 2012, we sold a substantial majority of our coal to domestic electric power generators, and we have multi-year coal supply agreements in place with electric power generators for a significant portion of our future production. The amount of coal consumed by electric power generation is affected by, among other things:

• 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 1.8% during 2012 compared with 2011, and U.S. electric generation from coal decreased by 13% in 2012 compared with 2011. 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, and could have a material adverse effect on the demand for coal and on our business over the long term.

Changes in the coal industry that affect our customers, such as those caused by decreased electricity demand and increased competition, could also adversely affect our business. Indirect competition from gas-fired plants that are cheaper to construct and easier to permit has the most potential to displace a significant amount of coal-fired generation in the near term, particularly older, less efficient coal-powered generators. In addition, uncertainty caused by federal and state regulations could cause coal customers to be uncertain of their coal requirements in future years, which could adversely affect our ability to sell coal to our customers under multi-year coal supply agreements.

Weather patterns can also greatly affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on

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the other hand, result in lower electrical demand. Any downward pressure on coal prices, due to decreases in overall demand or otherwise, including changes in weather patterns, would materially and adversely affect our results of operations.

The use of alternative energy sources for power generation could reduce coal consumption by U.S. electric power generators, which could result in lower prices for our coal.

In 2012, a substantial majority of the tons we sold were to domestic electric power generators. The amount of coal consumed for U.S. electric power generation is affected by, among other things:

• 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 consumption in the United States decreased by 1.8% during 2012 compared with 2011, and U.S. electric generation from coal decreased by 13% in 2012 compared with 2011. While the EIA projects that electricity generation will grow at an annual average rate of 0.8% through 2040, it projects that the percentage of electricity generated from coal will decrease to 35% of total generation by 2040, compared with 37% during 2012.

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 we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. The estimates of our reserves are based on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves periodically to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:

• 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 we currently mine;

• the percentage of coal ultimately recoverable;

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• the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

• 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 attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.

Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel, rubber tires and explosives, or the inability to obtain a sufficient quantity of those supplies, may adversely affect our operating costs or disrupt or delay our production.

Our coal mining operations use significant amounts of steel, electricity, diesel fuel, explosives, rubber tires and other mining and industrial supplies. The cost of roof bolts we use in our underground mining operations depends on the price of scrap steel. We also use significant amounts of diesel fuel and tires for the trucks and other heavy machinery we use. If the prices of mining and other industrial supplies, particularly steel-based supplies, diesel fuel and rubber tires, increase, our operating costs may be adversely affected. In addition, if we are unable to procure these supplies, our coal mining operations may be disrupted or we could experience a delay or halt in our production.

A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.

We conduct part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties or to royalties owed to those third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.

We outsource certain aspects of our business to third party contractors, which subjects us to risks, including disruptions in our business.

We contract with third parties to provide blasting services at all of our mines and loading services at our barge loadout facility located on the Green River. In addition, we contract with third parties to provide truck transportation services between our mines and our preparation plants. Accordingly, we are subject to the risks associated with the contractors’ ability to successfully provide the necessary services to meet our needs. If the contractors are unable to adequately provide the contracted services, and we are unable to find alternative service providers in a timely manner, our ability to conduct our coal mining operations and deliver coal to our customers may be disrupted.

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The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.

We depend upon barge, rail and truck transportation systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to supply coal to our customers. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. If transportation of our coal is disrupted or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.

Our profitability depends in part upon the multi-year coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing multi-year coal supply agreements or to enter into new agreements in the future.

We sell a majority of our coal under multi-year coal supply agreements. Under these arrangements, we fix the prices of coal shipped during the initial year and may adjust the prices in later years. As a result, at any given time the market prices for similar-quality coal may exceed the prices for coal shipped under these arrangements. Changes in the coal industry may cause some of our customers not to renew, extend or enter into new multi-year coal supply agreements with us or to enter into agreements to purchase fewer tons of coal than in the past or on different terms or prices. In addition, uncertainty caused by federal and state regulations, including the Clean Air Act, could deter our customers from entering into multi-year coal supply agreements.

Because we sell a majority of our coal production under multi-year coal supply agreements, our ability to capitalize on more favorable market prices may be limited. Conversely, at any given time we are subject to fluctuations in market prices for the quantities of coal that we are planning to produce but which we have not committed to sell. As described above under “Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our profitability and the value of our coal reserves,” the market prices for coal may be volatile and may depend upon factors beyond our control. Our profitability may be adversely affected if we are unable to sell uncommitted production at favorable prices or at all. For more information about our multi-year coal supply agreements, you should see the section entitled “Business—Sales and Marketing—Multi-Year Coal Supply Agreements.”

Our multi-year coal supply agreements subject us to renewal risks.

We sell most of the coal we produce under multi-year coal supply agreements. To the extent we are not successful in renewing, extending or renegotiating our multi-year coal supply agreements on favorable terms, we may have to accept lower prices for the coal we sell or sell reduced quantities of coal in order to secure new sales contracts for our coal.

Prices and quantities under our multi-year coal supply agreements are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or reopened. The expectation of future prices for coal depends upon factors beyond our control, including the following:

• domestic and foreign supply and demand for coal;

• domestic demand for electricity, which tends to follow changes in general economic activity;

• domestic and foreign economic conditions;

• the price, quantity and quality of other coal available to our customers;

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• competition for production of electricity from non-coal sources, including the price and availability of alternative fuels and other sources, such as natural gas, fuel oil, nuclear, hydroelectric, wind biomass and solar power, and the effects of technological developments related to these non-coal energy sources;

• domestic air emission standards for coal-fired power plants, and the ability of coal-fired power plants to meet these standards by installing scrubbers and other pollution control technologies, purchasing emissions allowances or other means; and

• legislative and judicial developments, regulatory changes, or changes in energy policy and energy conservation measures that would adversely affect the coal industry.

For more information regarding our major customers and multi-year coal supply agreements, see “Business—Sales and Marketing.”

The loss of, or significant reduction in purchases by, our largest customers could adversely affect our profitability.

For the year ended December 31, 2012, we derived approximately 63% of our total coal revenues from sales to our two largest customers—Louisville Gas and Electric (“LGE”) and Tennessee Valley Authority (“TVA”). For the year ended December 31, 2012, coal sales to LGE and TVA constituted approximately 36% and 27% of our total coal revenues, respectively. Our multi-year coal supply agreements with LGE expire in 2013, 2015, 2016 and 2017, and our multi-year coal supply agreements with TVA expire in 2013 and 2018; however, several of our multi-year coal supply agreements with LGE and TVA contain reopener provisions pursuant to which either party can request reopening of the agreement to renegotiate price and other terms for the remaining term of such agreement, and, subsequent to any such reopening, the failure to reach an agreement can lead to the termination of such agreement. In addition, one of our multi-year coal supply agreements with TVA provides that TVA has the unilateral right to terminate the agreement upon 60 days’ written notice, in which case TVA is required to pay us a termination fee equal to 10% of the base price multiplied by the remaining number of tons to be delivered under the agreement. If our multi-year coal supply agreements with LGE or TVA are terminated early pursuant to the reopener provisions, or we fail to extend or renew our multi-year coal supply agreements with LGE or TVA, our business and results of operations could be materially and adversely affected. Even if we are able to extend or renew our multi-year coal supply agreements with LGE and TVA, if market prices for such coal agreements are low at the time of such extensions or renewals or increases in costs during the term of such extended or renewed agreements are greater than the offsets from our cost pass-through and inflation adjustment provisions under such extended or renewed agreements, our business and results of operations could be materially and adversely affected.

Our multi-year coal supply agreements typically contain force majeure provisions allowing the parties to temporarily suspend performance during specified events beyond their control. Most of our multi-year coal supply agreements also contain provisions requiring us to deliver coal that satisfies certain quality specifications, such as heat value, sulfur content, ash content, chlorine content, hardness and ash fusion temperature. These provisions in our multi-year coal supply agreements could result in negative economic consequences to us, including price adjustments, purchasing replacement coal in a higher-priced open market, the rejection of deliveries or, in the extreme, contract termination. Our profitability may be negatively affected if we are unable to seek protection during adverse economic conditions or if we incur financial or other economic penalties as a result of the provisions of our multi-year coal supply agreements.

If our multi-year coal supply agreements with LGE or TVA are terminated or if we fail to extend or renew our multi-year coal supply agreements with LGE or TVA, we may be unable to timely replace such agreements. In such a case, our business and results of operations could be materially and adversely affected.

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Our assets and operations are concentrated in Western Kentucky and the Illinois Basin, and a disruption within that geographic region could adversely affect the Company’s performance.

We rely exclusively on sales generated from products distributed from the Illinois Basin and Western Kentucky. Due to our lack of diversification in geographic location, an adverse development in these areas, including adverse developments due to catastrophic events or weather and decreases in demand for coal or electricity, could have a significantly greater adverse impact on our ability to operate our business and our results of operations than if we held more diverse assets and locations.

The general partner of Armstrong Resource Partners, L.P. may be removed or control of Armstrong Resource Partners, L.P. may be otherwise transferred to a third party without our consent.

Armstrong Resource Partners, L.P. is majority-owned by Yorktown. Pursuant to the Amended and Restated Agreement of Limited Partnership of Armstrong Resource Partners, L.P. dated October 1, 2011 (the “ARP LPA”), Yorktown may remove our subsidiary, Elk Creek GP, as general partner of Armstrong Resource Partners, L.P. or otherwise cause a change of control of Armstrong Resource Partners, L.P. without our consent. If such a change in control of Armstrong Resource Partners, L.P. were to occur, our ability to enter into, or obtain renewals of, coal lease or mining license agreements with Armstrong Resource Partners, L.P. could be adversely affected. We may then have to seek alternative agreements or arrangements with unrelated parties and such alternative agreements or arrangements may not be available or may be on less favorable terms.

Some officers of Armstrong Energy may spend a substantial amount of time managing the business and affairs of Armstrong Resource Partners, L.P. and its affiliates other than us.

These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Armstrong Resource Partners, L.P. 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, L.P. These officers may also be conflicted when negotiating the terms of contracts between Armstrong Energy and Armstrong Resource Partners, L.P.

The fiduciary duties of officers and directors of Elk Creek GP, as general partner of Armstrong Resource Partners, L.P., may conflict with those of officers and directors of Armstrong Energy.

As the general partner of Armstrong Resource Partners, L.P., our subsidiary Elk Creek GP has a legal duty to manage Armstrong Resource Partners, L.P. in a manner beneficial to the limited partners of Armstrong Resource Partners, L.P. This legal duty originates in Delaware statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because Elk Creek GP is owned by Armstrong Energy, the officers and directors of Elk Creek GP also have fiduciary duties to manage the business of Elk Creek GP and Armstrong Resource Partners, L.P. in a manner beneficial to Armstrong Energy. The board of directors of Elk Creek GP, which includes some of the directors and executive officers of Armstrong Energy, may resolve any conflict between the interests of Armstrong Energy on the one hand, and Armstrong Resource Partners, L.P., on the other hand, and has broad latitude to consider the interests of all parties to the conflict.

Conflicts of interest may arise between Armstrong Energy 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. In addition, we may determine to permit Armstrong Resource Partners to engage in other activities, including the acquisition of coal reserves that will not be used by Armstrong Energy, and we may decide to fund certain of these activities, subject to the limitations imposed by our debt agreements.

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Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers’ compensation costs, coal leases and other obligations. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third party surety bond issuers of their right to refuse to renew the surety and restrictions on availability on collateral for current and future third party surety bond issuers under the terms of our financing arrangements.

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 will not be required to formally attest to the effectiveness of our internal controls. 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. Following effectiveness of the registration statement of which this prospectus is a part, 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, due to our status as a non-accelerated filer under the SEC rules, our independent registered public accounting firm is not required, and following effectiveness of the registration statement of which this prospectus is a part, will not be required, to formally attest to the effectiveness of our internal control over financial reporting. Further, we may take advantage of other accounting and disclosure related exemptions afforded to “emerging growth companies” from time to time.

Although we are not subject to the requirements of Section 404 of the Sarbanes-Oxley Act with respect to maintenance and assessment of internal control over financial reporting, if we fail to maintain proper and effective internal controls, our ability to produce accurate financial statements could be impaired, which could adversely affect our business, financial condition or results of operations. While management currently believes that its internal controls over financial reporting are adequate, we cannot assure you that an audit of the effectiveness of our internal controls over financing reporting would conclude that such controls are effective.

We will incur increased costs as a result of being subject to the Exchange Act reporting requirements.

As a privately held company, we have not been responsible for the corporate governance and financial reporting practices and policies required of companies that are subject to Exchange Act reporting requirements. Following the effectiveness of the registration statement of which this prospectus is a part, we will be subject to Exchange Act reporting requirements. As such, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act and related regulations of the SEC, with which we are not required to comply as a private company. Under the current rules of the SEC, beginning with fiscal 2014, 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. We will need to:

• institute a more comprehensive compliance function;

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• 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 our board of directors and management 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.

In addition, we also expect that being subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.

Our ability to operate our business and implement our strategies depends on the continued contributions of our executive officers and key employees. In particular, we depend significantly on our senior management’s long-standing relationships within our industry. The loss of any of our senior executives could have a material adverse effect on our business. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled management personnel with coal industry experience and competition for these persons in the coal industry is intense. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

We are subject to various legal proceedings, which may have an adverse effect on our business.

We are involved in a number of threatened and pending legal proceedings incidental to our normal business activities. While we cannot predict the outcome of the proceedings, there is always the potential that the costs of litigation in an individual matter or the aggregation of many matters could have an adverse effect on our cash flows, results of operations or financial position.

A shortage of skilled labor in the mining industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.

Efficient coal mining using modern techniques and equipment requires skilled laborers in multiple disciplines such as equipment operators, mechanics, electricians and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase, or if we experience materially increased health and benefit costs with respect to our employees, our results of operations could be materially and adversely affected.

Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.

All of our mines are operated by non-union employees. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union, subject to certain voting and other procedural

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requirements. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our production through potential strikes, slowdowns, picketing and work stoppages, and materially reduce our profitability.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. The current economic volatility and tightening credit markets increase the risk that we may not be able to collect payments from our customers. A continuation or worsening of current economic conditions or other prolonged global or U.S. recessions could also impact the creditworthiness of our customers. If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for all of the coal we sell to that customer. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If we are able to withhold shipments, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could have a material adverse effect on our financial position. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to Environmental and Other Regulations and Legislation

New regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.

One major by-product of burning coal is carbon dioxide (“CO₂”), which is a greenhouse gas and a source of concern with respect to global warming, also known as Climate Change. 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. New coal-fired power plants could meet the proposed standards 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. If adopted, the proposed standards could negatively impact the price of coal. 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.

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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 business, financial condition or results of operations. See “Business—Regulation and Laws—Climate Change.”

Extensive environmental requirements, including existing and potential future requirements relating to air emissions, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.

The operations of our customers may be subject to extensive environmental requirements concerning air emissions. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide (“SO₂”), particulate matter, nitrogen oxides (“NOx”), and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, SO₂, NOx, toxic gases and other air pollutants have been proposed or could become effective in coming years. In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.

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. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal.

In addition, contamination caused by the disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under federal and state laws. In addition, the EPA has proposed a rule concerning management of coal combustion residuals. New EPA regulation of such management would likely increase the ultimate costs to our customers of coal combustion. Such liabilities and increased costs in turn could have a material adverse effect on the demand for and prices received for our coal.

See “Business—Regulation and Laws” for more information about the various governmental regulations affecting us.

Legal requirements that we expect to significantly expand scrubbed coal-fired electricity generating capacity may be overturned or not enacted at all, which could result in less demand for Illinois Basin coal than we anticipate and materially and adversely affect our coal prices and/or sales.

Although a number of legal requirements have been or are in the process of being implemented that are expected to expand significantly the scrubbed coal-fired electricity generating capacity in the U.S., regulations driving this trend are subject to legal challenge, and could also be the subject of future legislation that withdraws any authorization for such requirements. For example, on August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) vacated the Cross-State Air Pollution Rule (“CSAPR”), which would have required states to reduce power plant emissions that contribute to ozone and/or fine particle pollution in other states, and ordered the EPA to continue administering the Clean Air Interstate Rule (“CAIR”) pending the promulgation of a replacement rate. On October 5, 2012, the EPA filed a petition seeking enhanced rehearing of the August 21, 2012, decision regarding CSAPR. On January 24, 2013, the D.C. Circuit denied the EPA’s petition for rehearing, and on March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit’s decision on the CSAPR. The CAIR remains in place pending such ruling. The outcome of such legal proceedings, 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

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would. This could adversely affect the demand for our coal and the price we will receive, which could materially and adversely affect our coal prices and/or sales.

Our failure to obtain and renew permits and approvals necessary for our mining operations could negatively affect our business.

Coal production is dependent on our ability to obtain and maintain various federal and state permits and approvals to mine our coal reserves within the timeline specified in our mining plans. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, which may increase the costs or possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. The slowing pace at which necessary permits are issued or renewed for new and existing mines has materially impacted coal production, especially in Central Appalachia. Permitting by the Army Corps of Engineers (the “Corps”), the EPA and the Department of the Interior has become subject to “enhanced review” under both the Surface Mining Control and Reclamation Act of 1977 (the “SMCRA”), and the federal Clean Water Act (the “CWA”).

Typically, we submit the necessary permit applications 12 to 30 months before we plan to mine a new area. Some of our required mining permits are becoming increasingly difficult to obtain within the time frames to which we were previously accustomed, and in some instances we have had to delay the mining of coal in certain areas covered by the application in order to obtain required permits and approvals. Permits could be delayed in the future if the EPA continues its enhanced review of CWA applications. If the required permits are not issued or renewed in a timely fashion or at all, or if permits issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production and our operations, and there could be a material adverse effect on our ability to produce coal profitably. See “Business—Regulation and Laws.”

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

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.

Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this were to occur, capital expenditures could be required in order for us to be allowed could be required in order for us to be allowed to reopen the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally allow us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these

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obligations, incur capital expenditures to reopen the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or terminate customers’ contracts. Any of these actions could have a material adverse effect on our business and results of operations.

Extensive environmental laws and regulations impose significant costs on our mining operations, and future laws and regulations could materially increase those costs or limit our ability to produce and sell coal.

The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to environmental matters such as:

• 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 have been or will be at all times in compliance with the applicable laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for sanctions, costs and liabilities in respect of these matters, we could be materially and adversely affected.

New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations. See “Business—Regulation and Laws.”

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If the assumptions underlying our estimates of reclamation and mine closure obligations are inaccurate, our costs could be greater than anticipated.

SMCRA and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements, engineering studies and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from our original assumptions or if governmental regulations change significantly. We are required to record new obligations as liabilities at fair value under generally accepted accounting principles. In estimating fair value, we considered the estimated current costs of reclamation and mine closure and applied inflation rates and a third-party profit, as required. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time, which may affect runoff or drainage water or other aspects of the environment. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and cleanup of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.

We maintain extensive coal refuse areas and slurry impoundments at a number of our mines. Such areas and impoundments are subject to extensive regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which could pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for civil or criminal fines and penalties.

Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.

Changes in the legal and regulatory environment could complicate or limit our business activities, increase our operating costs or result in litigation.

The conduct of our businesses is subject to various laws and regulations administered by federal, state and local governmental agencies in the United States. These laws and regulations may change, sometimes dramatically, as a result of political, economic or social events or in response to significant events. Certain recent developments particularly may cause changes in the legal and regulatory environment in which we operate and

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may impact our results or increase our costs or liabilities. 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 and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities.

Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration (“MSHA”), issued new or more stringent rules and policies on a variety of topics, including:

• 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. Future workplace accidents are likely to 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 we operate and could increase our operating costs or otherwise may prevent, delay or reduce our planned production, any of which could adversely affect our financial condition, results of operations and cash flows.

Although we are unable to quantify the full impact, implementing and complying with new laws and regulations could have an adverse impact on our business and results of operations and could result in harsher sanctions in the event of any violations. See “Business—Regulation and Laws.”

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Certain United States federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2013 budget recommends elimination of certain key United States federal income tax preferences relating to coal exploration and development (the “Budget Proposal”). The Budget Proposal would (1) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal and lignite royalties, and (4) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in United States federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in our common stock.

The current challenging economic environment, along with difficult and volatile conditions in the capital and credit markets, could materially adversely affect our financial position, results of operations or cash flows, and we are unsure whether these conditions will improve in the near future.

The United States economy and global credit markets remain volatile. Worsening economic conditions or factors that negatively affect the economic health of the United States and Europe could reduce our revenues and thus adversely affect our results of operations. The recent financial and sovereign debt crises in North America and Europe have led to a global economic slowdown, with the economics of those regions showing significant signs of weakness resulting in greater volatility in the United States economy and in the global capital and credit markets. These markets have been experiencing disruption, including, among other things, volatility in security prices, diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, failure and potential failures of major financial institutions, unprecedented government support of financial institutions and high unemployment rates. Instability in consumer confidence and increased unemployment have increased concerns of prolonged economic weakness, Furthermore, these developments may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. We are unable to predict the duration and severity of the current crisis or determine the specific impact of the current economic conditions on our business at this time, but we believe that further deterioration or a prolonged period of economic weakness will have an adverse impact on our results of operations, business and financial condition, as well as our ability to satisfy our obligations under the Notes.

Risks Related to the Exchange Offer

We cannot assure you that an active trading market for the Exchange Notes will exist if you desire to sell the Exchange Notes.

The Exchange Notes will be a new issue of debt securities of the same class as the Outstanding Notes and will generally be freely transferrable. Notwithstanding the foregoing, a liquid market may not develop for the Exchange Notes, and you may be unable to sell your Exchange Notes at a particular time, as we do not intend to apply for the Exchange Notes to be listed on any securities exchange or to arrange for quotation on any automated dealer quotation system. In addition, the trading prices of the Exchange Notes could be subject to significant fluctuations in response to government regulations, variations in quarterly operating results, general economic conditions and various other factors. The liquidity of the trading market in the Exchange Notes and the market price quoted for the Exchange Notes may also be adversely affected by changes in the overall market for high-yield securities and by changes in our financial performance or prospects or in the prospects for companies in our industry generally. The liquidity of any market for Exchange Notes will depend upon various factors, including:

• the number of holders of the Exchange Notes;

• the interest of securities dealers in making a market for the Exchange Notes;

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• the overall market for similar classes of securities;

• our financial performance or prospects; and

• the performance and prospects for companies in our industry generally.

Accordingly, we cannot assure you that a market or liquidity will develop for the Exchange Notes. Historically, the markets for non-investment grade indebtedness have been subject to disruptions that have caused substantial volatility in the prices of securities similar to the Exchange Notes. We cannot assure you that the market for the Exchange Notes, if any, will not be subject to similar disruptions. Any such disruptions may adversely affect you as a holder of the Exchange Notes. If no active trading market develops, you may be unable to resell your Exchange Notes at their fair market value or at all.

If you do not exchange your Outstanding Notes in the exchange offer, the transfer restrictions currently applicable to your Outstanding Notes will remain in force, and the market price of your Outstanding Notes could decline.

If you do not exchange your Outstanding Notes for Exchange Notes in the exchange offer, you will continue to be subject to restrictions on transfer of your Outstanding Notes as set forth in the offering memorandum distributed in connection with the private offering of the Outstanding Notes. In general, the Outstanding Notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the Outstanding Notes under the Securities Act.

The tender of Outstanding Notes under the exchange offer will reduce the aggregate principal amount of the Outstanding Notes, which may have an adverse effect upon, and increase the volatility of, the market prices of the Outstanding Notes due to a reduction in liquidity. In addition, if you do not exchange your Outstanding Notes in the exchange offer, you will no longer be entitled to exchange your Outstanding Notes for Exchange Notes registered under the Securities Act, and you will no longer be entitled to have your Outstanding Notes registered for resale under the Securities Act.

Risks Related to the Exchange Notes

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.

At June 30, 2013, our total long-term debt was approximately $203.4 million, which is comprised of the following: $193.5 million in borrowings under the Notes and $9.9 million in other long-term debt. As of June 30, 2013, we had a long-term obligation owed to our affiliate, Armstrong Resource Partners, associated with the financing transactions in connection with the transfers of undivided interests in certain land and mineral reserves to Armstrong Resource Partners totaling $104.9 million. We also have significant lease and royalty obligations, including, but not limited to, our capital lease obligations that totaled approximately $7.7 million as of June 30, 2013 and our obligations under non-cancelable operating leases that totaled approximately $48.9 million. Future minimum advance royalties totaled approximately $2.3 million as of June 30, 2013. In addition to advance royalties, production royalties are payable based on the quantity of coal mined in future years and prospective changes to mine plans. Our ability to satisfy our debt, lease and royalty obligations, and our ability to refinance our indebtedness, will depend upon our future operating performance. The amount of indebtedness we have incurred could have significant consequences to us, such as:

• increasing our vulnerability to adverse economic, industry or competitive developments;

• requiring a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;

• making it more difficult for us to satisfy our obligations with respect to the Notes;

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• limiting our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and

• limiting our flexibility in planning for, or reacting to, changes in our business or the industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploiting.

Despite our substantial indebtedness level, we and our subsidiaries will still be able to incur significant additional amounts of debt, which could further exacerbate the risks associated with our substantial indebtedness.

We may be able to incur substantial additional indebtedness in the future. Although the indenture governing the Exchange Notes and our Revolving Credit Facility each contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions and, under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we now face would increase. In addition, the indenture governing the Exchange Notes will not prevent us from incurring obligations that do not constitute indebtedness under the indenture.

The indenture governing the Exchange Notes contains restrictions that limit our flexibility in operating our business, and breach of those covenants may cause us to be in default under the indenture or the Revolving Credit Facility. Such a default, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations, and our ability to make payments on the Exchange Notes.

The the indenture governing the Exchange Notes contains various covenants that limit our ability to engage in specified types of transactions. These covenants limit our ability to, among other things:

• incur or assume liens or additional debt or provide guarantees in respect of obligations of other persons;

• pay dividends or distributions or redeem or repurchase capital stock;

• prepay, redeem or repurchase certain debt;

• make loans and investments;

• enter into agreements that restrict distributions from our subsidiaries;

• sell or transfer assets;

• enter into certain transactions with affiliates; and

• consolidate or merge with or into, or sell substantially all of our assets to, another person.

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities to finance future capital needs. A breach of any of these covenants could result in a default under the Revolving Credit Facility or the indenture. In addition, any debt agreements we enter into in the future may further limit our ability to enter into certain types of transactions. If we do not achieve the operating results required by the Revolving Credit Facility or future agreements, we would default under these covenants. If that occurs, our lenders, including holders of Exchange Notes, could accelerate their debt. If their debt is accelerated, we may not be able to repay all of their debt, in which case your Exchange Notes may not be fully repaid, if they are repaid at all.

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Our Revolving Credit Facility contains restrictions that limit our flexibility in operating our business, and breach of those covenants may cause us to be in default under the Revolving Credit Facility. Such a default, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations, and our ability to make payments on the Exchange Notes.

The Revolving Credit Facility includes customary covenants that, if there are borrowings under the Revolving Credit Facility and also subject to certain exceptions, restrict our ability and the ability of our subsidiaries to, among other things:

• incur or assume liens or additional debt (including capital leases) or provide guarantees in respect of obligations of other persons;

• pay dividends or distributions or redeem or repurchase capital stock;

• make loans, capital expenditures and investments;

• enter into agreements that restrict distributions from our subsidiaries;

• sell, divest or transfer assets;

• enter into certain transactions with affiliates; and

• consolidate or merge with or into, or sell substantially all of our assets to, another person.

In addition, at any time when (i) undrawn availability is less than the greater of (a) $10.0 million or (b) an amount equal to 20% of the borrowing base or (ii) an event of default (as such term is defined in the Revolving Credit Facility) has occurred and is continuing, we will be required to maintain a fixed charge coverage ratio, calculated as of the end of each calendar month for the 12 months then ended, greater than 1.0-to-1.0. The Revolving Credit Facility also contains customary affirmative covenants and events of default. If an event of default occurs, the lenders under the Revolving Credit Facility will be entitled to take various actions, including the acceleration of amounts due under the Revolving Credit Facility and all actions permitted to be taken by a secured creditor. If our debt is accelerated, we may not be able to borrow sufficient funds to refinance our debt or be able to repay all of it, in which case your Exchange Notes may not be fully repaid, if they are repaid at all. In addition, we may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our Revolving Credit Facility.

Our ability to generate the significant amount of cash needed to pay interest and principal on the Exchange Notes and service our other debt and financial obligations and our ability to refinance all or a portion of our indebtedness or obtain additional financing depends on many factors beyond our control.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on the Exchange Notes or our other indebtedness.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance the Exchange Notes or our other indebtedness. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of the indenture governing the Exchange Notes and existing or future debt instruments may restrict us from adopting some of these alternatives. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

Our consolidated balance sheets include interests in coal reserves for which legal title has been transferred to Armstrong Resource Partners.

As described in Note 13, “Related-Party Transactions,” to our audited financial statements included elsewhere in this prospectus, we have sold certain of our coal reserves to Armstrong Resource Partners. Under GAAP, these transfers are treated as financing transactions, with one consequence thereof being that the entire

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book value of these reserves is carried on our consolidated balance sheets, notwithstanding the fact that legal title to the reserves has been transferred to Armstrong Resource Partners. As a result, the collateral agent’s ability to foreclose on and liquidate our assets comprising coal reserves that are the subject of these lease transactions will be limited to the portion of the reserves owned by us. As of June 30, 2013, approximately 17% of the net book value of our “property, plant, equipment, and mine development, net” reflected assets for which legal title has been transferred to Armstrong Resource Partners.

Our subsidiaries hold most of our assets and conduct most of our operations and, unless they are subsidiaries that guarantee the Exchange Notes, they are not obligated to make payments on the Exchange Notes. The Exchange Notes will be structurally junior to indebtedness of our non-guarantor subsidiaries, if any.

Most of our operations are conducted through our subsidiaries. Therefore, we depend on the cash flow of our subsidiaries to meet our obligations. Our subsidiaries are separate and distinct legal entities and, except for our subsidiaries that will be guarantors of the Exchange Notes, they will have no obligation, contingent or otherwise, to pay amounts due under the Exchange Notes or to make any funds available to pay those amounts, whether by dividend, distribution, loan or other payments. Because the creditors of non-guarantor subsidiaries, if any, have direct claims on the subsidiaries and their assets, the claims of holders of the Exchange Notes are “structurally subordinated” to any liabilities of any non-guarantor subsidiaries. This means that the creditors of any non-guarantor subsidiaries have priority in their claims on the assets of any non-guarantor subsidiaries over the creditors of the issuer. Accordingly, if a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary occurs, holders of its indebtedness and its trade creditors will generally be entitled to payment of their claims from the assets of that subsidiary before any assets are made available for distribution to the issuer. The indenture requires that any of our future restricted subsidiaries (other than certain immaterial subsidiaries) will become guarantors of the Exchange Notes. See “Description of Exchange Notes.”

Certain of our subsidiaries are not subject to the restrictive covenants in the indenture governing the Exchange Notes.

Certain of our immaterial subsidiaries are not subject to the restrictive covenants in the indenture governing the Exchange Notes. This means that these entities will be able to engage in many of the activities that we and our restricted subsidiaries are prohibited or limited from doing under the terms of the indenture governing the Exchange Notes, such as incurring additional debt, securing assets in priority to the claims of the holders of the Exchange Notes, paying dividends, making investments, selling assets and entering into mergers or other business combinations. These actions could be detrimental to our ability to make payments of principal and interest when due and to comply with our other obligations under the Exchange Notes, and could reduce the amount of our assets that would be available to satisfy your claims should we default on the Exchange Notes.

A court could void our subsidiaries’ guarantees of the Exchange Notes under fraudulent transfer laws.

Although the guarantees provide you with a direct claim against the assets of the subsidiary guarantors, under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a guarantee could be voided, or claims with respect to a guarantee could be subordinated to all other debts of that guarantor. In addition, a bankruptcy court could void (i.e., cancel) any payments by that guarantor pursuant to its guarantee and require those payments to be returned to the guarantor or to a fund for the benefit of the other creditors of the guarantor.

The bankruptcy court might take these actions if it found, among other things, that when a subsidiary guarantor executed its guarantee (or, in some jurisdictions, when it became obligated to make payments under its guarantee):

• such subsidiary guarantor received less than reasonably equivalent value or fair consideration for the incurrence of its guarantee; and

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• such subsidiary guarantor:

• was (or was rendered) insolvent by the incurrence of the guarantee;

• was engaged or about to engage in a business or transaction for which its assets constituted unreasonably small capital to carry on its business; or

• intended to incur, or believed that it would incur, obligations beyond its ability to pay as those obligations matured.

A bankruptcy court would likely find that a subsidiary guarantor received less than fair consideration or reasonably equivalent value for its guarantee to the extent that it did not receive direct or indirect benefit from the issuance of the Exchange Notes. A bankruptcy court could also void a guarantee if it found that the subsidiary issued its guarantee with actual intent to hinder, delay or defraud creditors. Although courts in different jurisdictions measure solvency differently, in general, an entity would be deemed insolvent if the sum of its debts, including contingent and unliquidated debts, exceeds the fair value of its assets, or if the present fair saleable value of its assets is less than the amount that would be required to pay the expected liability on its debts, including contingent and unliquidated debts, as they become due.

We cannot predict what standard a court would apply in order to determine whether a subsidiary guarantor was insolvent as of the date it issued the guarantee or whether, regardless of the method of valuation, a court would determine that the subsidiary guarantor was insolvent on that date, or whether a court would determine that the payments under the guarantee constituted fraudulent transfers or conveyances on other grounds.

The indenture governing the Exchange Notes contains a “savings clause” intended to limit each subsidiary guarantor’s liability under its guarantee to the maximum amount that it could incur without causing the guarantee to be a fraudulent transfer under applicable law. There can be no assurance that this provision will be upheld as intended. In a recent case, the U.S. Bankruptcy Court in the Southern District of Florida found this kind of provision in that case to be ineffective, and held the subsidiary guarantees to be fraudulent transfers and voided them in their entirety.

If a guarantee is deemed to be a fraudulent transfer, it could be voided altogether, or it could be subordinated to all other debts of the subsidiary guarantor. In such case, any payment by the subsidiary guarantor pursuant to its guarantee could be required to be returned to the subsidiary guarantor or to a fund for the benefit of the creditors of the subsidiary guarantor. If a guarantee is voided or held unenforceable for any other reason, holders of the Notes would cease to have a claim against the subsidiary guarantor based on the guarantee and would be creditors only of the issuer and any subsidiary guarantor whose guarantee was not similarly voided or otherwise held unenforceable.

The indenture permits us to transfer coal reserves to Armstrong Resource Partners in lieu of cash payments in order to satisfy royalty obligations.

Pursuant to the Royalty Deferment and Option Agreement described under “Certain Relationships and Related Party Transactions,” our subsidiaries, Armstrong Coal Company, Inc. (“Armstrong Coal”), Western Diamond, LLC (“Western Diamond”) and Western Land Company, LLC (“Western Land”) have the option to defer cash royalty payments owed to subsidiaries of Armstrong Resource Partners relating to the 7% production royalty described under “Business—Our Mining Operations.” In lieu of cash payments, Armstrong Coal and its affiliates have the option to transfer to Armstrong Resource Partners an interest in the above-described coal reserves at fair market value, and in connection therewith, Armstrong Resource Partners grants to Armstrong Energy a leasehold interest in the applicable reserves. Since this agreement was executed in February 2011, Armstrong Energy and its subsidiaries have not paid any cash royalties to Armstrong Resource Partners but have transferred reserves with a total fair market value, at the time of transfer, of $10.6 million. If the Company continues to satisfy its royalty obligations to Armstrong Resource Partners by additional transfers of coal

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reserves, the Company expects that it will transfer all of its fee-owned reserves that are subject to the Royalty Deferment and Option Agreement to Armstrong Resource Partners by 2018. As of June 30, 2013, Armstrong Resource Partners has a 53.4% undivided interest in the reserves that have been subject to transfer to Armstrong Resource Partners pursuant to the Royalty Deferment and Option Agreement. Armstrong Energy leases such reserves from Armstrong Resource Partners. See “Business—Our Operational History” and “Certain Relationships and Related Party Transactions—Royalty Deferment and Option Agreement.”

While the indenture obligates the Company to grant a leasehold mortgage in any reserves transferred to Armstrong Resource Partners, the indenture also permits the Company to release the fee mortgage in the reserves at the time of transfer. As a result, the ability of the collateral agent to exercise remedies against, and receive value from, such reserves transferred to Armstrong Resource Partners in satisfaction of its royalty obligations may be limited.

There may not be sufficient collateral to repay all or any of the Exchange Notes, especially if we incur additional senior secured indebtedness, which will dilute the value of the collateral securing the Exchange Notes.

No appraisal of the value of the collateral has been made in connection with this exchange offer, and the fair market value is subject to fluctuations based on factors that include, among others, changing economic conditions, competition and other future trends. In the event of foreclosure on the collateral, the proceeds from the sale of the collateral may not be sufficient to satisfy in full our obligations under the Exchange Notes and our Revolving Credit Facility. The amount to be received upon such a sale would be dependent on numerous factors. The fair market value of the collateral is subject to fluctuations based on factors that include, among others, the condition of our industry, the ability to sell the collateral in an orderly sale, general economic conditions, the availability of buyers, our failure to implement our business strategy and similar factors. The amount received upon a sale of the collateral would be dependent on numerous factors, including but not limited to the actual fair market value of the collateral at such time and the timing and the manner of the sale. By its nature, portions of the collateral may be illiquid and may have no readily ascertainable market value.

To the extent that pre-existing liens, liens relating to the Revolving Credit Facility, liens permitted under the indenture and other rights, encumber any of the collateral securing the Exchange Notes and the guarantees, holders of such liens may exercise rights and remedies with respect to the collateral that could adversely affect the value of the collateral and the ability of the collateral agent, the trustee under the indenture or the holders of the Exchange Notes to realize or foreclose on the collateral. Consequently, liquidating the collateral securing the Exchange Notes may not result in proceeds in an amount sufficient to pay any amounts due under the Exchange Notes after satisfying the obligations to pay any creditors with equal or prior liens. If the proceeds of any sale of collateral are not sufficient to repay all amounts due on the Exchange Notes, the holders of the Exchange Notes (to the extent not repaid from the proceeds of the sale of the collateral) would have only an unsecured, unsubordinated claim against our and the subsidiary guarantors’ remaining assets.

In the event of a foreclosure on the Revolver Collateral (or a distribution in respect thereof in a bankruptcy or insolvency proceeding), the proceeds from such Revolver Collateral may not be sufficient to satisfy the Exchange Notes because such proceeds would, under the intercreditor agreement, first be applied to satisfy our obligations under our Revolving Credit Facility and certain hedging and cash management obligations. Only after all of our obligations under our Revolving Credit Facility and such other obligations have been satisfied will proceeds from such Revolver Collateral be applied to satisfy our obligations under the Exchange Notes. In addition, in the event of a foreclosure on the Exchange Notes Collateral, the proceeds from such foreclosure may not be sufficient to satisfy our obligations under the Exchange Notes. In particular, we have not obtained any valuation for the Exchange Notes Collateral.

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In the event of our bankruptcy, the ability of the holders of the Exchange Notes to realize upon the collateral will be subject to certain bankruptcy law limitations.

The ability of holders of the Exchange Notes to realize upon the collateral will be subject to certain bankruptcy law limitations in the event of our bankruptcy. Under federal bankruptcy law, secured creditors are prohibited from repossessing their security from a debtor in a bankruptcy case, or from disposing of security repossessed from such a debtor, without bankruptcy court approval, which may not be given. Moreover, applicable federal bankruptcy laws generally permit the debtor to continue to use and expend collateral, including cash collateral, and to provide liens senior to liens securing the Exchange Notes to secure indebtedness incurred after the commencement of a bankruptcy case, provided that the secured creditor either consents or is given “adequate protection.” “Adequate protection” could include cash payments or the granting of additional security, if and at such times as the presiding court in its discretion determines, for any diminution in the value of the collateral as a result of the stay of repossession or disposition of the collateral during the pendency of the bankruptcy case, the use of collateral (including cash collateral) and the incurrence of such senior indebtedness. In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the collateral agent would repossess or dispose of the collateral, or whether or to what extent holders of the Exchange Notes would be compensated for any delay in payment of loss of value of the collateral through the requirements of “adequate protection.”

Other secured indebtedness, including indebtedness under our Revolving Credit Facility, which is secured by a first-priority interest in receivables, inventory, deposit and securities accounts and certain other assets and proceeds thereof, will be senior to the Exchange Notes to the extent of the value of the Collateral securing such indebtedness on a first-priority basis.

Obligations under our Revolving Credit Facility are secured by a first-priority lien on the Revolver Collateral. The Exchange Notes and the guarantees are secured by a second-priority lien on the Revolver Collateral. Any rights to payment and claims by the holders of the Exchange Notes are, therefore, fully subordinated to any rights to payment and claims by our creditors under our Revolving Credit Facility with respect to distributions of such Revolver Collateral. Only when our obligations under our Revolving Credit Facility are satisfied in full will the proceeds of the Revolver Collateral be available, subject to other permitted liens, to satisfy obligations under the Exchange Notes and the guarantees. Consequently, the Exchange Notes and the guarantees are effectively subordinated to our Revolving Credit Facility to the extent of the value of the Revolver Collateral. In addition, the indenture governing the Exchange Notes allows us to incur other permitted liens on our assets, as well as additional indebtedness that may be secured by liens on the Collateral, which liens may be prior to the liens securing the Exchange Notes. Any such indebtedness or other obligations secured by such permitted liens may further limit the recovery from the realization of the value of such Collateral available to satisfy holders of the Exchange Notes.

The intercreditor agreement in connection with the indenture governing the Exchange Notes may limit the rights of the holders of the Exchange Notes and their control with respect to the Exchange Notes Collateral.

The rights of the holders of the Exchange Notes with respect to the Revolver Collateral may be substantially limited pursuant to the terms of the intercreditor agreement even during an event of default. Under the intercreditor agreement, if amounts or commitments remain outstanding under our Revolving Credit Facility and certain hedging and cash management obligations, actions taken in respect of the Revolver Collateral, including the ability to cause the commencement of enforcement proceedings against such Revolver Collateral and to control the conduct of these proceedings, will be at the sole direction of the holders of the obligations secured by the first-priority liens, subject to certain limitations. As a result, the collateral agent, on behalf of the holders of the Exchange Notes, may not have the ability to control or direct these actions, even if the rights of the holders of the Exchange Notes are adversely affected. See “Description of Exchange Notes—Intercreditor Agreement.”

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Under the terms of the intercreditor agreement, at any time that obligations that have the benefit of the first-priority liens on the Collateral are outstanding, if the holders of such indebtedness release the Revolver Collateral for any reason whatsoever (other than any such release granted following the discharge of obligations with respect to our Revolving Credit Facility), including, without limitation, in connection with any sale of assets, the second-priority security interest in such Revolver Collateral securing the Exchange Notes will be automatically and simultaneously released without any consent or action by the holders of the Exchange Notes, subject to certain exceptions. The Revolver Collateral so released will no longer secure our and the guarantors’ obligations under the Exchange Notes and the guarantees. In addition, because the holders of indebtedness secured by first-priority liens on the Revolver Collateral control the disposition of the Revolver Collateral, such holders could decide not to proceed against the Revolver Collateral, regardless of whether there is a default under the documents governing such indebtedness or under the indenture governing the Exchange Notes. The intercreditor agreement contains certain provisions benefiting holders of indebtedness under our Revolving Credit Facility, including provisions prohibiting the trustee and the collateral agent from objecting following the filing of a bankruptcy petition to a number of important matters regarding the Collateral and the financing provided to us. After such filing, the value of this Collateral could materially deteriorate and holders of the Exchange Notes would be unable to raise an objection. In addition, the right of holders of obligations secured by first-priority liens to foreclose upon and sell such Collateral upon the occurrence of an event of default also would be subject to limitations under applicable bankruptcy laws if we or any of our subsidiaries become subject to a bankruptcy proceeding. The intercreditor agreement also gives the holders of first-priority liens on the Revolver Collateral the right to access and use the Collateral that secures the Exchange Notes to allow those holders to protect the Revolving Collateral and to process, store and dispose of the Revolver Collateral.

The capital stock of each of our subsidiaries that has been pledged to secure the Exchange Notes will be automatically released from the collateral for the Exchange Notes to the extent that the pledge would require the preparation and filing of separate audited financial statements of such subsidiary under Rule 3-16 of Regulation S-X under the Securities Act.

Pursuant to the terms of the indenture governing the Notes, a portion (or, if necessary, all) of the capital stock of each of our subsidiaries that has been pledged to secure the Exchange Notes will be automatically released from the collateral for the Exchange Notes to the extent that the pledge would require the preparation and filing of separate audited financial statements of such subsidiary under Rule 3-16 of Regulation S-X under the Securities Act. As a result, the collateral securing the Exchange Notes will include the capital stock of each such subsidiary only to the extent that the applicable value of such capital stock (on a subsidiary-by-subsidiary basis) is less than 20% of the aggregate principal amount of the Outstanding Notes.

With respect to the real properties to be mortgaged as security for the Exchange Notes, title insurance is not required to be delivered. Therefore, there will be no independent assurance that the mortgages with respect to such real properties securing the Exchange Notes are encumbering the correct real properties or that there are no liens other than those permitted by the indentures encumbering such real properties.

In connection with this exchange offer, we are not required to obtain title insurance with respect to the real properties intended to constitute collateral. As a result, there is no independent assurance that, among other things, (i) we have the rights to such real properties that we purport to have in the mortgages encumbering such real properties and that our title to such real properties is not encumbered by liens not permitted by the indenture, and (ii) such mortgages have the priority intended and described in this prospectus. We will, however, represent that (i) we have the rights to such real properties that we purport to have in the mortgage and that our title to such real property is not encumbered by liens not permitted by the indentures, and (ii) the mortgages have the priority intended and described in the prospectus.

Surveys will not be provided with respect to the real properties to be mortgaged as security for the Exchange Notes. As a result, there will be no independent assurance that there will be no liens encumbering such real property interests other than those permitted by the indentures.

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In connection with this exchange offer, we are not required to provide surveys with respect to the real properties intended to constitute collateral for the Exchange Notes. As a result, there is no independent assurance that, among other things, (i) such real properties encumbered by each mortgage encumbering such properties includes the property owned by us or the subsidiary guarantors that was intended to be mortgaged, and (ii) no encroachments, adverse possession claims, zoning or other restrictions exist with respect to such real properties which could result in a material adverse effect on the value or utility of such real properties. See “Description of Exchange Notes—Security.”

The rights of holders of Exchange Notes to the collateral securing the Exchange Notes may be adversely affected by the failure to perfect security interests in the collateral and other issues generally associated with the realization of security interests in collateral.

Applicable law requires that a security interest in certain tangible and intangible assets can only be properly perfected and its priority retained through certain actions undertaken by the secured party. The liens in the collateral securing the Exchange Notes may not be perfected with respect to the claims of the Exchange Notes if the collateral agent is not able to take the actions necessary to perfect any of these liens on the date of the issuance of the Exchange Notes or thereafter. In addition, applicable law requires that certain property and rights acquired after the grant of a general security interest, such as real property, can only be perfected at the time such property and rights are acquired and identified and additional steps to perfect in such property and rights are taken. The trustee and collateral agent have no obligation to monitor the acquisition of additional property or rights that constitute collateral or the perfection of any security interest.

In addition, the security interest of the collateral agent will be subject to practical challenges generally associated with the realization of security interests in collateral. For example, the collateral agent may need to obtain the consent of third parties and make additional filings. If we are unable to obtain these consents or make these filings, the security interests may be invalid and the holders of the Exchange Notes will not be entitled to the collateral or any recovery with respect thereto. We cannot assure you that we or the collateral agent will be able to obtain any such consent. We also cannot assure you that the consents of any third parties will be given when required to facilitate a foreclosure on such assets. Accordingly, the collateral agent may not have the ability to foreclose upon those assets and the value of the collateral may significantly decrease.

The value of the collateral securing the Exchange Notes may not be sufficient to secure post-petition interest. Should our obligations under the Exchange Notes equal or exceed the fair market value of the collateral securing the Exchange Notes, the holders of the Exchange Notes may be deemed to have an unsecured claim.

In the event of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding against the issuer or the subsidiary guarantors, holders of the Exchange Notes will be entitled to post-petition interest under the U.S. Bankruptcy Code only if the value of their security interest in the collateral is greater than their pre-bankruptcy claim. Holders of the Exchange Notes may be deemed to have an unsecured claim if the issuer’s obligation under the Exchange Notes equals or exceeds the fair market value of the collateral securing the Exchange Notes. Holders of the Exchange Notes that have a security interest in the collateral with a value equal to or less than their pre-bankruptcy claim will not be entitled to post-petition interest under the U.S. Bankruptcy Code. The bankruptcy trustee, the debtor-in-possession or competing creditors could possibly assert that the fair market value of the collateral with respect to the Exchange Notes on the date of the bankruptcy filing was less than the then-current principal amount of the Exchange Notes. Upon a finding by a bankruptcy court that the Exchange Notes are under-collateralized, the claims in the bankruptcy proceeding with respect to the Exchange Notes would be bifurcated between a secured claim and an unsecured claim, and the unsecured claim would not be entitled to the benefits of security in the collateral. Other consequences of a finding of under-collateralization would be, among other things, a lack of entitlement on the part of holders of the Exchange Notes to receive post-petition interest and a lack of entitlement on the part of the unsecured portion of the Exchange Notes to receive other “adequate protection” under U.S. federal bankruptcy laws. In addition, if any payments of post-petition

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interest were made at the time of such a finding of under-collateralization, such payments could be re-characterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to Exchange Notes. No appraisal of the fair market value of the collateral securing the Exchange Notes has been prepared in connection with this offering of the Exchange Notes and, therefore, the value of the collateral agent’s interests in the collateral may not equal or exceed the principal amount of the Exchange Notes. We cannot assure you that there will be sufficient collateral to satisfy our and the subsidiary guarantors’ obligations under the Exchange Notes.

The collateral securing the Exchange Notes is subject to casualty risks.

We intend to maintain insurance or otherwise insure against hazards in a manner appropriate and customary for our business. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. Insurance proceeds may not compensate us fully for our losses. If there is a complete or partial loss of any of the collateral, the insurance proceeds may not be sufficient to satisfy payment of the Exchange Notes.

There are circumstances other than repayment or discharge of the Exchange Notes under which the collateral securing the Exchange Notes and the Note Guarantees will be released automatically, without your consent or the consent of the Trustee.

Under various circumstances, collateral securing the Exchange Notes will be released automatically, including:

• a sale, transfer or other disposal or liquidation of such collateral in a transaction not prohibited under the indenture governing the Exchange Notes;

• with respect to collateral held by a Guarantor, upon the release of such Guarantor from its Note Guarantee in accordance with the indenture governing the Exchange Notes; and

• with respect to collateral that will secure the Revolving Credit Facility on a first-priority basis, upon any release, sale or disposition (other than in connection with a cancellation or termination of the Revolving Credit Facility) of such collateral pursuant to the terms of the Revolving Credit Facility resulting in the release of the lien on such collateral securing the Revolving Credit Facility.

In addition, the Note Guarantee of a Guarantor will be automatically released in connection with a sale of such Guarantor in a transaction permitted under the indenture governing the Exchange Notes. The indenture also permits us to designate one or more of our restricted subsidiaries that is a Guarantor as an unrestricted subsidiary. If we designate a Guarantor as an unrestricted subsidiary for purposes of the indenture, all of the liens on any collateral owned by such subsidiary and any Note Guarantees by such subsidiary will be automatically released under the indenture governing the Exchange Notes. Designation of an unrestricted subsidiary will reduce the aggregate value of the collateral securing the Exchange Notes to the extent that liens on the assets of the unrestricted subsidiary and its subsidiaries are released. In addition, the creditors of the unrestricted subsidiary will have a senior claim on the assets of such unrestricted subsidiary. See “Description of Exchange Notes.”

The Exchange Notes will be issued with original issue discount for U.S. federal income tax purposes.

Because the principal amount of the Exchange Notes exceeds their issue price by an amount that is equal to or greater than 0.25% of the stated principal amount of the Exchange Notes multiplied by the number of complete years to maturity, such Exchange Notes will be treated as issued with OID for U.S. federal income tax purposes in an amount equal to such difference. U.S. holders of such Exchange Notes generally must include the OID in gross income over the term of the Exchange Notes on a constant yield basis, regardless of their method of accounting for tax purposes. As a result, in addition to including stated interest income, U.S. holders generally would recognize taxable income in respect of an Exchange Note in advance of the receipt of cash attributable to such income.

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Any future Note guarantees or additional liens on collateral provided after the Exchange Notes are issued could also be avoided by a trustee in bankruptcy.

The indenture governing the Exchange Notes provides that certain of our future subsidiaries will guarantee the Exchange Notes and secure their Note guarantees with liens on their assets. The indenture governing the Exchange Notes also requires the issuer and the subsidiary guarantors to grant liens on certain assets that they acquire after the Exchange Notes are issued. Any future Note guarantee or additional lien in favor of the collateral agent for the benefit of the holders of the Exchange Notes might be avoidable by the grantor (as debtor-in-possession) or by its trustee in bankruptcy or other third parties if certain events or circumstances exist or occur. For instance, if the entity granting the future Note guarantee or additional lien were insolvent at the time of the grant and if such grant was made within 90 days before that entity commenced a bankruptcy proceeding, and the granting of the future Note guarantee or additional lien enabled the holders of the Exchange Notes to receive more than they would if the grantor were liquidated under chapter 7 of the U.S. Bankruptcy Code, then such Note guarantee or lien could be avoided as a preferential transfer.

We may not be able to repurchase the Exchange Notes upon a change of control.

Upon the occurrence of a “change of control” as defined in the indenture, we will be required to offer to repurchase all outstanding Exchange Notes at 101% of the principal amount thereof plus, without duplication, accrued and unpaid interest and additional interest, if any, to the date of repurchase. However, it is possible that we will not have sufficient funds at the time of the change of control to make the required repurchase of or that restrictions in our Revolving Credit Facility or other indebtedness will not allow such repurchases. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a “Change of Control” under the indenture. See “Description of Exchange Notes—Repurchase of Exchange Notes upon a Change of Control.”

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RATIO OF EARNINGS TO FIXED CHARGES

The table below sets forth our ratio of earnings to fixed charges on a consolidated basis for each of the time periods indicated.

	Year Ended December 31,													Six Months Ended June 30,
	2008			2009			2010		2011		2012			2012		2013
Ratio of earnings to fixed charges(1)		N/A	(2)		N/A	(2)		1.34x		1.26x		N/A	(2)		1.04x		N/A	(2)

(1) Earnings consist of income from operations before income taxes and minority interests and are adjusted to include only fixed charges, excluding capitalized interest, and amortization of capitalized interest. Fixed charges consist of interest incurred on long-term debt, capitalized interest, and the portion of operating lease rentals deemed representative of the interest factor.

(2) The ratio of earnings to fixed charges was less than one-to-one coverage and accordingly represents a deficit of $18.7 million, $14.3 million and $24.9 million for the years ended December 31, 2012, 2009 and 2008, respectively, and $11.8 million for the six months ended June 30, 2013.

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USE OF PROCEEDS

We will not receive any proceeds from the exchange of the Notes. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement. In consideration for issuing the Exchange Notes as contemplated by this prospectus, we will receive Outstanding Notes in a like principal amount. The Outstanding Notes surrendered in exchange for the Exchange Notes will be retired and canceled and will not be reissued. Accordingly, the issuance of the Exchange Notes will not result in any change in our capitalization.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA

The following table presents our selected historical consolidated financial and operating data for the periods indicated for Armstrong Energy, Inc. and its subsidiaries and our Predecessor. The selected historical financial data for the years ended December 31, 2008, 2009, 2010, 2011 and 2012 and the balance sheet data as of December 31, 2008, 2009, 2010, 2011 and 2012 are derived from the audited financial statements of Armstrong Energy, Inc. and our Predecessor. The selected financial data for the six months ended June 30, 2012 and 2013 and the balance sheet data as of June 30, 2012 and 2013 are derived from the unaudited financial statement included herein.

As of October 1, 2011, we no longer consolidate the results of operations of Armstrong Resource Partners in our consolidated financial statements and we account for our ownership in Armstrong Resource Partners under the equity method of accounting. As a result, our financial results for the years ended December 31, 2008, 2009 and 2010 are not directly comparable to our financial results for the years ended December 31, 2011 and 2012. For more information, please see Note 3, “Deconsolidation of Armstrong Resource Partners,” to our audited financial statements included herein.

Historical results are not necessarily indicative of results we expect in future periods. The following selected financial data should be read 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.

	Predecessor
	Year Ended December 31,															Six Months Ended June 30,
	2008			2009			2010			2011			2012			2012			2013
Results of Operations Data
Total revenues	$	57,069		$	167,904		$	220,625		$	299,270		$	382,109		$	193,173		$	202,466
Costs and expenses		64,667			166,686			201,473			291,335			375,461			183,740			196,528
Operating income (loss)		(7,598	)		1,218			19,152			7,935			6,648			9,433			5,938
Interest expense		(14,752	)		(12,651	)		(11,070	)		(10,839	)		(19,268	)		(9,050	)		(17,242	)
Other income (expense), net		971			988			87			278			(1,466	)		393			275
Gain (loss) on extinguishment of debt		—			—	��		—			6,954			(3,953	)		—			—
Income (loss) before income taxes		(21,379	)		(10,445	)		8,169			4,328			(18,039	)		776			(11,029	)
Income tax provision		—			—			—			(856	)		—			—			—
Net income (loss)		(21,379	)		(10,445	)		8,169			3,472			(18,039	)		776			(11,029	)
Less: income (loss) attributable to non-controlling interest		(5,552	)		(1,730	)		3,351			7,448			—			—			—
Net income (loss) attributable to common stockholders	$	(15,827	)	$	(8,715	)	$	4,818		$	(3,976	)	$	(18,039	)	$	776		$	(11,029	)
Balance Sheet Data (at period end)
Total assets	$	372,674		$	450,618		$	478,038		$	507,908		$	560,309		$	504,502		$	571,122
Working capital		(34,668	)		(17,749	)		2,905			(30,629	)		48,873			(33,181	)		39,120
Total long-term debt(1)		145,698			141,224			123,996			159,709			203,896			125,761			203,366
Total stockholders’ equity		168,931			255,333			296,681			168,138			182,662			199,475			171,069

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	Predecessor
	Year Ended December 31,															Six Months Ended June 30,
	2008			2009			2010			2011			2012			2012			2013
Other Data
Tons sold (unaudited)		1,398			4,674			5,387			7,030			8,521			4,263			4,454
Tons produced (unaudited)		1,379			4,434			5,645			6,642			8,769			4,454			4,677
Sales price per ton (unaudited)	$	40.82		$	35.92		$	40.96		$	42.57		$	44.84		$	45.32		$	45.45
Net cash provided by (used in):
Operating activities	$	(11,079	)	$	3,054		$	37,194		$	48,174		$	30,769		$	20,724		$	29,290
Investing activities		(80,020	)		(62,476	)		(41,755	)		(75,827	)		(46,524	)		(29,908	)		(40,617	)
Financing activities		79,402			64,854			(3,935	)		39,132			56,257			(7,669	)		(4,099	)
Adjusted EBITDA(2) (unaudited)		(1,029	)		16,567			41,099			41,601			50,854			30,764			29,330
Adjusted EBITDA is calculated as follows (unaudited):
Net income (loss)	$	(21,379	)	$	(10,445	)	$	8,169		$	3,472		$	(18,039	)	$	776		$	(11,029	)
Income tax provision		—			—			—			856			—			—			—
Depreciation, depletion and amortization		5,810			14,464			21,979			31,666			37,043			18,259			18,930
Non-cash production royalty to related party		—			—			—			578			5,695			2,363			4,017
Interest expense, net		14,377			12,482			10,872			10,694			19,200			9,016			17,212
Non-cash stock compensation expense		163			66			79			1,383			697			350			290
Loss on settlement of interest rate swap		—			—			—			—			1,409			—			—
Loss on deferment of equity offering		—			—			—			—			1,130			—			—
Gain on settlement of asset retirement obligations		—			—			—			—			(234	)		—			(90	)
(Gain) loss on extinguishment of debt		—			—			—			(6,954	)		3,953			—			—
Non-cash charge related to non-recourse notes		—			—			—			217			—			—			—
Gain on deconsolidation		—			—			—			(311	)		—			—			—
	$	(1,029	)	$	16,567		$	41,099		$	41,601		$	50,854		$	30,764		$	29,330

(1) Amount does not include $98.4 million and $71.0 million of certain long-term obligations to Armstrong Resource Partners as of December 31, 2012 and 2011, respectively, and $104.9 million and $96.8 million as of June 30, 2013 and 2012, respectively, which are characterized as financing transactions due to our continuing involvement in the lease of the related land and mineral reserves.

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

Adjusted EBITDA is defined as net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, non-cash production royalty to related party, loss on settlement of interest rate swap, loss on deferment of equity offering, gain on settlement of asset retirement obligations, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt.

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Adjusted EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDA reported by different companies, and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.

For example, Adjusted EBITDA does not reflect:

• cash expenditures, or future requirements, for capital expenditures or contractual commitments;

• changes in, or cash requirements for, working capital needs;

• the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt; and

• any cash requirements for assets being depreciated and amortized that may have to be replaced in the future.

Adjusted EBITDA does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital and other commitments and obligations. However, our management team believes Adjusted EBITDA is useful to an investor in evaluating our company because this measure:

• is widely used by investors in our industry to measure a 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.

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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 financial statements and related notes appearing elsewhere in this prospectus. This discussion and analysis contains forward-looking statements that involve a risks and uncertainties. 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 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 diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin, with both surface and underground mines. We market our coal primarily to proximate and investment grade electric utility companies as fuel for their steam-powered generators. Based on 2012 production, we are the fifth largest producer in the Illinois Basin and the second largest in Western Kentucky. We were formed in 2006 to acquire and develop a large coal reserve holding. We commenced production in the second quarter of 2008 and currently operate seven mines, including four surface and three underground. We control approximately 322 million tons of proven and probable coal reserves. Our reserves and operations are located in the Western Kentucky counties of Ohio, Muhlenberg, Union and Webster. We also own and operate three coal processing plants, which support our mining operations. From our reserves, we mine coal from multiple seams that, in combination with our coal processing facilities, enhance our ability to meet customer requirements for blends of coal with different characteristics. The locations of our coal reserves and operations, adjacent to the Green River, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling, and provide our customers with rail, barge and truck transportation options.

We market our coal primarily to large utilities with coal-fired, base-load, scrubbed power plants under multi-year coal supply agreements. Our multi-year coal supply agreements usually have specific and possibly different volume and pricing arrangements for each year of the agreement. These agreements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. At June 30, 2013, we had multi-year coal supply agreements with nine customers for terms ranging from one to six years. As of August 31, 2013, we are contractually committed to sell 9.2 million tons of coal in 2013 and 8.2 million tons of coal in 2014, which represents approximately 98% and 84% of our expected total coal sales in 2013 and 2014, respectively.

During the six months ended June 30, 2013 and 2012, we produced 4.7 million and 4.5 million tons of coal, respectively, and during the same periods, we sold 4.5 million and 4.3 million tons of coal, respectively. For the six months ended June 30, 2013, our revenue from coal sales was $202.5 million, and we generated operating income of $5.9 million, net loss of $11.0 million, and Adjusted EBITDA of $29.3 million. Our revenue, operating income, net income and Adjusted EBITDA for the six months ended June 30, 2012 were $193.2 million, $9.4 million, $0.8 million, and $30.8 million, respectively. During the three months ended June 30, 2013 and 2012, we produced 2.4 million and 2.3 million tons of coal, respectively, and during the same periods, we sold 2.2 million and 2.2 million tons of coal, respectively. For the three months ended June 30, 2013, our revenue from coal sales was $101.2 million, and we generated operating income of $4.0 million, net loss of $4.5 million, and Adjusted EBITDA of $15.7 million. Our revenue, operating income, net income and Adjusted EBITDA for the three months ended June 30, 2012 were $99.1 million, $6.6 million, $1.9 million and $17.9 million, respectively.

Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies (explosives, diesel fuel and electricity), maintenance, royalties and excise taxes. Unlike some of our competitors, we employ a completely non-union workforce. Many of the benefits of our non-union workforce are related to higher productivity and are not necessarily reflected in our direct costs. In addition, while we typically

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do not pay our customers’ transportation costs, they may be substantial and are often the determining factor in a coal consumer’s contracting decision. The location of our coal reserves and operations, adjacent to the Green and Ohio Rivers, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling and provide our customers with rail, barge and truck transportation options.

Evaluating the Results of Our Operations

We evaluate the results of our operations based on several key measures:

• our coal production, sales volume and weighted average sales prices;

• our cost of coal sales; and

• our Adjusted EBITDA, a non-GAAP financial measure.

We define our coal sales price per ton, or average sales price, as total coal sales divided by tons sold. We review coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis. We define Adjusted EBITDA as net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, non-cash production royalty to related party, loss on settlement of interest rate swap, loss on deferment of equity offering, gain on settlement of asset retirement obligations, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis, the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness, our operating performance and return on investment compared to those of other companies in the coal energy sector, without regard to financing or capital structures, and the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. Adjusted EBITDA has several limitations that are discussed under “Selected Historical Consolidated Financial and Operating Data,” where we also include a quantitative reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure, which is net income (loss).

Coal Production, Sales Volume and Sales Prices

We evaluate our operations based on the volume of coal we produce, the volume of coal we sell and the prices we receive for our coal. Because we sell substantially all of our coal under multi-year coal supply agreements, our coal production, sales volume and sales prices are largely dependent upon the terms of those contracts. The volume of coal we sell is also a function of the productive capacity of our mines and changes in our inventory levels and those of our customers.

Our multi-year coal supply agreements typically provide for a fixed price, or a schedule of fixed prices, over the contract term. In addition, the contracts typically contain price reopeners that provide for a market-based adjustment to the initial price after the initial years of those contracts have been fulfilled. These contracts would terminate if we cannot agree upon a market-based price with the customer. In addition, many of our multi-year coal supply agreements have full or partial cost pass through or inflation adjustment provisions; specifically, costs related to fuel, explosives and new government impositions are subject to certain pass-through provisions under many of our multi-year coal supply agreements. Cost pass-through provisions typically provide for increases in our sales prices in rising operating cost environments and for decreases in declining operating cost environments. Inflation adjustment provisions typically provide some protection in rising operating cost environments. We also receive premiums, or pay penalties, based upon the actual quality of the coal we deliver, which is measured for characteristics such as heat (Btu), sulfur and moisture content.

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We evaluate the price we receive for our coal on an average sales price per ton basis. The following table provides operational data with respect to our coal production, coal sales volume and average sales prices per ton for the periods indicated:

	Year Ended December 31,						Six Months Ended June 30,
	2010		2011		2012		2012		2013
	(In thousands, except per ton amounts)
Tons of Coal Produced		5,645		6,642		8,769		4,454		4,677
Tons of Coal Sold		5,387		7,030		8,521		4,263		4,454
Average Sales Price Per Ton	$	40.96	$	42.57	$	44.84	$	45.32	$	45.45

Cost of Coal Sales

We evaluate our cost of coal sales on a cost per ton basis. Our cost of coal sales per ton represents our production costs divided by the tons of coal we sell. Our production costs include labor and associated benefits, fuel, lubricants, explosives, operating lease expenses, repairs and maintenance, royalties, and all other costs that are directly related to our mining operations, other than the cost of depreciation, depletion and amortization (“DD&A”) expenses. Our production costs also exclude any indirect or selling related costs, such as selling, general and administrative (“SG&A”) expenses. Our production costs do not take into account the effects of any of the inflation adjustment or cost pass-through provisions in our multi-year coal supply agreements, as those provisions result in an adjustment to our coal sales price.

The following table provides summary information for the dates indicated relating to our cost of coal sales per ton produced:

	Year Ended December 31,						Six Months Ended June 30,
	2010		2011		2012		2012		2013
	(In thousands, except per ton amounts)
Tons of Coal Sold		5,387		7,030		8,521		4,263		4,454
Average Sales Price Per Ton	$	40.96	$	42.57	$	44.84	$	45.32	$	45.45
Cost of Coal Sales Per Ton	$	28.19	$	31.52	$	33.16	$	32.33	$	32.91

Adjusted EBITDA

Although Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, our management believes that it is useful in evaluating our financial performance. Adjusted EBITDA has several limitations that are discussed under “Selected Historical Consolidated Financial and Operating Data,” where we also include a quantitative reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure, which is net income (loss).

Factors that Impact Our Business

For the past three years, over 90% of our coal sales were made under multi-year coal supply agreements. We intend to continue to enter into multi-year coal supply agreements for a substantial portion of our annual coal production, using our remaining production to take advantage of market opportunities as they present themselves. We believe our use of multi-year coal supply agreements reduces our exposure to fluctuations in the spot price for coal and provides us with a reliable and stable revenue base. Using multi-year coal supply agreements also allows us to partially mitigate our exposure to rising costs, to the extent those contracts have full or partial cost pass through provisions or inflation adjustment provisions. For example, our contracts with LGE contain provisions that adjust the price paid for our coal in the event there is a change in the price of diesel fuel, a key cost component in our coal production. Certain of our other contracts, such as those with TVA, contain provisions that permit us to

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seek additional price adjustments to account for changes in environmental and other laws and regulations to which we are subject, to the extent those changes increase the cost of our production of coal.

Our anticipated coal production for 2013 is 9.4 million tons, with approximately 9.2 million tons, or 98%, committed and priced as of August 31, 2013. As of August 31, 2013, the average price per committed ton for 2013 is $44.78. As of August 31, 2013, we have approximately 8.2 million tons, or 84%, of our anticipated 2014 production committed and priced. As of August 31, 2013, the average price per committed ton for 2014 is $47.73.

Certain of our multi-year coal supply agreements contain option provisions that give the customer the right to elect to purchase, or defer the purchase of, additional tons of coal each month during the contract term at a fixed price provided for in the contract. Our multi-year coal supply agreements that provide for these option tons typically require the customer to provide us with advance notice of an election to take or defer these option tons. Because the price of these option tons is fixed under the terms of the contract, we could be obligated to deliver coal to those customers at a price that is below the market price for coal on the date the option is exercised. If our customers elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production. Similarly, short term changes by our customers in the amount of coal they purchase as a result of these option and deferment provisions may affect our average sales price per ton of coal in any given month or similarly narrow window. For example, as discussed in more detail below, our average sales price per ton during the year ended December 31, 2012 was higher than the average sales price per ton during the year ended December 31, 2011, due to higher pricing on our long-term contracts due to the annual increases under the majority of our multi-year coal supply agreements, and spot sales that did not occur in 2011.

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 2012 decreased by approximately 108 million tons, or 11%, from 2011 levels. The decline in U.S. domestic coal consumption during 2012 was primarily a function of 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.

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Results of Operations

Factors Affecting the Comparability of Our Results of Operations

The comparability of our operating results for the years ending December 31, 2010, 2011 and 2012 is impacted by the opening of additional mines during each of the periods. We began production of coal mid-year 2008 at one underground mine and one surface mine. Our coal production increased substantially from 1.4 million tons in 2008 to 8.8 million tons in 2012. The increase in production was primarily the result of the opening of two additional mines in 2009, a third in 2010, and three additional mines in 2011. Partially offsetting the impact of opening these new mines is the closure of one mine in 2011 and the temporary idling of another in 2012. Due to these changes in the number of operating mines during the aforementioned periods, it is difficult to provide direct comparisons of reported results during each period. In addition, as discussed in more detail below, from late 2009 through November 2010, we received a price incentive from LGE under one of our multi-year coal supply agreements, which added $3.29 per ton to the sales price under that agreement.

As of October 1, 2011, we no longer consolidate the results of operations of Armstrong Resource Partners in our consolidated financial statements and account for our ownership in Armstrong Resource Partners under the equity method of accounting. As a result, our financial results for the year ended December 31, 2010 are not directly comparable to our financial results for the years ended December 31, 2011 and 2012. For more information, please see Note 3, “Deconsolidation of Armstrong Resource Partners” in our audited financial statements included herein.

Summary

The following table presents certain of our historical consolidated financial data for the periods indicated. The following table should be read in conjunction with “Selected Historical Consolidated Financial and Operating Data.”

	Year Ended December 31,									Six Months Ended June 30,
	2010			2011			2012			2012			2013
	(In thousands, except per share and per ton amounts)
Results of Operations Data
Total revenues	$	220,625		$	299,270		$	382,109		$	193,173		$	202,466
Costs and expenses:
Costs of coal sales		151,838			221,597			282,569			137,794			146,606
Production royalties to related party		—			578			5,695			2,363			4,017
Depreciation, depletion and amortization		18,892			27,661			33,066			16,119			17,765
Asset retirement obligation expenses		3,087			4,005			3,977			2,140			1,165
Selling, general and administrative expenses		27,656			37,494			50,154			25,324			26,975
Total costs and expenses		201,473			291,335			375,461			183,740			196,528
Operating income		19,152			7,935			6,648			9,433			5,938
Interest expense		(11,070	)		(10,839	)		(19,268	)		(9,050	)		(17,242	)
Other income (expense), net		87			278			(1,466	)		393			275
Gain (loss) on extinguishment of debt		—			6,954			(3,953	)		—			—
Income (loss) before income taxes		8,169			4,328			(18,039	)		776			(11,029	)
Income tax provision		—			(856	)		—			—			—
Net income (loss)		8,169			3,472			(18,039	)		776			(11,029	)
Less: income attributable to non-controlling interest		3,351			7,448			—			—			—
Net income (loss) attributable to common stockholders	$	4,818		$	(3,976	)	$	(18,039	)	$	776		$	(11,029	)
Other Data
Adjusted EBITDA (unaudited)	$	41,099		$	41,601		$	50,854		$	30,764		$	29,330
Adjusted EBITDA per ton sold (unaudited)		7.63			5.92			5.97			7.22			6.59

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(1) Adjusted EBITDA is a non-GAAP financial measure which represents net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, non-cash production royalty to related party, loss on settlement of interest rate swap, loss on deferment of equity offering, gain on settlement of asset retirement obligations, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt. For these purposes, “GAAP” refers to U.S. generally accepted accounting principles. Please see “Selected Historical Consolidated Financial and Operating Data” for a reconciliation of Adjusted EBITDA to net income (loss).

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Overview

We reported revenue of $101.2 million for the three months ended June 30, 2013, compared to $99.1 million for the three months ended June 30, 2012. Coal sales were 2.2 million tons in the second quarter of 2013 and 2012. Our average sales price per ton in the three months ended June 30, 2013 totaled $45.18 per ton, as compared to $45.13 for the same period of the prior year. Our net loss and Adjusted EBITDA for the second quarter of 2013 was $4.5 million and $15.7 million, respectively, as compared to net income and Adjusted EBITDA for the second quarter of 2012 of $1.9 million and $17.9 million, respectively.

Coal Production and Sales Volume

Our tons of coal produced increased to 2.4 million tons during the three months ended June 30, 2013 from 2.3 million tons in the same period of 2012. This increase is primarily attributable to increased production at the Kronos underground mine, which completed development early in 2012, partially offset by a decline in production at the Midway surface mine in the current year due to a change in the mine plan.

Average Sales Price Per Ton

Our average sales price per ton increased to $45.18 during the second quarter of 2013 from $45.13 in the second quarter of 2012. This slight per ton increase is due to higher pricing from annual increases on our multi-year coal supply agreements.

Revenue

Our coal sales revenue for the three months ended June 30, 2013 increased by $2.1 million, or 2.2%, to $101.2 million, as compared to the three months ended June 30, 2012. This increase is primarily attributable to a favorable volume variance of approximately $2.0 million due to the minimal increase in tons sold in the current year. In addition, revenue was positively impacted by a favorable price variance of $0.1 million year over year, as discussed above.

Cost of Coal Sales (Excluding DD&A Expenses and SG&A Expenses)

Cost of coal sales (excluding depreciation, depletion, and amortization (DD&A) expenses) increased 4.7% to $72.0 million in the three months ended June 30, 2013, from $68.8 million in the same period of 2012. On a per ton basis, our cost of coal sales increased during the three months ended June 30, 2013, compared to the same period of 2012, from $31.33 per ton to $32.13 per ton. This increase is due to less favorable mining conditions at our Midway surface mine in 2013, partially offset by efficiencies gained in the current year at the Kronos underground mine due to the lack of restrictions on the depth of advancement that can be made at the mine.

Production Royalties to Related Party

Production royalties to related party increased $0.6 million to $2.0 million for the three months ended June 30, 2013, as compared to $1.4 million in the same period of 2012. The increase in production royalties earned by ARP is due to the increased production levels at the Kronos underground mine in the current year.

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Depreciation, Depletion and Amortization

DD&A expenses increased by $0.5 million, or 5.8%, during the three months ended June 30, 2013 to $9.0 million, as compared to the same period of 2012. The increase is primarily due to an increase in machinery and equipment as we continued to expand our operations in 2012 with the completion of the development of the Kronos underground mine. In addition, depletion and amortization expenses were slightly higher as a result of the higher production in 2013.

Asset Retirement Obligation Expense

Asset retirement obligation expense decreased by $0.4 million to $0.6 million in the three months ended June 30, 2013, as compared to the same period of 2012. The decrease is primarily attributable to changes in asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative Expenses

Selling, general, and administrative (SG&A) expenses were $13.7 million for the three months ended June 30, 2013, which was $0.9 million, or 7.2%, higher than the three months ended June 30, 2012. On a per ton basis for the three months ended June 30, 2013, SG&A expenses were $6.13, compared to $5.83 for the three months ended June 30, 2012. The increase in the three months ended June 30, 2013, as compared to the same period of 2012, is due primarily to higher coal severance and other selling related costs from the slight increase in tons sold in the current year, higher expense for compensation and related benefits due to annual compensation increases, and an increase in legal related expenses from litigating various matters.

Interest Expense, Net

Interest expense, net is derived from the following components:

	Three Months Ended June 30,
	2013		2012
11.75% Senior Secured Notes due 2019	$	5,875	$	—
Senior Secured Credit Facility		—		1,530
Long-term obligation to related party		2,773		2,408
Other, net		26		928
Total	$	8,674	$	4,866

Interest expense, net was $8.7 million for the three months ended June 30, 2013, as compared to $4.9 million for the three months ended June 30, 2012. The increase is principally attributable to a higher average interest rate in the current year due to the $200.0 million of 11.75% Senior Secured Notes due 2019 (the Notes) entered into in December 2012. We also have higher average borrowings in the current year, as compared to 2012, due to the incremental increase in borrowings from completing the senior notes offering in December 2012 and the repayment of the then outstanding senior secured credit facility. In addition, the closing of the reserve transfers to ARP in March 2012 and April 2013 increased the principal balance of the long-term obligation to related party by $25.7 million and $4.9 million, respectively.

Net (Loss) Income

Net loss for the three months ended June 30, 2013 was $4.5 million, as compared to net income of $1.9 million for the same period of 2012. The decline is largely due to the increase in interest expense from higher average borrowings and an increase in the average interest rate in the current year, as well as higher operating costs year-over-year, partially offset by the slight increase in tons sold and improved pricing in the current year.

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Adjusted EBITDA

Our Adjusted EBITDA for the three months ended June 30, 2013 was $15.7 million, or $7.02 per ton, as compared to $17.9 million, or $8.15 per ton, for the three months ended June 30, 2012. The decrease resulted primarily from higher average operating costs and SG&A expenses in the current year, partially offset by higher average sales prices, as well as an increase in the tons sold.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Overview

We reported revenue of $202.5 million for the six months ended June 30, 2013, compared to $193.2 million for the six months ended June 30, 2012. Coal sales increased 4.5% to 4.5 million tons in the first half of 2013, compared to 4.3 million tons in the same period of the prior year. Our average sales price per ton in the six months ended June 30, 2013 totaled $45.45 per ton, as compared to $45.32 for the same period of the prior year. Our net loss and Adjusted EBITDA for the first half of 2013 was $11.0 million and $29.3 million, respectively, as compared to net income and Adjusted EBITDA for the first half of 2012 of $0.8 million and $30.8 million, respectively.

Coal Production and Sales Volume

Our tons of coal produced increased to 4.7 million tons in the first half of 2013 from 4.5 million tons in the same period of 2012. This increase is primarily attributable to increased production at the Kronos underground mine, which completed development early in 2012, partially offset by a decline in production at the Midway surface mine in the current year due to a change in the mine plan.

Average Sales Price Per Ton

Our average sales price per ton increased to $45.45 in the first half of 2013 from $45.32 in the first half of 2012. This slight per ton increase is due to higher pricing from annual increases on our multi-year coal supply agreements, partially offset by unfavorable customer mix related to the timing of deliveries in the current year.

Revenue

Our coal sales revenue for the six months ended June 30, 2013 increased by $9.3 million, or 4.8%, to $202.5 million, as compared to the six months ended June 30, 2012. This increase is primarily attributable to a favorable volume variance of approximately $8.7 million due to the sale of 0.2 million additional tons in the current year from increased production at our Kronos underground mine in 2013, as compared to 2012, partially offset by a decline in production at the Midway surface mine due to a change in the mine plan in the current year. In addition, revenue was positively impacted by a favorable price variance of $0.6 million year over year, as discussed above.

Cost of Coal Sales (Excluding DD&A Expenses and SG&A Expenses)

Cost of coal sales (excluding DD&A expenses) increased 6.4% to $146.6 million in the six months ended June 30, 2013, from $137.8 million in the same period of 2012. This increase was primarily attributable to the 0.2 million increase in tons sold in 2013, as compared to 2012. On a per ton basis, our cost of coal sales increased during the six months ended June 30, 2013, compared to the same period of 2012, from $32.33 per ton to $32.91 per ton. This increase is due to less favorable mining conditions at our Midway and Lewis Creek surface mines in 2013, partially offset by efficiencies gained in the current year at the Kronos underground mine due to the lack of restrictions on the depth of advancement that can be made at the mine and favorable mining conditions at our Equality Boot mine in 2013.

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Production Royalties to Related Party

Production royalties to related party increased $1.6 million to $4.0 million for the six months ended June 30, 2013, as compared to $2.4 million in the same period of 2012. The increase in production royalties earned by ARP is due to the increased production levels at the Kronos underground mine in the current year.

Depreciation, Depletion and Amortization

DD&A expenses increased by $1.6 million, or 10.2%, during the six months ended June 30, 2013 to $17.8 million, as compared to the same period of 2012. The increase is primarily due to an increase in machinery and equipment as we continued to expand our operations in 2012 with the completion of the development of the Kronos underground mine. In addition, depletion and amortization expenses were slightly higher as a result of the higher production in 2013.

Asset Retirement Obligation Expense

Asset retirement obligation expense decreased by $1.0 million to $1.2 million in the six months ended June 30, 2013, as compared to the same period of 2012. The decrease is primarily attributable to changes in asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative Expenses

SG&A expenses were $27.0 million for the six months ended June 30, 2013, which was $1.7 million, or 6.5%, higher than the six months ended June 30, 2012. On a per ton basis for the six months ended June 30, 2013, SG&A expenses were $6.06, compared to $5.94 for the six months ended June 30, 2012. The increase is primarily due to higher coal severance and other selling related costs ($1.0 million) that are directly related to the 4.5% increase in total sales for the first half of 2013, as compared to the same period of 2012. In addition, we experienced higher expense for compensation and related benefits expense ($0.8 million) in the current year, as compared to the first half of 2012, as our employee count increased with the added production and year-over-year compensation increases. Partially offsetting the increase is a decline in information technology related expenses.

Interest Expense, Net

Interest expense, net is derived from the following components:

	Six Months Ended June 30,
	2013		2012
11.75% Senior Secured Notes due 2019	$	11,750	$	—
Senior Secured Credit Facility		—		3,184
Long-term obligation to related party		5,370		4,348
Other, net		122		1,518
Total	$	17,242	$	9,050

Interest expense, net was $17.2 million for the six months ended June 30, 2013, as compared to $9.1 million for the six months ended June 30, 2012. The increase is principally attributable to a higher average interest rate in the current year due to the $200.0 million of 11.75% Senior Secured Notes due 2019 entered into in December 2012. We also have higher average borrowings in the current year, as compared to 2012, due to the incremental increase in borrowings from completing the senior notes offering in December 2012 and the repayment of the then outstanding senior secured credit facility. In addition, the closing of the reserve transfers to ARP in March 2012 and April 2013 increased the principal balance of the long-term obligation to related party by $25.7 million and $4.9 million, respectively.

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Net (Loss) Income

Net loss for the six months ended June 30, 2013 was $11.0 million, as compared to net income of $0.8 million for the same period of 2012. The decline is largely due to the increase in interest expense from higher average borrowings and an increase in the average interest rate in the current year, as well as higher operating costs and SG&A costs year-over-year, partially offset by the increase in tons sold and improved pricing in the current year.

Adjusted EBITDA

Our Adjusted EBITDA for the six months ended June 30, 2013 was $29.3 million, or $6.59 per ton, as compared to $30.8 million, or $7.22 per ton, for the six months ended June 30, 2012. The decrease resulted primarily from higher average operating costs and SG&A expenses in the current year, partially offset by higher average sales prices, as well as an increase in the tons sold.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Overview

We reported revenue of $382.1 million for the year ended December 31, 2012, compared to $299.3 million for the year ended December 31, 2011. Coal sales increased 21.2% to 8.5 million tons in 2012, compared to 7.0 million tons in 2011. Our average sales price per ton for the year ended December 31, 2012 increased 5.3%, to $44.84 per ton, compared to the prior year. Our net loss and Adjusted EBITDA for the year ending December 31, 2012 was $18.0 million and $50.9 million, respectively, as compared to net income and Adjusted EBITDA for 2011 of $3.5 million and $41.6 million, respectively.

Coal Production and Sales Volume

Our tons of coal produced increased 32.0% to 8.8 million tons in 2012 from 6.6 million tons in 2011. This increase is primarily attributable to (a) the commencement of production at the Lewis Creek surface mine and Kronos underground mine in June 2011 and September 2011, respectively, and (b) increased production at our Equality Boot surface mine in 2012, which resulted in an incremental increase in our sales by 2.9 million tons, year over year. This increase was partially offset by the closure of the Big Run underground mine in October 2011 and the temporary idling of the East Fork mine in March 2012.

Average Sales Price Per Ton

Our average sales price per ton increased 5.3% to $44.84 in 2012 from $42.57 in 2011. This $2.27 per ton increase resulted from the combination of (a) higher pricing due to annual increases on our multi-year coal supply agreements, (b) an increase in spot sales that did not occur in 2011, and (c) the addition of new customers in the current year whose pricing is commensurate with current market prices.

Revenue

Our coal sales revenue for the year ended December 31, 2012 increased by $82.8 million, or 27.7%, compared to the year ended December 31, 2011. This increase is primarily attributable to increased sales volume year over year, as we had a full year of production from our Lewis Creek surface mine and Kronos underground mine, which were opened during June 2011 and September 2011, respectively, and increased productivity at our Equality Boot mine in 2012. Partially offsetting the increase in volume is the closure of the Big Run mine in October 2011 and the temporary idling of the East Fork mine in March 2012. These factors contributed to a year-over-year increase in revenue of $63.5 million. In addition, revenue was positively impacted by increased pricing year over year, as discussed above, which resulted in a year-over-year increase in revenue of approximately $19.3 million.

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Cost of Coal Sales (Excluding DD&A Expenses and SG&A Expenses)

Cost of coal sales (excluding DD&A expenses) increased 27.5% to $282.6 million in the year ended December 31, 2012, from $221.6 million in the prior year. This increase was primarily attributable to a full year of production from the Lewis Creek surface mine and Kronos underground mine, which increased operating costs by $69.6 million during 2012, as compared to 2011. In addition, cost of coal sales declined in the current year due to the closure of the Big Run mine and temporary idling of the East Fork mine, which was offset by increased costs at the Equality Boot mine due to the implementation of the new ground control plan in the fourth quarter of 2011 and less favorable mining conditions at the Parkway and Midway mines during 2012. On a per ton basis, our cost of coal sales increased from the year ended December 31, 2011 to 2012 from $31.52 per ton to $33.16 per ton, due primarily to the expansion of our underground operations with the opening of the Kronos mine, which are higher cost operations as compared to our surface mines and higher costs at our Equality Boot mine resulting from changes in the ground control plan implemented in the fourth quarter of 2011. In addition, we experienced operating inefficiencies at our Kronos mine in the first half of the year from restrictions on the depth of advancement that can be made.

Production Royalties to Related Party

Production royalties to related party increased $5.1 million to $5.7 million in 2012, as compared to $0.6 million in the prior year. The increase in production royalties earned by Armstrong Resource Partners is due to a full year of production from the Kronos underground mine in 2012.

Depreciation, Depletion and Amortization Expenses

DD&A expenses increased by $5.4 million, or 19.5%, during 2012, as compared to 2011. The primary reason for the increase was a $5.2 million increase in depreciation associated with the opening of the Lewis Creek surface mine and Kronos underground mine in the latter half of 2011. Depletion and amortization expenses were also higher as a result of the higher production in 2012, partially offset by a reduction in depreciation and amortization expenses from the closure of the Big Run mine in September 2011 and temporary idling of the East Fork mine in March 2012.

Asset Retirement Obligation Expense

Asset retirement obligation expense for the year ended December 31, 2012 is comparable to the amount incurred in the prior year. Increased expense in the current year from the opening of the Lewis Creek surface mine and the Kronos underground mine in the prior year was offset by the impact of the closure of the Big Run mine in 2011 and Maddox mine in 2012.

Selling, General and Administrative Expenses

SG&A expenses were $50.2 million for the year ended December 31, 2012, which was $12.7 million, or 33.8%, higher than the year ended December 31, 2011. On a cost per ton sold basis for the year ended December 31, 2012, SG&A expenses were $5.89, compared to $5.33 for 2011. Administrative expenses related to the Lewis Creek surface mine and Kronos underground mine accounted for the majority of the increase in costs, as well as higher coal severance and similar costs that are directly related to the $82.8 million, or 27.7%, increase in total sales for 2012, as compared to 2011.

Interest Expense

Interest expense was $19.3 million for the year ended December 31, 2012, as compared to $10.8 million for the year ended December 31, 2011. The increase was principally attributable to interest expense incurred in 2012 associated with the long-term obligation to a related party totaling $9.3 million that was recognized as a result of the deconsolidation of Armstrong Resource Partners on October 1, 2011. Interest expense recognized in 2011 related to the long-term obligation to a related party totaled $2.5 million.

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Other Income (Expense), Net

Other income (expense), net totaled expense of $1.5 million for the year ended December 31, 2012, as compared to expense of $0.2 million for the year ended December 31, 2011. Other income (expense), net for 2012 included a loss on settlement of interest rate swap of $1.4 million associated with terminating an interest rate swap in conjunction with the prepayment and termination of the senior secured credit facility and a loss on deferment of equity offering of $1.1 million. We had previously deferred costs incurred related to a proposed equity offering. In the fourth quarter of 2012, as the offering had been delayed for an extended period of time, a charge was recognized to write-off all deferred amounts associated with the proposed equity offering. Partially offsetting these charges in 2012 was revenue earned from timber, scrap, and crop sales. The prior year expense consists of multiple items which are individually immaterial.

(Loss) Gain on Extinguishment of Debt

In February 2011, we entered into a senior secured credit facility (the “2011 Credit Facility”) and repaid our then outstanding promissory notes with the proceeds. As a result of the aforementioned repayment, we recorded a gain on extinguishment of debt of $7.0 million in the year ended December 31, 2011. On December 21, 2012, we completed a $200.0 million offering of senior secured Notes, the proceeds of which were used to prepay and terminate the 2011 Credit Facility. As a result, we recognized a loss on extinguishment of debt of $4.0 million associated with the write-off of a portion of the unamortized deferred financing costs. See “Description of Other Indebtedness” for a more detailed discussion of our financing activities.

Income Taxes

We recorded an income tax provision of zero and $0.9 million for the years ended December 31, 2012 and 2011, respectively. The 2011 provision related primarily to current alternative minimum tax and certain state income tax as a result of taxable income generated from certain of our subsidiaries in 2011.

Net Income (Loss)

Our net loss for the year ended December 31, 2012 was $18.0 million, as compared to net income of $3.5 million for the year ended December 31, 2011. The decline in net earnings is due to an increase in per ton operating costs resulting from the increase in underground production, higher DD&A expenses as a result of the continued expansion of our overall operations and increased production, and an increase in interest expense resulting from the recognition of a long-term obligation to a related party as a result of the deconsolidation of Armstrong Resource Partners on October 1, 2011. Partially offsetting the overall earnings decline is an increase in revenue from both favorable price and volume variances.

Adjusted EBITDA

Our Adjusted EBITDA for the year ended December 31, 2012 was $50.9 million, or $5.97 per ton, as compared to $41.6 million, or $5.92 per ton, for the year ended December 31, 2011. The increase resulted primarily from an increase in revenue related to the higher average sales prices, as well as an increase in the tons sold due to the increase in the number of mines in operation. This increase was partially offset by higher operating costs at the Kronos and Parkway underground mines and Equality Boot and Midway surface mines in 2012.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Overview

We reported revenue of $299.3 million for the year ended December 31, 2011, compared to $220.6 million for the year ended December 31, 2010. Coal sales increased 30% to 7.0 million tons in 2011, compared to

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5.4 million tons in 2010. Our average sales price per ton in 2011 increased 3.9%, or $1.61 per ton, compared to 2010. Our net income decreased from $8.2 million in 2010 to $3.5 million in 2011. Our Adjusted EBITDA increased slightly to $41.6 million for 2011 from $41.1 million for 2010.

Coal Production and Sales Volume

Our tons of coal produced increased 17.7% to 6.6 million tons in 2011 from 5.6 million tons in 2010. This increase is primarily attributable to the commencement of production at the Equality Boot, Lewis Creek, and Maddox surface mines, which increased our sales by 2.6 million tons for 2011, as compared to 2010. This increase was partially offset by lower production at our other surface mines as a result of high levels of rainfall, decreases at our East Fork operation of 0.9 million tons as a portion of the mine was depleted and MSHA mandates that impacted production at the Big Run mine. Sales volume during 2011 was slightly lower than anticipated due to weather-induced high water issues on the Green and Ohio Rivers, which delayed barge deliveries to two of our customers. However, the reduction in barge-delivered tons was partially offset by an increase in the number of tons delivered by truck. In addition, maintenance cycles at the primary plants receiving our coal under our contracts with TVA resulted in the deferment or force majeure of approximately 327,000 tons of scheduled deliveries during 2011.

Average Sales Price Per Ton

Our average sales price per ton increased 3.9% to $42.57 in 2011 from $40.96 in 2010. This $1.61 per ton increase resulted from the combination of (a) higher pricing on our long-term contracts due to the annual increases under the majority of our multi-year coal supply agreements, and (b) spot sales that did not occur in 2010. These increases were partially offset by the elimination of the $3.29 per ton price adjustment in December 2010 that we received from LGE pending permitting approval of our Equality Boot mine.

Revenue

Our coal sales revenue for 2011 increased by $78.6 million, or 35.6%, compared to 2010. This increase is primarily attributable to coal sales from our Equality Boot and Lewis Creek mines, which completed development during January 2011 and June 2011, respectively, and contributed an additional $95.6 million of revenue as compared to 2010. The positive effect of the opening of the Equality Boot and Lewis Creek mines was partially offset by record rainfall amounts that hampered barge deliveries, the partial deferment of deliveries of scheduled tons under contract by TVA, Big Rivers and Alcoa.

Operating Costs and Expenses (Excluding DD&A Expenses and SG&A Expenses)

Operating costs and expenses increased 45.9% to $221.6 million in 2011, from $151.8 million in 2010. This increase was primarily attributable to completing development of our Equality Boot and Lewis Creek mines in January 2011 and June 2011, respectively, which resulted in operating costs of $79.7 million during 2011. On a per ton basis, our cost of coal sales increased during 2011, compared to 2010, from $28.19 per ton to $31.52 per ton, due to unfavorable mining conditions at our surface mines as a result of record rainfall amounts, poor roof conditions at the Big Run mine that required additional support and reduced productivity, and reduced production at the Parkway and East Fork mines. In addition, we experienced higher material and supplies costs in 2011, compared to 2010, related to equipment maintenance expenses and fuel and oil-related expenses. Specifically:

• Equipment maintenance expenses per ton sold increased 22.7% to $8.71 per ton in 2011 from $7.10 per ton in 2010. The increase of $23.0 million in 2011 as compared to 2010 is primarily the result of the cost of additional equipment at our Equality Boot mine; and

• Fuel and oil-related expenses per ton sold increased 62.5% to $4.11 per ton in 2011 from $2.53 per ton in 2010. The increase of $15.2 million in 2011 as compared to 2010 is the result of higher fuel prices in 2011. A portion of the higher fuel prices will be recovered through higher revenue in future periods through fuel adjustment cost provisions in certain of our multi-year coal supply agreements.

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Depreciation, Depletion and Amortization Expenses

DD&A expenses increased by $8.8 million, or 46.4%, during 2011, as compared to 2010. The primary reason for the increase was a $10.0 million increase in DD&A associated with the Equality Boot and Lewis Creek operations. Amortization expense was also slightly higher as a result of the higher production in 2011. Lower depletion and depreciation expenses were realized at operations with reduced production levels from 2010, thereby offsetting a portion of the increases.

Asset Retirement Obligation Expense

Asset retirement obligation expense increased by $0.9 million, or 29.7%, in 2011, as compared to 2010. The increase is due primarily to the opening of the Equality Boot and Lewis Creek mines.

Selling, General and Administrative Expenses

SG&A expenses were $38.1 million for 2011, which was $10.4 million, or 37.7%, higher than 2010. On a cost per ton sold basis for 2011, SG&A expenses were $5.42, compared to $5.13 for 2010. Administrative expenses related to the Equality Boot and Lewis Creek mines accounted for the majority of the increase in costs, and higher coal severance and similar costs that are directly related to the $78.6 million, or 35.6%, increase in total sales for 2011 as compared to 2010.

Interest Expense

Interest expense was $10.8 million for 2011, as compared to $11.1 million for 2010. The decrease was principally attributable to lower interest rates associated with the 2011 Credit Facility as compared to our outstanding debt during 2010 in the form of the promissory notes that were repaid when we entered into the 2011 Credit Facility in February 2011. The decline was partially offset by interest expense incurred associated with the long-term obligation to a related party that was recognized as a result of the deconsolidation of Armstrong Resource Partners on October 1, 2011. As a result of the aforementioned repayment of outstanding promissory notes, we recorded a gain on extinguishment of debt of $7.0 million in 2011.

Income Taxes

We recorded an income tax provision of $0.9 million for 2011 while no provision was recorded in 2010. The provision related primarily to current alternative minimum tax and certain state income tax. The current provision is due to taxable income generated in 2011 for certain subsidiaries, compared to taxable losses generated in 2010.

Net Income (Loss)

Our net income declined $4.7 million from $8.2 million for the year ended December 31, 2010 to $3.5 million for the year ended December 31, 2011. The decline in net earnings is due to higher per ton operating costs as a result of unfavorable mining conditions and higher DD&A and SG&A expenses due to the continued expansion of our operations. Partially offsetting the overall earnings decline is an increase in revenue from both favorable price and volume variances and the recognition of a $7.0 million gain on extinguishment of debt associated with the repayment of certain outstanding promissory notes in 2011.

Adjusted EBITDA

Our Adjusted EBITDA for 2011 was $41.6 million, or $5.92 per ton, as compared to $41.1 million, or $7.63 per ton, for 2010. The increase resulted from an increase in tons sold and higher average sales price, partially offset by the partial deferment of deliveries of scheduled tons under contract by TVA, Big Rivers and Alcoa, the expiration of the price incentive realized during 2010 in connection with one of our LGE sales

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contracts, and the higher operating costs attributable to the commencement of production at the Equality Boot and Lewis Creek mines during 2011.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in mining our reserves, as well as complying with applicable environmental laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service our debt. Our primary sources of liquidity to meet these needs have been cash generated by our operations, borrowings under our credit facilities and contributions from our equity holders.

On December 21, 2012, we completed a $200.0 million offering of 11.75% senior secured Notes due 2019 and received proceeds of $193.1 million, as the Notes were issued at an OID of 96.567%. Interest on the Notes is due semiannually on June 15 and December 15 of each year, with the first payment made on June 15, 2013. In connection with the offering, we prepaid and terminated our then existing 2011 Credit Facility and recognized a loss on extinguishment of debt of $4.0 million associated with the write-off of a portion of the unamortized deferred financing costs incurred on the 2011 Credit Facility. In addition, we entered into the Revolving Credit Facility, an asset-based revolving credit facility, which provides for revolving borrowings of up to $50.0 million.

We believe that existing cash balances, cash generated from operations and borrowings under our Revolving Credit Facility will be sufficient to meet working capital requirements, anticipated capital expenditures and debt service requirements. We manage our exposure to changing commodity prices for our long-term coal contract portfolio through the use of multi-year coal supply agreements. We generally enter into fixed price, fixed volume supply contracts with terms greater than one year with customers with whom we have historically had limited collection issues. Our ability to satisfy debt service obligations, to fund planned capital expenditures, and to make acquisitions, will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.

The principal indicators of our liquidity are our cash on hand and availability under our Revolving Credit Facility. As of June 30, 2013, our available liquidity was $64.4 million, comprised of cash on hand of $44.7 million and $19.7 million available under our Revolving Credit Facility.

Our long-term debt consisted of the following as of the dates indicated:

	December 31,				June 30,
Type	2011		2012		2013
11.75% Senior Secured Notes due 2019	$	—	$	193,152	$	193,473
Revolving Credit Facility		—		—		—
2011 Credit Facility—Term Loan		100,000		—		—
2011 Credit Facility—Revolving Credit Facility		40,000		—		—
Other		19,709		10,744		9,893
		159,709		203,896		203,366
Less: current maturities		33,957		3,935		4,354
Total long-term debt	$	125,752	$	199,961	$	199,012

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Senior Secured Notes due 2019

On December 21, 2012, we completed the $200.0 million Notes offering. The Notes were issued at an OID of 96.567%. The OID was recorded on our balance sheet as a component of long-term debt, and is being amortized to interest expense over the life of the Notes. As of June 30, 2013, the unamortized OID was $6.5 million. We incurred $8.4 million of deferred financing fees related to the Notes, which have been capitalized and will be amortized over the life of the Notes.

Interest on the Notes is due semiannually on June 15 and December 15 of each year, with the first payment made on June 15, 2013. We may redeem all or part of the Notes at any time prior to December 15, 2016, at a redemption price of 100% of the Notes redeemed plus a “make-whole” premium and accrued and unpaid interest to the applicable redemption date. We may redeem the Notes, in whole or in part, at any time during the twelve months commencing on December 15, 2016 at 105.875% of the principal amount redeemed, at any time during the twelve months commencing December 15, 2017 at 102.938% of the principal amount redeemed, and at any time after December 15, 2018 at 100.000% of the principal amount redeemed, in each case plus accrued and unpaid interest to the applicable redemption date. In addition, at any time prior to December 15, 2015, we may redeem Notes with the net cash proceeds received from one or more Equity Offerings (as defined in the indenture governing the Notes) at a redemption price equal to 111.75% of the principal amount redeemed plus accrued and unpaid interest to the applicable redemption date, in an aggregate principal amount for all such redemptions not to exceed 35% of the original aggregate principal amount of the Notes.

Upon the occurrence of an event of a Change in Control (as defined in the indenture governing the Notes), unless we have exercised our right to redeem the Notes, we will be required to make an offer to purchase the Notes at a redemption price of 101.000%, plus accrued and unpaid interest to the date of repurchase.

Subject to certain customary release provisions, the Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by us and substantially all of our current and future domestic restricted subsidiaries (as defined). See “Description of Exchange Notes—Note Guarantees.” They are also secured, subject to certain exceptions and permitted liens, on a first-priority basis by substantially all of our and the guarantors’ assets that do not secure the Revolving Credit Facility (see below) on a first-priority basis. Subject to certain exceptions and permitted liens, the Notes will also be secured on a second-priority basis by a lien on the assets securing our obligations under the Revolving Credit Facility on a first-priority basis.

The indenture governing the Notes contains restrictive covenants which, among other things, limit the ability (subject to exceptions) of us and our restricted subsidiaries (as defined) to (a) incur additional indebtedness or issue preferred equity; (b) pay dividends or distributions on or purchase our stock or our restricted subsidiaries’ stock; (c) make certain investments; (d) use assets as security in other transactions; (e) create guarantees of indebtedness by restricted subsidiaries; (f) enter into agreements that restrict dividends, distributions, or other payment by restricted subsidiaries; (g) sell certain assets or merge with or into other companies; and (h) enter into transactions with affiliates.

We and the guarantor subsidiaries entered into a registration rights agreement (the “Registration Rights Agreement”) in connection with the issuance and sale of the Notes. Pursuant to the Registration Rights Agreement, we and the guarantor subsidiaries agreed to file a registration statement with the SEC to register an exchange offer pursuant to which we will offer to exchange a like aggregate principal amount of senior notes identical in all material respects to the Notes, except for terms relating to transfer restrictions, for any or all of the outstanding Notes. Pursuant to the Registration Rights Agreement, we must use commercially reasonable efforts to cause the registration statement to become effective as soon as practicable and to complete the exchange offer no later than June 30, 2014. Should those events not occur within the specified time frame, the applicable interest rates on the Notes shall be increased by 0.25% per annum for the first 90 days following the occurrence of such failure. Such interest rate will increase by an additional 0.25% per annum thereafter at the end of each subsequent 90-day period up to a maximum aggregate increase of 1.0% per annum. Once any of the required events occurs, the interest rates will revert to the rate specified in the indenture governing the Notes.

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Revolving Credit Facility

Concurrently with the closing of the Notes offering on December 21, 2012, we entered into the Revolving Credit Facility, an asset-based revolving credit facility. The Revolving Credit Facility provides for a five-year $50.0 million revolving credit facility that will expire on December 21, 2017. Borrowings under the Revolving Credit Facility may not exceed a defined borrowing base. In addition, the Revolving Credit Facility includes a $10.0 million letter of credit sub-facility and a $5.0 million swingline loan sub-facility. As of December 31, 2012 and June 30, 2013, there were no borrowings outstanding under the Revolving Credit Facility and we had $20.0 million and $19.7 million, respectively, available for borrowing under the facility. We incurred $1.2 million of deferred financing fees related to the Revolving Credit Facility that have been capitalized and are being amortized to interest expense over the life of the facility.

Interest and Fees

Borrowings under the Revolving Credit Facility bear interest, at our option, at a rate based on (i) LIBOR, plus a margin ranging from 3.5% to 4.0%, or (ii) a base rate, plus a margin ranging from 2.5% to 3.0%. Margins may be increased by 2.0% per annum during the existence of any event of default. We are also required to pay certain other fees with respect to the Revolving Credit Facility, including (i) an unused commitment fee ranging from 0.50% to 0.375% in respect of unutilized commitments, (ii) a fronting fee equal to 0.25% per annum of the amount of outstanding letters of credit and (iii) customary annual administration fees.

Collateral and Guarantors

The Revolving Credit Facility is secured by substantially all of our and our subsidiaries’ assets (other than certain excluded assets), with (i) a first priority lien on the ABL Priority Collateral (as defined) and (ii) a second priority lien on the Notes Priority Collateral (as defined). The Revolving Credit Facility is also guaranteed on a full and unconditional basis by the same subsidiaries that guarantee the Notes.

Restrictive Covenants and Other Matters

The Revolving Credit Facility includes customary covenants that, subject to certain exceptions, restrict our ability and the ability of our subsidiaries to, among other things, incur indebtedness (including capital leases), create liens on assets, make investments, loans, guarantees, advances or acquisitions, pay dividends and distributions, liquidate, merge or consolidate, divest assets, engage in certain transactions with affiliates, create joint ventures or subsidiaries, change the nature of our business, change our fiscal year, issue stock, amend organizational documents, make capital expenditures and provide negative pledges on assets. In addition, at any time when (i) undrawn availability is less than the greater of (a) $10 million or (b) an amount equal to 20% of the borrowing base or (ii) an event of default has occurred and is continuing, we will be required to maintain a fixed charge coverage ratio, calculated as of the end of each calendar month for the twelve months then ended, greater than 1.0 to 1.0.

The Revolving Credit Facility also contains customary affirmative covenants and events of default. If an event of default occurs, the lenders under the Revolving Credit Facility will be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.

Prepayments and Commitment Reductions

Voluntary prepayments and commitment reductions will be permitted, in whole or in part, in minimum amounts without premium or penalty, other than customary breakage costs with respect to LIBOR loans.

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2011 Credit Facility

On February 9, 2011, we entered into the 2011 Credit Facility, which was comprised of a $100.0 million term loan and a $50.0 million revolving credit facility. The term loan was a five-year term loan that required principal payments in the amount of $5.0 million on the first day of each quarter commencing on January 1, 2012 through January 1, 2016, with the remaining outstanding principal and interest balance due upon maturity on February 9, 2016. On December 21, 2012, in connection with the offering of the Notes, we voluntarily prepaid and terminated the 2011 Credit Facility, and repaid all outstanding amounts under the agreement. As a result of the prepayment and termination of the 2011 Credit Facility, we recognized a loss on extinguishment of debt of $4.0 million in connection with the write-off of related unamortized deferred financing costs.

Cash Flows

The following table reflects cash flows for the applicable periods:

	Year Ended December 31,									Six Months Ended June 30,
	2010			2011			2012			2012			2013
	(In thousands)
Net cash provided by (used in):
Operating Activities	$	37,194		$	48,174		$	30,769		$	20,724		$	29,290
Investing Activities	$	(41,755	)	$	(75,827	)	$	(46,524	)	$	(29,908	)	$	(40,617	)
Financing Activities	$	(3,935	)	$	39,132		$	56,257		$	(7,669	)	$	(4,099	)

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Net cash provided by operating activities was $29.3 million for the six months ended June 30, 2013, an increase of $8.6 million from net cash provided by operating activities of $20.7 million for the same period of 2012. We experienced a decline in operating income in the first half of 2013 due to higher operating costs and an increase in SG&A expenses, partially offset by increased revenue from selling more tons and improved pricing year over year. The higher production levels and completion of the Kronos underground mine also increased DD&A by $1.6 million in the first half of 2013, as compared to the same period of 2012. Positively impacting cash flows from operations for the six months ending June 30, 2013 was an increase in accounts payable and accrued liabilities of $16.5 million due to the timing of payments as well as increased capital expenditures associated with the development of the Lewis Creek underground mine, which was completed in the first half of 2013 and an increase in related party payables, which is included as a component of other non-current liabilities, due to an increase in royalties earned by Armstrong Resource Partners. Negatively impacting operating cash flows was an increase in inventory experienced during the six months ended June 30, 2013 due to an increase in coal inventory on hand, as well as an increase in materials and supplies inventory resulting from the development of the Lewis Creek underground mine. Impacting cash flows from operations for the six months ended June 30, 2012 was an increase in accounts receivable due to the ramping up of the Kronos underground mine in the first half of 2012 and a decline in advanced royalties, which is included as a component of other non-current assets, from the continued increase in tons being sold.

Net cash used in investing activities increased $10.7 million to $40.6 million for the six months ended June 30, 2013, compared to $29.9 million for the same period of 2012. The current year investment is largely attributable to capital expenditures on equipment and mine development for the completion of the Lewis Creek underground mine, whereas the 2012 investment relates to capital expenditures for the completion of the Kronos underground mine and the initial development of the Lewis Creek underground mine. In addition, negatively impacting cash flows in the six months ending June 30, 2013 is the short-term note of $17.5 million to Thoroughbred, a related party. The proceeds from the note, which was repaid in July 2013, were used by Thoroughbred as a partial down-payment to acquire additional reserves that are anticipated to be leased to us.

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Net cash used in financing activities was $4.1 million for the six months ended June 30, 2013, compared to net cash used in financing activities of $7.7 million for the six months ended June 30, 2012. The current year activity relates primarily to scheduled capital lease and other long-term debt payments. The prior year activity consists of the issuance of $30.0 million of Series A convertible preferred stock, offset by scheduled debt payments and the repayment of $15.0 million under our then existing senior secured credit facility with a portion of the proceeds.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Net cash provided by operating activities was $30.8 million for the year ended December 31, 2012, a decrease of $17.4 million from net cash provided by operating activities of $48.2 million for 2011. We experienced a decline in operating income in the year ended December 31, 2012, as compared to 2011. While there was an increase in tons sold from operating more mines, as well as improved pricing in 2012, this was partially offset by higher average operating costs and SG&A costs. The operation of additional mines and higher production levels also increased DD&A by $5.4 million in 2012, as compared to 2011. Further, the continued expansion has impacted the cash flows from operating assets and liabilities in 2012, primarily by leading to an increase in accounts receivable and a decline in advanced royalties, which is included as a component of other non-current assets. In addition, we recognized a loss on extinguishment of debt in 2012 of $4.0 million associated with the prepayment and termination of the 2011 Credit Facility. Impacting cash flows from operations for the year ended December 31, 2011 was the inclusion of a non-cash gain on early extinguishment of debt, as well as our opening of the Equality Boot, Lewis Creek, and Kronos mines in September 2010, June 2011, and September 2011, respectively, that resulted in a net increase in cash from operating assets and liabilities resulting from increased accounts payable and payroll and other accrued incentives, partially offset by an increase in accounts receivable. In addition, positively impacting cash flows from operations was a decline in inventories of approximately $1.6 million in 2011 due to lower productivity levels at certain of our mines resulting from weather and other mining related issues earlier in the year.

Net cash used in investing activities was $46.5 million for the year ended December 31, 2012, compared to $75.8 million for 2011. The 2012 investment is primarily attributable to capital expenditures on equipment and mine development for the continued expansion of our Kronos underground mine and development of our Lewis Creek underground mine, whereas the 2011 investment relates to capital expenditures on the initial development of the Kronos underground mine and development of the Lewis Creek surface mine. In addition, we made an investment in 2011 of approximately $2.5 million in an affiliate for the planned construction of an export facility on the lower Mississippi River.

Net cash provided by financing activities was $56.3 million for the year ended December 31, 2012, compared to net cash provided by financing activities of $39.1 million for the year ended December 31, 2011. The 2012 activity consists of the $200.0 million Notes offering, issuance of $30.0 million of Series A convertible preferred stock and borrowings of $18.5 million under the 2011 Credit Facility, offset by the payment of long-term debt obligations of $169.9 million, which includes scheduled debt maturities and the repayment and termination of the 2011 Credit Facility with proceeds from the Notes offering and the payment of financing fees totaling $11.1 million primarily related to the Notes offering and the establishment of the Revolving Credit Facility. The 2011 net cash inflow is primarily attributable to the closing of the 2011 Credit Facility and the repayment of our then existing long-term debt in connection therewith.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net cash provided by operating activities was $48.2 million for the year ended December 31, 2011, an increase of $11.0 million from net cash provided by operating activities of $37.2 million for 2010. The increase in cash provided by operating activities was principally attributable to the expansion of our operations with completing development of the Equality Boot and Lewis Creek mines in January 2011 and June 2011, respectively, and the initiation of development of the Kronos mine in September 2011. The additional mines and

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higher production levels resulted in increased DD&A expense in the current year, as well as impacted our cash flows from operating assets and liabilities, primarily by leading to an increase in accounts payable and payroll and other accrued incentives in the current year. Negatively impacting cash flows from operations was a year-over-year decline in net income due to higher overall operating costs and the inclusion of a non-cash gain on extinguishment of debt recognized in the year ended December 31, 2011.

Net cash used in investing activities was $75.8 million for the year ended December 31, 2011, compared to $41.8 million for 2010. This $34.0 million increase was primarily attributable to capital expenditures on equipment and mine development for our Kronos and Lewis Creek mines, as well as the acquisition of additional reserves in December 2011. In addition, we made an investment in an affiliate for the planned construction of an export facility on the lower Mississippi River in 2011 of $2.5 million.

Net cash provided by financing activities was $39.1 million for the year ended December 31, 2011, compared to net cash used in financing activities of $3.9 million for the year ended December 31, 2010. This difference was primarily attributable to the closing of the 2011 Credit Facility and the repayment of our existing long-term debt in connection therewith. In addition, we received $20.0 million from Armstrong Resource Partners in December 2011 in connection with the transfer of an undivided interest in certain of our reserves, which closed in March 2012. Partially offsetting the increase in net cash provided by financing activities is the year-over-year decline in minority contributions of $28.1 million, to $5.0 million in 2011.

Contractual Obligations

We have various commitments primarily related to long-term debt, including capital leases and operating lease commitments related to equipment. We expect to fund these commitments with cash on hand, cash generated from operations and borrowings under our Revolving Credit Facility. The following table provides details regarding our contractual cash obligations as of December 31, 2012:

	Payments Due by Period
	Total		Less Than One Year		1-3 Years		3-5 Years		More Than Five Years
	(In thousands)
Long-term debt obligations (principal and interest)	$	375,790	$	27,513	$	53,189	$	48,062	$	247,026
Long-term obligation to related party(1)		298,179		8,691		20,867		20,501		248,120
Operating lease obligations		47,301		18,438		25,719		2,907		237
Capitalized lease obligations (principal and interest)		10,605		4,753		5,180		672		—
Purchase obligations		4,095		4,095		—		—		—
Total	$	735,970	$	63,490	$	104,955	$	72,142	$	495,383

(1) Long-term obligation to related party is an obligation associated with a financing arrangement with Armstrong Resource Partners. Payments due are estimated based on current mine plans and estimated sales prices of the coal and will be revised as mine plans change. For the foreseeable future, we are deferring the payment of any production royalty amounts due to Armstrong Resource Partners. In consideration for granting the option to defer these payments, we granted to Armstrong Resource Partners the option to acquire an additional undivided interest in certain of our coal reserves in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which we would satisfy payment of any deferred fees by selling part of our interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental regulations. Our anticipated total capital expenditures for 2013 are estimated in a range of

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$35.0 million to $37.0 million, of which approximately 75% represents machinery and equipment purchases and approximately 25% represents mine development related expenditures. Management anticipates funding 2013 capital requirements with current cash balances and cash flows provided by operations. We will continue to have significant capital requirements over the long-term, which may require us to incur debt or seek additional equity capital. The availability and cost of additional capital will depend upon prevailing market conditions and several other factors over which we have limited control, as well as our financial condition and results of operations.

Mine Development Costs

Mine development costs are capitalized until production commences, other than production incidental to the mine development process, and are amortized on a units-of-production method based on the estimated proven and probable reserves. Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels. The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Our estimate of when construction of the mine for economic extraction is substantially complete is based upon a number of assumptions, such as expectations regarding the economic recoverability of reserves, the type of mine under development, and the completion of certain mine requirements, such as ventilation. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

In April 2012, development of the Kronos underground mine was completed with the installation of the third and fourth units, which is estimated to expand annual production capacity to approximately 2.3 million tons. Capitalized development costs totaled $66.4 million, which will be amortized over the life of the mine.

The Lewis Creek underground mine, a two unit underground mine, came out of development in July 2013. Annual saleable production from the mine is estimated to be approximately 1.0 million tons. Capitalized development costs, which will be amortized over the life of the mine, totaled $24.2 million.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as surety bonds and performance bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral. We also post performance bonds to secure our performance of various contractual obligations.

As of June 30, 2013, we had approximately $33.0 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $4.0 million of cash posted as collateral.

Related Party Transactions

We have continuing related party transactions with our affiliate, Armstrong Resource Partners, which principally relate to royalties earned by Armstrong Resource Partners from our leases of certain mineral rights owned or controlled by Armstrong Resource Partners. In addition, we have entered into an Administrative

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Services Agreement with Armstrong Resource Partners and its general partner, pursuant to which we earn a fee for providing certain general administrative and management services to Armstrong Resource Partners.

On March 21, 2013, we agreed to sell an additional 2.59% undivided interest in certain land and mineral reserves to Armstrong Resource Partners. The percentage interest in the land and mineral reserves sold was based an a fair value determined by a third-party specialist. In exchange for the undivided interest in the land and reserves, Armstrong Resource Partners forgave amounts owed by us totaling $4.9 million. As a result of this transaction, which closed on April 1, 2013, Armstrong Resource Partners’ undivided interest in certain of our land and mineral reserves in Muhlenberg and Ohio Counties increased to 53.4%. In addition, the transferred mineral reserves were leased back to us on terms similar to those applicable to the previous transfers. As we will have a continuing involvement in the reserves, the transaction is accounted for as a financing arrangement and an additional long-term obligation to Armstrong Resource Partners of $4.9 million was recognized in the second quarter of 2013. As a result of the additional asset transfer, the effective interest rate on the long-term obligation to Armstrong Resource Partners was reduced to 10.65%.

On June 28, 2013, Thoroughbred, an entity wholly owned by Yorktown, acquired approximately 65 million tons of fee-owned underground coal reserves and approximately 40 million tons of leased underground coal reserves from Peabody. The acquired coal reserves are located in Muhlenberg and McLean Counties of Kentucky, contiguous to our reserves. It is anticipated that these reserves will be leased to us in exchange for a production royalty.

In connection with Thoroughbred’s acquisition of these coal reserves, we loaned Thoroughbred $17.5 million, which was repaid in July 2013. The proceeds of the loan were used to make a portion of the down payment to Peabody for the purchase of the coal reserves.

Please read “Certain Relationships and Related Party Transactions” for additional information concerning related party transactions.

Critical Accounting Policies and Estimates

Our preparation of financial statements in conformity with GAAP requires that we make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. We base our judgments, estimates and assumptions on historical information and other known factors that we deem relevant. Estimates are inherently subjective as significant management judgment is required regarding the assumptions utilized to calculate accounting estimates.

The most significant areas requiring the use of management estimates and assumptions relate to units-of-production amortization calculations, asset retirement obligations, useful lives for depreciation of fixed assets and estimates of fair values for asset impairment purposes. This section describes those accounting policies and estimates that we believe are critical to understanding our historical consolidated financial statements and that we believe will be critical to understanding our consolidated financial statements subsequent to this exchange offer.

Inventory

Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of supplies, primarily spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes labor, equipment operating expenses and certain transportation and operating overhead.

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Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets.

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results. These factors and assumptions relate to geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine; the percentage of coal in the ground ultimately recoverable; historical production from the area compared with production from other producing areas; the assumed effects of regulation and taxes by governmental agencies; and assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Certain account classifications within our financial statements such as depreciation, depletion, and amortization and certain liability calculations such as asset retirement obligations may depend upon estimates of coal reserve quantities and values. Accordingly, when actual coal reserve quantities and values vary significantly from estimates, certain accounting estimates and amounts within our consolidated financial statements may be materially impacted. Coal reserve values are reviewed annually, at a minimum, for consideration in our consolidated financial statements.

Advance Royalties

A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable through a reduction in royalties payable on future production.

Long-Lived Assets

We review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted. Several examples of impairment indicators include a significant decrease in the market price of a long-lived asset; a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset; or a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. The foregoing factors are not all inclusive, and management must continually evaluate whether other factors are present that would indicate a long-lived asset may be impaired. The amount of impairment is measured by the difference between the carrying value and the fair value of the asset. We have not recorded an impairment loss for any of the periods presented.

Asset Retirement Obligation

Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S., as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows,

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discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2012 and for the six months ended June 30, 2013 was $4.0 million and $1.2 million, respectively. See Note 19 to our audited consolidated financial statements for additional details regarding our asset retirement obligations.

Income Taxes

We account for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or the entire deferred tax asset will not be realized. In our evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our evaluation, we may record a change in valuation allowance through income tax expense in the period such determination is made. We believe that the judgments and estimates are reasonable; however, actual results could differ.

Revenue Recognition and Accounts Receivable

Revenues from coal sales are recognized when title passes to the customer as the coal is shipped. Some coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped. In certain cases, a customer’s analysis of the coal quality is binding and the results of the analysis are received on a delayed basis. In these cases, we estimate the amount of the quality adjustment and adjust the estimate to actual when the information is provided by the customer. Historically, such adjustments have not been material.

Our accounts receivable are recorded at the invoiced amount. Our sales are primarily to large utilities that have excellent credit. We evaluate the need for an allowance for doubtful accounts based on anticipated recovery and industry data. If any of our customers were to encounter financial difficulties that restricted their ability to make payments, our estimate of an appropriate allowance for doubtful accounts could change. As of June 30, 2013, December 31, 2012 and 2011, we had not established an allowance for accounts receivable.

Stock-Based Compensation

We account for stock-based compensation in accordance with the authoritative guidance on stock compensation. Under the fair value recognition provisions of this guidance, stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as expense, net of estimated forfeitures, over the requisite service period, which is generally the vesting period of the respective award.

The primary stock-based compensation tool used by us for our employee base is through awards of restricted stock. Restricted stock awards generally cliff vest after two to three years of service. The fair value of restricted stock is equal to the fair market value of our common stock at the date of grant and is amortized to expense ratably over the vesting period, net of forfeitures. Because our common stock is not publicly traded, we must estimate the fair market value based on multiple valuation methods. The valuations of our common stock were determined in accordance with the guidelines outlined in the American Institute of Certified Public Accountants Practice Aid, Valuation of Privately-Held-Company Equity Securities Issued as Compensation by a third-party valuation specialist. The assumptions we use in the valuation model are based on future expectations combined with management judgment. In the absence of a public trading market, our board of directors, with

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input from management, exercised significant judgment and considered numerous objective and subjective factors to determine the fair value of our common stock as of the date of each option grant, including the following factors:

• our operating and financial performance;

• current business conditions and projections;

• the likelihood of achieving a liquidity event for the shares of common stock underlying these restricted stock grants, such as an initial public offering of our common stock or a sale of our company, given prevailing market conditions;

• our stage of development;

• any adjustment necessary to recognize a lack of marketability for our common stock;

• the market performance of comparable publicly traded companies; and

• the U.S. and global capital market conditions.

We granted restricted stock awards with the following grant date fair values between January 1, 2009 and December 31, 2012:

Grant Date	Number of Shares Underlying the Award		Grant-Date Fair Value
January 2010		18,500	$	6.49
August 2010		16,650		5.95
June 2011		83,250		13.93
September 2011		9,250		14.80
December 2012		18,500		12.11

The fair value of our common stock was determined based on multiple valuation methodologies utilizing both quantitative and qualitative factors. Significant factors considered and the valuation methodology used to determine the fair value of our common stock at these grant dates include:

January 2010

In September 2009, we sold 1,387,500 shares of common stock to our majority stockholder at $10.81 per share. As our financial forecast and expected growth rate had not materially changed between September 2009 and January 2010, and the demand for Illinois Basin coal remained strong, we utilized $10.81 as the reasonable undiscounted fair value of our common stock for the restricted stock grant made in January 2010. A third-party specialist determined a non-marketability discount of 40% should be applied due to the unlikely nature of a liquidity event occurring in the near future. Application of the non-marketability discount resulted in an overall fair value of $6.49 per share.

August 2010

Between February 2010 and August 2010, the economic factors impacting our business had not changed significantly, and thus, we assumed the undiscounted fair value of our common stock had remained unchanged at $10.81 per share. A third-party specialist determined that a non-marketability discount of 45% should be applied based on the likelihood of a liquidity event. Application of the non-marketability discount resulted in an overall fair value of $5.95 per share.

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June 2011

Between September 2010 and June 2011, we experienced significant growth in our business due primarily to two additional mines commencing operations. In addition, due to the continued strength in the coal markets during this period, we concluded the likelihood of a liquidity event had increased. In June 2011, we granted restricted stock awards to certain executive and non-executive employees. The undiscounted fair value of our common stock, which totaled $17.41 per share, was determined by a third-party specialist based on both a market approach using the comparable company method and an income approach using the discounted cash flow method. Given a liquidity event was expected to occur within approximately one year, a non-marketability discount of 20% was applied to determine an overall fair value per share. Based on this valuation and the factors discussed above, the third-party specialist determined the overall fair value per share was $13.93.

September 2011

Between July 2011 and September 2011, our outlook on the industry remained positive and we believed the likelihood of a liquidity event was more probable. In September 2011, a non-executive employee was granted a restricted stock award. As our financial forecasts and expectations for growth had not changed significantly from June 2011, a third-party specialist concluded the undiscounted fair value of our common stock had remained unchanged from our previous grant at $17.41 per share. Given a liquidity event was expected to occur within approximately six to nine months, a non-marketability discount of 15% was determined by a third-party specialist and applied to determine an overall fair value per share. Based on this valuation and the factors discussed above, the third-party specialist determined the overall fair value per share was determined to be $14.80.

December 2012

Throughout 2012, the outlook for the coal industry weakened and the probability of a liquidity event declined. In December 2012, a restricted stock award was granted to an executive employee. The undiscounted fair value of our common stock, which totaled $14.25 per share, was determined by a third-party specialist based on both a market approach using the comparable company method and an income approach using the discounted cash flow method. Based on the likelihood of a liquidity event, a non-marketability discount of 15% was applied to determine an overall fair value per share. Based on this valuation and the factors discussed above, the overall fair value per share was determined to be $12.11.

Stock compensation expense totaled $0.7 million, $1.4 million, and $0.1 million for the years ended December 31, 2012, 2011, and 2010, respectively, and $0.3 million and $0.4 million for the six months ended June 30, 2013 and 2012, respectively. Stock compensation expense to be recognized on non-vested restricted stock awards as of June 30, 2013 was approximately $0.2 million.

New Accounting Standards Issued and Adopted

We are an “emerging growth company,” as defined in Section 2(a)(19) of the Securities Act, as modified by the JOBS Act. 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, and delay compliance with new or revised accounting standards until those standards are applicable to private companies. 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.

In February 2013, the Financial Accounting Standards Board (“FASB”) issued an amendment to the accounting guidance for the reporting of amounts reclassified out of accumulated other comprehensive income

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(“AOCI”). The amendment expands the existing disclosure by requiring entities to present information about significant items reclassified out of AOCI by component. In addition, an entity is required to provide information about the effects on net income (loss) of significant amounts reclassified out of each component of AOCI to net income (loss) either on the face of the statement where net income (loss) is presented or as a separate disclosure in the notes of the financial statements. The amendment is effective prospectively for annual or interim reporting periods beginning after December 15, 2012. The adoption of this accounting pronouncement did not have a material impact on our financial statement disclosures.

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 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. 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 was effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not materially affect our consolidated financial statements.

Quantitative and Qualitative Disclosures about Market Risk

We defined market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks are commodity price risk and credit risk.

Commodity Price Risk

We sell most of the coal we produce under multi-year coal supply agreements. Historically, we have principally managed the commodity price risks from our coal sales by entering into multi-year coal supply agreements of varying terms and durations, rather than through the use of derivative instruments. See “Factors that Impact our Business” above for more information about our multi-year coal supply agreements.

Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward purchases to manage a portion of our exposure related to diesel fuel volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have increased net loss by $0.4 million for the six months ended June 30, 2013 and reduced net income by $1.0 million for the year ended December 31, 2012. A hypothetical increase of 10% in steel prices would have increased net loss by $1.0 million for the six months ended June 30, 2013 and reduced net income by $1.5 million for the year ended December 31, 2012. A hypothetical increase of 10% in explosives prices would have increased net loss by $0.8 million for the six months ended June 30, 2013 and reduced net income by $1.6 million for the year ended December 31, 2012.

Credit Risk

In 2012, approximately 99% of our coal sales were made to electric utilities. Therefore, our credit risk is primarily with domestic electric power generators. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into a transaction with the customer and to constantly monitor outstanding accounts receivable against established credit limits. When deemed appropriate, we will take steps to reduce credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. Credit losses are provided for in the financial statements and have historically been minimal.

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Seasonality

Our business has historically experienced some variability in its results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as floods or blizzards, can impact our ability to mine and ship our coal and our customers’ ability to take delivery of coal.

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THE COAL INDUSTRY

Overview

Coal is an abundant natural resource that serves as the primary fuel source for the generation of electric power and as a key ingredient in the production of steel. According to the World Coal Association (“WCA”), approximately 42% of the world’s electricity generation and approximately 60% of global steel production is fueled by coal. Global coal production totaled 8.5 billion tons in 2011 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 1.0 billion tons in 2012, according to the EIA. A majority of this production is used for electric power generation.

The following table sets forth the consumption of coal in the United States by consuming sector by the EIA for the periods indicated:

U.S. Coal Consumption (tons in millions)

	2010		2011		2012
Electric Power		975		929		825
Industrial		49		46		43
Steel Production		21		21		21
Residential/Commercial		3		3		2
Total U.S. Coal Consumption		1,049		999		891

Source: EIA

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 2012, coal-fired power plants produced approximately 37% of all electric power generation, more than any other domestic fuel source. Thermal coal used by electric utilities and other power producers accounted for 870 million tons or 98% of total coal consumption in 2012.

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.

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.

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

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trade exports are expected to grow to 1.1 billion tons by 2018, from 890 million tons in 2012, 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 (35% in 2040).

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.

According to the EIA, the U.S. coal industry produced approximately 1.0 billion tons of coal in 2012, 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.

• Increasing demand for coal produced in the Illinois Basin. We believe the increasing demand for coal produced in the Illinois Basin is due to a combination of factors including:

• Significant expansion of scrubbed coal-fired electricity generating capacity. The EIA forecasts a 22% increase in FGD installed on the coal-fired generation fleet by 2040 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. This represents an increase from 192 gigawatts in 2011 to 235 gigawatts, or 86% of all U.S. coal-fired capacity in the electric sector. The EIA estimates that in 2011, approximately 61% of all U.S. coal-fired generation operating or under construction had FGD technology installed. Illinois Basin coal generally has a higher sulfur content per ton than coal produced in other regions. However, we believe that FGD utilization will enable operators to use the most competitively priced coal (on a delivered cents per million Btu basis) irrespective of sulfur content, and thus lead to a strong increase in demand for Illinois Basin coal.

• Declines in Central Appalachian thermal coal production. Wood Mackenzie forecasts that production of Central Appalachian thermal coal will continue to decline, falling from 84 million tons in 2013 to 49 million tons in 2015, due to reserve depletion, regulatory-driven decreases in surface production and more difficult geological conditions. These factors are expected to result in significantly higher mining costs and prices for Central Appalachian thermal coal. We believe this will lead to an increase in demand for thermal coal from the Illinois Basin due to its comparatively lower delivered cost to the major Eastern U.S. utilities who are currently the principal users of thermal coal from Central Appalachia.

• Growing demand for seaborne thermal coal. Global thermal coal exports are projected to rise from 890 million tons in 2012 to 1.1 billion tons by 2018. We believe that limitations on existing global export coal supply, infrastructure constraints, relative exchange rates, coal quality and cost structure could create significant thermal coal export opportunities for U.S. coal producers, including Illinois Basin coal producers, particularly those similar to us with transportation access to both the Mississippi River and to rail connecting to Louisiana export terminals. In addition, we believe that certain domestic users of U.S. thermal coal will need to seek alternative sources of domestic supply as an increasing amount of domestic coal is sold in global export markets.

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• Stable long-term outlook for U.S.thermal coal market. According to the EIA, coal-fired electricity generation accounted for approximately 37% of all electricity generation in the United States in 2012. 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 2040, at 35% of total generation.

Illinois Basin Coal Market

Our operations are located in the Western Kentucky region of the Illinois Basin and we produce thermal coal for consumption by electricity generators operating scrubbed power plants in the Eastern United States and along the Mississippi River and for international coal consumers who are capable of utilizing our coal. We compete with other producers of similar quality coal in the Illinois Basin, as well as with producers of other thermal coal in other U.S. production regions including the Powder River Basin and Northern, Central and Southern Appalachia.

In 2011, 46.2% of the electricity in our market area was generated by coal-fired power plants. The table below compares the total electricity generation in our market area to that which was coal-fired for 2011.

	2011 Total Electricity Generation GWh		2011 Coal-Fired Electricity Generation
			GWh		Percent of Total
Total-Our Primary Market Area(1)		2,688,136		1,241,671		46.2	%
Total United States		4,100,656		1,733,430		42.3	%

(1) Any state east of the Mississippi River, as well as Minnesota, Iowa, Missouri, Arkansas and Louisiana.

Source: EIA

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, continuing to benefit producers of coal from the Illinois Basin.

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 D.C. Circuit issued a ruling to stay the CSAPR pending judicial review. On January 24, 2013, the D.C. Circuit denied the EPA’s petition for rehearing, and on March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit’s decision on the CSAPR. The CAIR remains in place pending such ruling. 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 rule published in February 2012, which regulates the emission of mercury and other toxic air pollutants.

To comply with the expected tightening of emissions limitations, operators of coal-fired electricity generation have increasingly invested in FGD, selective and non-selective catalytic reduction systems and other advanced control technologies at their large, base load power plants. In 2011, 192 gigawatts of the 314 gigawatts (61%) of U.S. coal-fired generation was equipped with FGD emissions systems. The EIA projects that with the

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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 FGD generation capacity to approximately 86% of all U.S. capacity in the electric sector capacity by 2040.

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 2012 through 2016. The scrubbed generation unit additions are expected to impact 112 million tons of coal consumption at these units during that period, which we believe will 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

	2012		2013		2014		2015		2016
U.S. Coal-Fired Capacity Adding Scrubbing Equipment (MW)		10,343		9,013		5,715		8,965		3,425
Coal Tons Affected (Mst)		33		29		18		29		11

Source: Wood Mackenzie, September 2013

Long-Term U.S. Thermal Coal Outlook

The following table provides Wood Mackenzie’s long-term outlook for the U.S. thermal coal market. Wood Mackenzie forecasts that coal used for electricity generation will grow from 894 million tons in 2013 to 945 million tons in 2020. Importantly, Illinois Basin coal production is expected to grow rapidly during this period, from 131 million tons to 203 million tons, a 6% compound annual growth rate. Conversely, Wood Mackenzie estimates that Central Appalachian thermal coal production will decline from 84 million tons in 2013 to 35 million tons in 2020.

	2013			2014			2015		2020		2030
Supply (Mst)
Powder River Basin		448			470			441		479		540
Central Appalachia		84			78			49		35		28
Illinois Basin		131			143			153		203		239
Northern Appalachia		120			125			127		114		109
Metallurgical		78			75			75		70		77
Imports		4			5			3		2		2
Other (including Refuse or Petcoke)		189			201			200		242		245
		1,055			1,097			1,047		1,145		1,241
Demand (Mst)
Electricity Generation		894			932			878		945		799
Industrial		49			52			52		53		54
Thermal Export		55			48			42		77		310
Metallurgical Demand		78			75			75		70		77
Stockpile Decrease		(22	)		(10	)		—		—		—
		1,055			1,097			1,047		1,145		1,241

Source: Wood Mackenzie Long Term US Thermal Coal Market Outlook, May 2013

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Global Thermal Coal Markets

Global coal production accounted for 30% of global primary energy consumption in 2012, according to BP.

Source: BP Statistical Review of World Energy, June 2013

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 2012, China and India accounted for 35% of world thermal coal imports.

The Australian Bureau of Resources and Energy Economics (BREE) projects world thermal coal imports will grow to 1.2 billion tons in 2018, with China and India accounting for more than 487 million tons of import demand, up from 343 million tons in 2012.

All other markets’ thermal coal imports are projected to rise from 631 million tons in 2012 to 671 million tons by 2018.

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

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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 isgenerally 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

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the coal, thereby making it more expensive to transport. Moisture content in coal, on an as-sold basis, can range from approximately 2% to over 15% of the 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.

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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 149 million tons in 2012. 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. We currently do not, nor do we plan to in the near future, produce coal using longwall mining techniques.

Surface Mining

Surface mining produces the majority of U.S. coal output, accounting for approximately 68% of U.S. production in 2011. Surface mining is generally used when coal is found relatively close to the surface, when

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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.

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BUSINESS

Overview

About the Company

We are a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin, with both surface and underground mines. We market our coal primarily to proximate and investment grade electric utility companies as fuel for their steam-powered generators. Based on 2012 production, we are the fifth largest producer in the Illinois Basin and the second largest in Western Kentucky. We were formed in 2006 to acquire and develop a large coal reserve holding. We commenced production in the second quarter of 2008 and currently operate seven mines, including four surface and three underground, and are seeking permits for three additional mines. We control approximately 322 million tons of proven and probable coal reserves. We also own and operate three coal processing plants which support our mining operations. From our reserves, we mine coal from multiple seams that, in combination with our coal processing facilities, enhance our ability to meet customer requirements for blends of coal with different characteristics. The locations of our coal reserves and operations, adjacent to the Green River, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling, and provide our customers with rail, barge and truck transportation options.

We are majority-owned by Yorktown. After giving effect to this exchange offer, we will continue to be majority-owned by Yorktown. In addition, Yorktown is represented on our board by Bryan H. Lawrence, founder and principal of Yorktown Partners LLC. As a result, Yorktown has, and can be expected to have, a significant influence in our operations, in the outcome of stockholder voting concerning the election of directors, the adoption or amendment of provisions in our charter and bylaws, the approval of mergers, and other significant corporate transactions.

Our revenue has increased from zero in 2007 to $382.1 million in the year ended December 31, 2012 and our net loss and Adjusted EBITDA for the year ended December 31, 2012 totaled $18.0 million and $50.9 million, respectively.

For the year ended December 31, 2012, we produced 8.8 million tons of coal. As of August 31, 2013, we are contractually committed to sell 9.2 million tons of coal in 2013 and 8.2 million tons of coal in 2014, which represent 98% and 84% of our expected total coal sales in 2013 and 2014, respectively.

Our Business Strategy

Maintain safe mining operations and comply with environmental standards. We consider safety to be our greatest operational priority. We have won numerous awards for our safety record since 2008 recognizing our low injury and incident rates. We intend to maintain programs and policies designed to enable us to remain among the safest coal operators in the industry. We also intend to continue to implement responsible, effective environmental practices throughout our operations and reclamation activities.

Increase and diversify coal sales to utilities with base load scrubbed power plants in our primary market area and pursue export opportunities. We expect that the demand for Illinois Basin coal will rise as a result of an increase in power plants being retrofitted with FGD units, or scrubbers. We intend to continue to focus our marketing efforts principally on power plants in the Mid-Atlantic, Southeastern and Midwestern states that we expect will become consumers of Illinois Basin coal and to seek to diversify our customer base through a combination of multi-year coal supply agreements and sales in the spot market. As of August 31, 2013, we are contractually committed to sell 9.2 million tons of coal in 2013 and 8.2 million tons of coal in 2014, which represent 98% and 84% of our expected total coal sales in 2013 and 2014, respectively. In addition, we believe that the relative heat, ash, sulfur content and cost of our coal, combined with the accessibility of our coal mines and coal processing facilities to the Mississippi River and to rail connecting to Louisiana export terminals, will provide opportunities to export our coal to overseas customers.

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Continue to grow our production opportunistically. We intend to continue to increase our coal production opportunistically in the coming years as the market environment allows and commensurate with our ability to secure supply agreements in support of this growth. We also intend to continue to make opportunistic contiguous reserve acquisitions in amounts approximately consistent with our acquisition experience. We believe our disciplined growth will be supported by an increasing demand for Illinois Basin coal. We will seek to support production growth by executing mining plans for our existing undeveloped reserves and by opportunistically acquiring additional coal reserves that are located near our current mining operations or otherwise offer the potential for efficient and economical development of low-cost production to serve our primary market area.

Maximize profitability by maintaining low-cost mining operations. We operate our mines in a manner aimed at keeping our product quality high while maintaining low production costs. We seek to maximize our coal production and control our costs by continuing to improve our operating efficiency. Our efficiency is, in part, a function of the overburden ratios (the amount of surface material needed to be removed to extract coal) that exist at our surface coal mines. Our efficiency is also enhanced by our fleet of mobile mining equipment, substantially all of which is new, our use of what we believe to be the only draglines in Kentucky, our utilization of river coal movement, our information technology systems and our coordinated equipment utilization and maintenance management functions. We also believe that our highly experienced operating management and well-trained workforce will continue to help in identifying and implementing cost containment initiatives, such as near-term operating synergies from any potential future reserve acquisitions.

Our Reorganization

In August 2011, Armstrong Resources Holdings, LLC merged with and into Armstrong Energy, Inc., which subsequently changed its name to Armstrong Energy Holdings, Inc. Subsequently, Armstrong Land Company, LLC was converted to a C-corporation and changed its name to Armstrong Energy, Inc. effective October 1, 2011 (the “Reorganization”). In connection with the Reorganization, each owner of Armstrong Land Company, LLC received 9.25 shares of Armstrong Energy, Inc. common stock for each unit held.

Our Operational History

Since 2006, we have acquired a substantial portion of our coal reserves, surface properties, mining rights and other assets through a series of transactions including the following:

Date	Principal Assets Acquired	Purchase Price
September 2006	Surface properties and mineral reserves (both fee and leasehold) in Ohio and Muhlenberg Counties, Kentucky, including certain of the Ken and Rockport reserves.(1)	$25.5 million
December 2006	Approximately 9,500 acres of surface property and mineral reserves (both fee and leasehold), including certain of the Equality Boot and Parkway reserves.(1)	$41.0 million
March 2007	Properties and mineral reserves (both fee and leasehold) in Ohio and Muhlenberg Counties, Kentucky, including certain of the West Fork, Midway, Paradise and Vogue reserves.(1)	$46.5 million
May 2007	Surface properties and mineral reserves (both fee and leasehold) in Ohio and Muhlenberg Counties, Kentucky, including certain of the Sunnyside, Lewis Creek and East Fork reserves, and the idled Big Run mine.(1)	$49.6 million
March 2008	Elk Creek Reserves.(2)	$75.6 million
December 2011	Properties and mineral reserves (both fee and leasehold) in Muhlenberg County, Kentucky.	$13.3 million
December 2011	#9 seam coal reserves in Union County, Kentucky (both fee and leasehold interests).	$ 9.0 million

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(1) Since 2011, the fee-owned portions of these reserves have been subject to transfer to Armstrong Resource Partners, our affiliate, pursuant to the Royalty Deferment and Option Agreement. As of June 30, 2013, Armstrong Resource Partners has a 53.4% undivided interest in such reserves, and we have a 46.6% undivided interest in such reserves. See “Certain Relationships and Related Transactions—Royalty Deferment and Option Agreement” and “—About Armstrong Resource Partners.”

(2) Acquired a leasehold interest with Armstrong Resource Partners.

These acquisitions were funded through aggregate payments of approximately $82.7 million and promissory notes with an aggregate principal amount of approximately $177.8 million, which have subsequently been repaid.

In October 2010, we entered into a lease that gives us the right to mine the substantial underground coal reserves located in Union and Webster Counties, Kentucky (the “Union/Webster Counties” reserves). The Union/Webster Counties reserves contain approximately 127 million tons of clean recoverable reserves. The lease requires us to pay minimum annual advance royalties in the form of 16,000 tons, recoupable against earned royalties up to $500,000 per calendar year. The lease also provides for a 6.0% earned royalty rate that may also be satisfied by the delivery of coal at the election of the lessor. We are obligated to meet certain due diligence requirements or pay additional advance royalties prior to the commencement of mining.

In 2009 and 2010, we borrowed an aggregate principal amount of $44.1 million from Armstrong Resource Partners, and the proceeds of those loans were used to satisfy various installment payments required by the promissory notes referred to above. Under the terms of these borrowings, Armstrong Resource Partners had the option to acquire interests in coal reserves then held by Armstrong Energy in Muhlenberg and Ohio Counties in satisfaction of the loans it had made to Armstrong Energy. On February 9, 2011, Armstrong Resource Partners exercised this option. In connection with that exercise, Armstrong Resource Partners paid Armstrong Energy an additional $5.0 million in cash and agreed to offset $12.0 million in accrued advance royalty payments owed by Armstrong Energy to Armstrong Resource Partners, relating to the lease of the Elk Creek Reserves, to acquire an additional partial undivided interest in certain of the coal reserves held by Armstrong Energy in Muhlenberg and Ohio Counties at fair market value. Through these transactions, Armstrong Resource Partners acquired a 39.45% undivided interest as a joint tenant in common with Armstrong Energy in the majority of our coal reserves, excluding the Union/Webster Counties reserves. The aggregate amount paid by Armstrong Resource Partners to acquire its interest in these reserves was the equivalent of approximately $69.5 million.

In December 2011, we entered into a series of transactions with Peabody, pursuant to which we acquired additional property near our existing and planned mines containing an estimated total of 7.7 million clean recoverable tons of coal and entered into leases for an estimated 14 million clean recoverable tons. In addition we entered into a joint venture relating to coal reserves near our Parkway mine. In connection with the joint venture, Peabody agreed to contribute an aggregate of approximately 25 million tons of clean recoverable coal reserves located in Muhlenberg County, Kentucky, and we agreed to contribute mining assets to the joint venture. In July 2013, we and Peabody terminated the joint venture. Concurrent with termination of the joint venture, we agreed to lease from Peabody the coal reserves that Peabody was to contribute to the joint venture.

We and Peabody entered into an Asset Purchase Agreement in December 2011 pursuant to which we acquired from Peabody its rights and interests in certain owned and leased coal reserves located in Muhlenberg County, Kentucky, in exchange for (i) a cash payment by us of approximately $8.9 million, (ii) a promissory note in the aggregate principal amount of approximately $4.4 million, and (iii) an overriding royalty to Peabody to the extent we mine in excess of certain tonnages from the property as set forth in the Asset Purchase Agreement. The overriding royalty due to Peabody was amended in July 2013.

In December 2011, we and Midwest Coal Reserves of Kentucky, LLC, an affiliate of Peabody (“Midwest Coal”), entered into a Contract to Sell and Lease Real Estate pursuant to which we acquired from Midwest Coal its right, title and interest in and to the #9 seam coal reserves in Union County, Kentucky. In addition, Midwest Coal agreed to lease to us approximately 2,000 acres of #9 seam of coal. In consideration of the sale and lease of

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real property, we agreed to deliver (i) approximately $6.0 million in cash, (ii) a promissory note in the aggregate principal amount of approximately $3.0 million, and (iii) an overriding royalty of 2% of the gross selling price on each ton of coal produced and sold from the coal reserves that were purchased (thus excluding the leased coal).

In December 2011, Armstrong Resource Partners sold 200,000 Series A convertible preferred units of limited partner interest to Yorktown in exchange for $20.0 million. Also in December 2011, we entered into a Membership Interest Purchase Agreement with Armstrong Resource Partners pursuant to which we agreed to sell to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by us. In exchange for our agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners paid us $20.0 million. In addition to the cash paid, certain amounts due by us to Armstrong Resource Partners totaling $5.7 million were forgiven by Armstrong Resource Partners, which resulted in aggregate consideration of $25.7 million. This transaction, which closed in March 2012, resulted in the transfer by us of an 11.36% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease. We used the cash proceeds of this transaction to fund the Muhlenberg County and Ohio County reserve acquisitions described above.

In addition, on April 1, 2013, we transferred an additional 2.59% undivided interest in certain land and mineral reserves to Armstrong Resource Partners. In exchange for the undivided interest in the land and mineral reserves, Armstrong Resource Partners forgave amounts owed by us totaling approximately $4.9 million. As a result of this transaction, Armstrong Resource Partners’ undivided interest in certain of our land and mineral reserves in Muhlenberg and Ohio Counties increased to 53.4%. In addition, on April 1, 2013, the transferred mineral reserves were leased back to us on terms similar to those applicable to the previous transfers.

Corporate Structure

The following chart shows a summary of the corporate structure of Armstrong Energy, Inc. and certain of its relationships.

(1) A portion of our reserves are controlled jointly by our affiliate, Armstrong Resource Partners (with a 53.4% undivided interest as of June 30, 2013), and Armstrong Energy (with a 46.6% undivided interest as of

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June 30, 2013) and certain of our remaining reserves are owned solely by Armstrong Resource Partners, with whom we have a long-term leasehold interest. See “—About Armstrong Resource Partners” and “Certain Relationships and Related Party Transactions—Lease Agreements.” These reserves include the Kronos and Lewis Creek underground mines.

About Armstrong Resource Partners

Armstrong Resource Partners was formed in 2008 to engage in the business of management and leasing of coal properties and collection of royalties in the Western Kentucky region of the Illinois Basin. Armstrong Energy holds a 0.4% equity interest in Armstrong Resource Partners through a wholly-owned subsidiary, Elk Creek GP, which is the general partner of Armstrong Resource Partners. The outstanding limited partnership interests (“common units”) of Armstrong Resource Partners, representing 97.8% of its equity interests, are owned by Yorktown. Yorktown is entitled to 97.8% of all distributions made by Armstrong Resource Partners. Armstrong Energy is also majority-owned by Yorktown.

Pursuant to the ARP LPA, Elk Creek GP has the exclusive authority to conduct, direct and manage all activities of Armstrong Resource Partners. Pursuant to the ARP LPA, effective October 1, 2011, Yorktown unilaterally may remove Elk Creek GP as general partner in some circumstances. As a result, beginning October 1, 2011, Armstrong Energy no longer consolidates the results of Armstrong Resource Partners in the financial statements of Armstrong Energy.

In 2009 and 2010, Armstrong Energy borrowed an aggregate principal amount of $44.1 million from Armstrong Resource Partners, and the proceeds of those loans were used to satisfy various installment payments required by the promissory notes that were delivered in connection with the acquisition of our coal reserves. Under the terms of these borrowings, Armstrong Resource Partners had the option to acquire interests in coal reserves then held by Armstrong Energy in Muhlenberg and Ohio Counties in satisfaction of the loans it had made to Armstrong Energy. On February 9, 2011, Armstrong Resource Partners exercised this option. In connection with that exercise, Armstrong Resource Partners paid Armstrong Energy an additional $5.0 million in cash and agreed to offset $12.0 million in accrued advance royalty payments owed by Armstrong Energy to Armstrong Resource Partners, relating to the lease of the Elk Creek Reserves, to acquire an additional partial undivided interest in certain of the coal reserves held by Armstrong Energy in Muhlenberg and Ohio Counties at fair market value. Through these transactions, Armstrong Resource Partners acquired a 39.45% undivided interest as a joint tenant in common with Armstrong Energy in the majority of our coal reserves, excluding the Union/Webster Counties reserves. The aggregate amount paid by Armstrong Resource Partners to acquire its interest in these reserves was the equivalent of approximately $69.5 million.

On February 9, 2011, Armstrong Energy entered into lease agreements with Armstrong Resource Partners pursuant to which Armstrong Resource Partners granted Armstrong Energy leases to its 39.45% undivided interest in the mining properties described above and licenses to mine coal on those properties. The initial term of each such agreement is ten years, and will automatically extend for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or such agreement is terminated upon proper notice. Armstrong Energy is obligated to pay Armstrong Resource Partners a production royalty equal to 7% of the sales price of the coal which Armstrong Energy mines from the properties. Under the terms of these agreements, Armstrong Resource Partners retains the surface rights to use the properties containing these reserves for non-mining purposes. Events of default under the lease agreements include the failure by Armstrong Energy to pay royalty payments to Armstrong Resource Partners when due and a default by Armstrong Energy under any agreement, indenture or other obligation to any creditor that, in the opinion of Armstrong Resource Partners, may have a material adverse effect on Armstrong 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 Armstrong Resource Partners can terminate one or more of the lease agreements. In addition, Armstrong Energy has agreed to indemnify Armstrong Resource Partners from and against any and all claims, damages, demands, expenses, fines, liabilities, taxes and any other losses related in any way to Armstrong

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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.

The aforementioned lease transaction has been accounted for as a financing arrangement due to our continuing involvement in the land and mineral reserves transferred.This has resulted in the recognition of an initial obligation of $69.5 million by Armstrong Energy, which represents the fair value of the assets transferred. As the financial results of Armstrong Resource Partners historically have been consolidated, this transaction did not impact our results of operations or financial condition through September 30, 2011. As noted above, the financial results of Armstrong Resource Partners were deconsolidated from Armstrong Energy effective October 1, 2011. Subsequently, the long-term obligation is reflected on our balance sheet and will continue to beamortized through 2034, the estimated mine life of the reserves, at an annual rate of 7% of the estimated gross revenue generated from the sale of the coal originating from the leased mineral reserves. As of June 30, 2013, the outstanding principal balance of the long-term obligations to Armstrong Resource Partners was $104.9 million.

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

On February 9, 2011, Armstrong Resource Partners also entered into a lease and sublease agreement with Armstrong Energy relating to our Elk Creek Reserves and granted Armstrong Energy a license to mine coal on those properties. The terms of this agreement mirror those of the lease agreements described above. Armstrong Energy has paid $12.0 million of advance royalties under the lease, of which $1.7 million, as of June 30, 2013, is recoupable against future production royalties.

In December 2011, we entered into a Membership Interest Purchase Agreement with Armstrong Resource Partners pursuant to which we agreed to sell to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by us. In exchange for our agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners paid us $20.0 million. In addition to the cash paid, certain amounts due from us to Armstrong Resource Partners totaling $5.7 million were forgiven by Armstrong Resource Partners, which resulted in aggregate consideration of $25.7 million. This transaction, which closed in March 2012, resulted in the transfer by us of an 11.36% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease. As a result of this transaction, as of December 31, 2012, of our total reserves of 322 million tons, 62 million tons (19.2%) are owned 100% by Armstrong Resource Partners, and 121 million tons (37.5%) were held by Armstrong Energy and Armstrong Resource Partners as joint tenants in common with 49.19% and 50.81% interests, respectively. On April 1, 2013, Armstrong Energy transferred a 2.59% undivided interest in certain of its land and mineral reserves to Armstrong Resource Partners in exchange for aggregate consideration of $4.9 million. This increased Armstrong Resource Partners’ interest in certain properties of Armstrong Energy to 53.4%. See “Business—Our Operational History.”

Our Mining Operations

We currently operate seven active mines, all of which are located in the Illinois Basin coal region in western Kentucky. Our operations are comprised of four surface mines and three underground mines, and we have three preparation plants serving these operations. In 2012, approximately 60% of the coal that we produced came from our surface mining operations. In addition, we are seeking permits for three additional mines.

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

The following tables provide a summary of information regarding our active mines as of December 31, 2012.

			Clean Recoverable Coal (Proven and Probable Reserves)(1)							Production						Quality Specifications   (As Received)(2)
Mines (Commenced Operations)	Mining Method(3)		Proven Reserves		Probable Reserves		Total			Year Ended December 31, 2012			Six Months Ended June 30, 2013			Heat Value (Btu/ Lb)		SO2 Content (Lbs/ MMBtu)
	(Tons in thousands)
Active mines
Midway (July 2008)		S		16,440		2,122		18,562	(4)		1,518			697			11,112		4.6
Parkway (April 2009)		U		6,933		4,747		11,680			1,558			729			11,925		4.3
East Fork (June 2009)(5)		S		2,604		543		3,147	(4)		41			—			11,078		7.8
Equality Boot (September 2010)		S		19,656		826		20,482	(6)		2,868			1,327			11,401		5.6
Lewis Creek (June 2011)		S		5,140		97		5,237	(4)		942			446			11,198		4.9
Kronos (September 2011)		U		16,775		2,395		19,170	(7)		1,842			1,313			11,793		4.5
Lewis Creek (March 2013)		U		18,676		2,666		21,342	(7)		—			165			11,793		4.5
Total active mines				86,224		13,396		99,620			8,769	(8)		4,677	(9)
Additional reserves
Ken		S		17,166		3,854		21,020	(4)		—			—			11,809		5.0
Union/Webster		U		47,281		80,187		127,468			—			—			12,435		4.4
Other		S/U		58,807		14,681		73,488	(10)		—			—			11,688		5.1
Total additional reserves				123,254		98,722		221,976			—			—
Total				209,478		112,118		321,596			8,769	(8)		4,677	(9)
Other inferred recoverable resources(11)								104,356

(1) As of December 31, 2012. For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.

(2) Quality specifications displayed on an “as received” basis. If derived from multiple seams, data represents an average.

(3) U = Underground; S = Surface.

(4) Of these reserves, 50.81% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2012.

(5) Warden and Kronos pits. Production at the Kronos pit ceased in August 2011 and the Warden pit was temporarily idled in March 2012.

(6) Of these reserves, 50.81% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2012. Includes approximately 0.3 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.

(7) Based on internal estimates, recoverable reserves are split among the three mines that comprise the Elk Creek Reserves.

(8) Of this amount, 76 tons and 31 tons of production from the Kronos and Lewis Creek underground mines, respectively, was capitalized because they were in the developmental phase.

(9) Of this amount, 156 tons and 28 tons of production from the Lewis Creek underground and surface mines, respectively, was capitalized because they were in the developmental phase.

(10) Of these reserves, excluding an estimated 21.3 million tons of Elk Creek Reserves, 50.81% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2012. Includes approximately 1.9 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.

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(11) Other inferred resources includes tonnage for which tonnage, grade and mineral content can be estimated with a low level of confidence. It is inferred from geological evidence and assumed but not verified geological/or grade continuity. Inferred resources are computed by projecting data from available seam measurements to distances beyond those used for the probable classification. These numbers are based on information gathered through appropriate techniques from location such as outcrops, trenches, pits, workings and drill holes which may be of limited or uncertain quality and reliability.

	Clean Recoverable Tons (Proven     and Probable Reserves)(1)
	Owned		Leased		Total			Primary Transportation Method
	(In thousands)
Active Mines (Commenced Operations)
Midway (July 2008)		18,562		—		18,561	(2)	Rail, barge & truck
Parkway (April 2009)		1,292		10,388		11,680		Truck
East Fork (June 2009)(3)		2,648		499		3,147	(2)	Rail, barge & truck
Equality Boot (September 2010)		20,482		—		20,482	(4)	Barge
Lewis Creek (surface) (June 2011)		5,237		—		5,237	(2)	Rail, barge & truck
Kronos (September 2011)		18,091		1,079		19,170	(5)	Rail, barge & truck
Lewis Creek (underground) (March 2013)		20,141		1,201		21,342	(5)	Rail, barge & truck
Total active mines		86,453		13,167		99,620

(1) For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.

(2) Of these reserves, 50.81% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners as of December 31, 2012.

(3) Warden and Kronos pits. Production at the Kronos pit ceased in August 2011 and the Warden pit was temporarily idled in March 2012.

(4) Of these reserves, 50.81% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2012. Includes approximately 0.3 million tons related to reserves for which we own or lease a 50% or more partial joint interest and royalties on extractions may be payable to other owners.

(5) Based on internal estimates, recoverable reserves are split among the Elk Creek Reserves.

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The following map shows the locations of our mining operations and coal reserves:

In general, we have developed our mines and preparation plants at strategic locations in close proximity to rail or barge shipping facilities. Coal is transported from our mines to customers by means of railroads, trucks, and barge lines. We currently own or lease under long-term arrangements a substantial portion of the equipment utilized in our mining operations. We employ sophisticated preventative maintenance and rebuild programs and upgrade our equipment to ensure that it is productive, well-maintained and cost-competitive. Our maintenance programs also employ procedures designed to enhance the efficiencies of our operations.

We control approximately 322 million tons of coal available for production at our active and proposed mines in Ohio and Muhlenberg counties in Western Kentucky, of which we lease approximately 156 million tons from various unaffiliated landowners.

Armstrong Coal, our wholly-owned subsidiary, has entered into leases with Western Mineral Development, LLC (“Western Mineral”), Western Land and Western Diamond, each of which is our wholly-owned subsidiary, for the reserves described above, excluding the Elk Creek Reserves. Those leases are for a term of ten years but can be renewed for an additional 10-year term or until all of the mineable and merchantable coal has been mined. The leases provide for a 7% production royalty payment to be paid by Armstrong Coal to the lessors.

Effective February 9, 2011, Armstrong Coal, Western Diamond and Western Land entered into a Royalty Deferment and Option Agreement with Western Mineral. Pursuant to this agreement, Western Mineral agreed to grant to Armstrong Coal and its affiliates the option to defer payment of Western 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 Coal and its affiliates granted to Western Mineral the option to acquire an additional partial undivided interest in certain of the coal reserves held by Armstrong Energy, Inc. in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which Armstrong

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Coal and its affiliates would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.

On October 11, 2011, Western Diamond and Western Land (together, the “Sellers”) entered into an agreement with Western Mineral pursuant to which the Sellers agreed to sell an additional partial undivided interest in substantially all of the coal reserves and real property owned by the Sellers previously subject to the options exercised by Armstrong Resource Partners on February 9, 2011 (see “Certain Relationships and Related Party Transactions—Sale of Coal Reserves”), other than any of Sellers’ real property and related mining rights associated with the Parkway mine.

We also lease the Elk Creek Reserves from Armstrong Resource Partners, and the terms of that lease mirror the leases described above. The lease with Armstrong Resource Partners also recognizes and permits us to recoup a pre-existing advance royalty balance of $12.0 million against production royalties as they come due.

Approximately 127 million tons of recoverable coal are located in the Union/Webster Counties reserves. We have entered into a lease with a non-affiliated third party for such reserves, which requires us to pay minimum annual advance royalties in the form of 16,000 tons, recoupable against earned royalties up to $500,000 per calendar year. The lease also provides for a 6% earned royalty rate that may also be satisfied by the delivery of coal at the election of lessor. We are also obligated to meet certain due diligence requirements or pay additional advance royalties prior to the commencement of mining.

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 averaged approximately 12.7-to-1 in 2012. The Midway mine produced approximately 1.5 million tons of clean coal in 2012 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 18.6 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 the Parkway mine. 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 1.6 million tons of clean coal in 2012. As of December 31, 2012, the Parkway mine currently had approximately 11.7 million tons of proven and probable reserves. 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 41,000 tons of clean coal in 2012, and there were approximately 3.1 million tons of proven and probable reserves at the East Fork mine at December 31, 2012. Production at the Kronos pit ceased in August 2011 and production at the Warden pit was temporarily idled in March 2012.

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

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thermal coal from the West Kentucky #14, #13, #12 and #11 seams and produced approximately 2.9 million tons of coal in 2012. 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 11.3-to-1 in 2012. The Equality Boot mine had approximately 20.5 million tons of proven and probable reserves as of December 31, 2012. 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 five miles to the Armstrong Dock Preparation Plant where it is unloaded, processed, reloaded onto barges and then shipped to 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 commencedin June 2011 at the Lewis Creek mine, and thermal coal is being mined from the West Kentucky seams #13A and #13. Lewis Creek produced approximately 0.8 million tons of clean coal in 2012. 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 the Lewis Creek mine. As of December 31, 2012, there were approximately 5.2 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 extracts thermal coal from the WestKentucky #9 seam. The Kronos mine produced approximately 1.8 million clean tons of coal in 2012. The mine

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utilizes four continuous miner super sections and there were approximately 19.2 million tons of proven andprobable reserves at the Kronos mine as of December 31, 2012. Coal mined at Kronos is transported by truck tothe Midway Preparation Plan and by conveyor to the Armstrong Dock Preparation Plant for processing and delivery.

Lewis Creek Underground Mine.The Lewis Creek underground mine, which came out of development in July 2013, produces coal from the West Kentucky #9 seam utilizing two continuous miner super sections operating concurrently. We estimate that the saleable production from the Lewis Creek underground mine will be approximately 1.0 million tons annually. As of December 31, 2012, there are approximately 21.3 million tons of proven and probable reserves at the Lewis Creek reserves.

Future Mines. We expect to open additional mines in 2015 and 2016. We continue to evaluate our plans for the expansion and extension of existing mines and the development of future mines.

Our Coal Preparation Facilities

The majority of coal from each of our mining operations is processed at a coal preparation plant located near the mine or connected to the mine by an overland conveyor system. Currently, we have three preparation plants, Midway, Parkway and Armstrong Dock. These coal preparation plants allow us to treat the coal we extract from our mines to ensure a consistent quality and to enhance its suitability for particular end-users. In 2012, our preparation plants processed approximately 96% of the raw coal we produced. In addition, depending on coal quality and customer requirements, we may blend coal mined from different locations in order to achieve a more suitable product. At the current time, our preparation plants do not process coal from other companies, and we do not have any present intention to do so.

The following chart provides information regarding our preparation plants:

	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:	1,200	400	1,200
Loadout Tons Per Hour:	2,500 (Rail)	—	2,500 (Barge)
Transportation:	Rail, Truck	Truck	Barge

Our Midway Plant is 1,200 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.

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

The Armstrong Dock Plant is a 1,200 TPH raw coal feed, heavy media preparation plant that was constructed in 2008. The plant is connected to a newly-refurbished 10,000 ton “donut” storage stockpile and an extensive conveyor handling system. The Armstrong Dock Plant has a coal handling system that permits the loading of coal into barges adjacent to the dock conveyor or into trucks adjacent to the plant itself.

The treatments we employ at our preparation plants depend on the size of the raw coal. For coarse material, the separation process relies on the difference in the density between coal and waste rock where, for the very fine

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

Sales and Marketing

Our sales and marketing functions are handled from our St. Louis, Missouri headquarters with assistance from our Madisonville, Kentucky operations center. Prior to 2011, the majority of our coal sales were made through the use of third-party independent contractors who were paid a per-ton commission with respect to the coal they brokered for sale. Commencing in 2011, the majority of our new coal sales have been made through our in-house Director of Coal Sales, and no new commissions are paid with respect to coal sold by our employees.

Multi-year Coal Supply Agreements

As is customary in the coal industry, we enter into multi-year coal supply agreements with many of our customers. Multi-year coal supply agreements usually have specific and possibly different volume and pricing arrangements for each year of the agreement. These agreements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In 2012, we sold approximately 95% of our coal under multi-year coal supply agreements. The majority of our multi-year coal supply agreements include a fixed price for the term of the agreement or a pre-determined escalation in price for each year. Some of our multi-year coal supply agreements may include a variable pricing system. At June 30, 2013, we had multi-year coal supply agreements with remaining terms ranging from one to six years.

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

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

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

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

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Customers

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

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Our primary customers are electric utilities. We may also sell coal to industrial companies, brokers and other coal producers. For the year ended December 31, 2012 and the six months ended June 30, 2013, approximately 99% and 99%, respectively, of our coal revenues related to sales to electric utilities. The majority of our electric utility customers purchase coal for terms of one to six years, but we also supply coal on a spot basis for some of our customers.

In 2012, we sold coal to 11 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 six months ended June 30, 2013, we derived approximately 42% and 37% of our total coal revenues from sales to LGE and TVA, respectively.

We currently have four multi-year coal supply agreements with LGE for the sale of coal. The first agreement was entered into in 2008 and expires in 2016. As amended, the agreement calls for 2.1 million tons annually through 2015 and 0.9 million tons in 2016. Pricing ranges from $28.35 to $30.25 per ton over the remaining 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 an annual delivery of 1.25 million tons in 2013 and 0.75 million tons from 2014 through 2016. In addition to typical quality adjustments, the price is $45.00 per ton in 2013. The agreement 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. Notice has been given to reopen the agreement and if the parties are unable to reach a mutually acceptable agreement as to those terms being renegotiated, the agreement will terminate as of December 31, 2013. The third agreement with LGE was entered into in 2012. It calls for 0.5 million tons in 2013 and 1.0 million tons from 2014 through 2015. Prices range from $46.00 to $49.00 per ton over the term of the agreement, subject to certain quality related adjustments. There is no price reopener provision in this agreement. The fourth agreement, entered into in 2013, calls for delivery of 0.8 million tons in 2014, 0.85 million tons in 2015 and 1.0 million tons in 2016 and 2017. Prices range from $44.25 to $48.90 during the term of the agreement. There are no price reopener provisions in this agreement.

Pursuant to the LGE multi-year coal supply agreements, we may be entitled to certain price or other adjustments if there is a change in certain governmental impositions which increases our cost to provide coal under the LGE multi-year coal supply agreements. In connection with a November 2011 MSHA (the “2011 MSHA Order”) order that increased our cost to provide coal, in August 2013, we entered into a settlement agreement and release with LGE. Pursuant to the settlement agreement and release, LGE paid us approximately $2.5 million for increased costs incurred by us between November 2011 and June 30, 2013 as a result of the 2011 MSHA Order. In addition, the parties agreed that for coal provided on or after July 1, 2013, we would bill LGE an additional amount of $0.87 per ton for tons shipped from our Equality Boot mine.

We also have three multi-year coal supply agreements with TVA for the sale of coal. The first agreement with TVA was entered into in 2008 and terminates at the end of 2013. As amended, the agreement calls for delivery of 1.0 million tons in 2013 at a price of $55.88 per ton, subject to certain quality related adjustments. We entered into a second agreement with TVA in 2012. As amended, this agreement calls for delivery of 1.0 million tons in 2013 and 2014 and 2.0 million tons annually from 2015 to 2018. The price ranges from $45.50 to $49.03 per ton in 2013 and 2014, subject to certain quality related adjustments that are typical of the industry. TVA has the option in 2013 and 2014 to increase shipments by up to an additional 1.0 million tons annually by making timely elections pursuant to the agreement. The pricing on the additional tons is $43.12 per ton in 2013 and $46.47 per ton in 2014. As of August 31, 2013, TVA has elected to take an additional 1.0 million tons in 2013 and 0.5 million tons in 2014. The agreement provides that either party may elect at its sole option to reopen the agreement for negotiation with respect to price and/or other terms as it concerns all coal to be delivered from 2015 through 2018. We entered into the third agreement with TVA in 2013. This agreement calls for delivery of 1.0 million tons annually from 2014 to 2017. The price ranges from $49.65 to $52.10 per ton in 2014 and 2015, subject to certain quality related adjustments that are typical of the industry. TVA has the option to increase shipments by up to an additional 0.5 million tons annually by making timely elections pursuant to the agreement.

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The agreement provides that either party may elect at its sole option to reopen the agreement for negotiation with respect to price and/or other terms as it concerns all coal to be delivered from 2016 through 2017.

Transportation

We ship our coal to domestic customers by means of railcars, barges or trucks, or a combination of these means of transportation. We generally sell coal free on board at the mine or nearest loading facility. Our customers normally bear the costs of transporting coal by rail or barge. Historically, most domestic electricity generators have arranged long-term shipping agreements with rail or barge companies to assure stable delivery costs. Approximately 40% of our coal shipped in 2012 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. In 2012, 35% and 25% of our coal sales tonnage also was shipped by truck and rail, respectively.

Ram Terminals, LLC

We own a 5.0% equity interest in Ram Terminals, LLC (“Ram”). Ram owns 600 acres of Mississippi Riverfront property approximately 10 miles south of New Orleans and intends to permit, design and construct a seaborne coal export terminal capable of servicing up to Panamax-sized bulk carriers with an annual through-put capacity of up to 10 million tons. The terminal will be used to facilitate and ensure our access to international markets, as well as to handle export coal volumes of both metallurgical and thermal coal of other coal companies. One of the investment funds managed by Yorktown Partners LLC, is the controlling unitholder in Ram and is expected to provide the funds for future capital expenditures related to the development of the site. See “Prospectus Summary—Yorktown Partners LLC”. We will be involved in the initial design and construction of the terminal and will provide accounting and bookkeeping assistance to Ram.

Competition

The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States, and we compete with many of these producers. Our main competitors include Alliance Resource Partners, L.P., Patriot Coal Corp., Peabody Energy, Inc., the Cline 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 we do. Based on MSHA data, we were the fifth largest producer of Illinois Basin coal in fiscal 2012, producing approximately 7% of the total Illinois Basin coal. As the price of domestic coal increases, we also compete with companies that produce coal from one or more foreign countries, such as Colombia, Indonesia and Venezuela.

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

Our Safety Programs

Our safety programs include: (i) employing 12 full-time safety professionals; (ii) implementing policies and procedures to protect employees and visitors at our mines; (iii) utilizing experienced third-party blasting professionals to conduct our blasting activities; (iv) requiring a certified surface mine foreman to be in charge of the activities at each mine; and (v) ensuring that each employee undergoes the required safety, hazard and task training.

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We have won numerous awards for our safety record since 2008 recognizing our low injury and incident rates, as follows:

	Number of Awards
Awarding Body	2012		2011		2010		2009		2008
Kentucky Office of Mine Safety		—		—		1		1		—
Sentinels of Safety		8		—		6		3		1
Green River Safety Council		—		10		7		4		2

On October 28, 2011, an accident occurred at the Company’s Equality Boot mine and, tragically, two employees of a local blasting company were killed when rock fell from the highwall to the pit floor where they were travelling. Following the accident, pursuant to Section 103(k) of the Mine Act, MSHA issued an order prohibiting all activity at the Equality Boot Mine until MSHA determined that it was safe to resume normal mining operations. On November 2, 2011, MSHA modified the 103(k) order to permit the Company to resume mining the #14 seam in the Equality Boot mine.

On November 8, 2011, the Company submitted a ground control plan addendum to MSHA which was approved the same day, and subsequently incorporated into the Company’s mining operations at the Equality Boot mine. As a result, on November 8, 2011, MSHA modified the 103(k) order to permit the Company to resume normal mining activities in all areas of the Equality Boot mine until such time as the Commonwealth of Kentucky completes its accident report concerning the incident.

On February 7, 2012, the Kentucky Office of Mine Safety and Licensing issued its Fatal Accident Report. The Commonwealth of Kentucky concluded that the failure of the highwall occurred where the rock strata transitioned from wide bands of shale to smaller bands on laminated rock, thus creating a slicken slide fault in the area where the rock fell. The Kentucky Office of Mine Safety and Licensing did not find any causes or circumstances which contributed to the accident other than the aforementioned naturally occurring geological condition.

Finally, on May 7, 2012, MSHA issued its final Investigation Report concerning the accident. Similar to the findings of the Kentucky Office of Mine Safety and Licensing, MSHA concluded that the accident occurred because of a geologic anomaly located in the portion of the highwall below the #14 coal seam and above the #13 coal seam where there were two intersecting or nearly intersecting discontinuities in the rock formation. Although MSHA concluded that personnel at the Equality Boot mine had failed to recognize the anomaly and issued five Section 104(a) citations in connection with the accident, MSHA did not issue any citations finding high negligence or reckless disregard on the part of the Company or its employees.

Suppliers

We use various supplies and raw materials in our coal mining operations, such as petroleum-based fuels, explosives, tires and steel, as well as spare parts and other consumables. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction. We use sole source suppliers for certain parts of our business such as explosives and fuel, and preferred suppliers for other parts at our business such as dragline and shovel parts and related services. We believe adequate substitute suppliers are available.

Employees

At June 30, 2013, we employed a total of approximately 1,032 employees, none of whom is represented for collective bargaining by a union. We believe that our relations with all employees are good.

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Seasonality

Our business has historically experienced some variability in its results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as floods or blizzards, can impact our ability to mine and ship our coal and our customers’ ability to take delivery of coal.

Legal Proceedings

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

Regulation and Laws

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

• employee health and safety;

• permitting and licensing requirements;

• air quality standards;

• 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 customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal.

The costs of compliance with these laws and regulations have been and are expected to continue to be significant. Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may substantially increase equipment and operating costs, result in delays and disrupt operations or termination of operations, the extent of which cannot be predicted with any degree of certainty. Changes in applicable laws or the adoption of new laws relating to energy production may cause coal to become a less attractive source of energy. For example, if emissions rates or caps on greenhouse gases are enacted or a tax on carbon is imposed, the market share of coal as fuel used to generate electricity would be expected to decrease. Thus, future laws, regulations or enforcement priorities may adversely affect our mining operations, cost structure or the demand for coal.

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We are committed to operating our mines in compliance with applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. Violations, including violations of any permit or approval, can result in substantial civil and criminal fines and penalties, including revocation or suspension of mining permits. None of the violations we have experienced to date have had a material impact on our operations or financial condition.

Mining Permits and Approvals

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

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

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 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, the CWA, the Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”). Our mines are located in Kentucky, which has primacy to administer the SMCRA program.

SMCRA permit provisions include a complex set of requirements, which include, among other things, coal exploration, mine plan development, topsoil or a topsoil removal alternative, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, disposal of excess spoil, protection of the hydrologic balance, subsidence control for underground mines, surface runoff and drainage control, mine drainage and mine discharge control and treatment, establishment of suitable post mining land uses and re-vegetation. Our preparation of a mining permit application begins by collecting baseline data to adequately characterize the pre-mining environmental conditions of the permit area. This work is typically conducted by

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

Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being “permit blocked” under the federal Applicant Violator Systems. Thus, non-compliance with SMCRA can provide the bases to deny the issuance of new mining permits or modifications of existing mining permits. We know of no basis to be, and are not, permit-blocked.

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

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund (“AML”), which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the fee are used to

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restore mines closed or abandoned prior to SMCRA’s adoption in 1977. The fee was $0.315 per ton of coal produced from surface mines and $0.135 per ton on deep-mined coal from 2008 to 2012. Currently, the fee is $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from 2013 to 2021. In 2012, we recorded approximately $2.1 million of expense related to these reclamation fees.

Surety Bonds

Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. The cost of surety bonds have fluctuated in recent years, and the market terms of these bonds have generally become more unfavorable to mine operators. For example, in connection with our current bonds, we are required to post substantial security in the form of cash collateral. These changes in the terms of the bonds have been accompanied at times by a decrease in the number of companies willing to issue surety bonds. Some mine operators have therefore used letters of credit to secure the performance of a portion of our reclamation obligations. Many of these bonds are renewable on a yearly basis. We cannot predict our ability to obtain bonds or other approved forms of performance security, or the cost of such security, in the future. As of June 30, 2013, we had approximately $33.0 million in surety bonds outstanding to secure the performance of our reclamation obligations which are collateralized by cash deposits of approximately $4.0 million.

Mine Safety and Health

Stringent health and safety standards have been in effect since the enactment of the Federal Coal Mine Health and Safety Act of 1969. The Mine Act provided for MSHA and significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. For example, it requires periodic inspections of surface and underground coal mines and the issuance of citations or orders for the violation of a mandatory health and safety standard. A civil penalty must be assessed for each citation or order issued. Serious violations of mandatory health and safety standards may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators who knowingly or willfully violate a mandatory health and safety standard, or order and provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly or willfully violate a mandatory health and safety standard or order. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards. In addition to federal regulatory programs, the State of Kentucky in which we operate, also has programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. Such regulation has a significant effect on our operating costs.

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

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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 111^th 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 112^th Congress. Our compliance with current or future mine health and safety regulations could increase our mining costs. At this time, it is not possible to predict the full effect that the new or proposed statutes, regulations and policies will have on our operating costs, but they will increase our costs and those of our competitors. Some, but not all, of these additional costs may be passed on to customers.

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

Black Lung

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to eligible claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. During 2012 and for the six months ended June 30, 2013, we recorded $6.4 million and $3.5 million, respectively, of expense related to this excise tax.

In December 2000, the Department of Labor amended regulations implementing the federal black lung laws to, among other things, establish a presumption in favor of a claimant’s treating physician and limit a coal operator’s ability to introduce medical evidence regarding the claimant’s medical condition. Due to these changes, the number of claimants who are awarded benefits has since increased, and will continue to increase, as will the amounts of those awards. The Patient Protection and Affordable Care Act (“PPACA”), which was implemented in 2010, provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in coal mines and suffer from totally disabling lung disease. A coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner’s work. Second, it changed the law so black lung benefits being received by miners automatically go to their dependent survivors, regardless of the cause of the miner’s death. Our payment obligations for federal black lung benefits to claimants entitled to such benefits are either substantially secured by insurance coverage or paid from a tax exempt trust established for that purpose. Based on actuarial reports and required funding levels, from time to time we may have to supplement the trust corpus to cover the anticipated liabilities going forward. These regulations may have a material impact on our costs expended in association with the federal Black Lung program. In addition, we could be held liable under various Kentucky statutes for black lung claims.

Coal Industry Retiree Health Benefit Act of 1992

The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) provides for the funding of health benefits for certain United Mine Workers of America (“UMWA”), retirees and their spouses or dependents. The Coal Act established the Combined Benefit Fund into which employers who are “signatory operators” are

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obligated to pay annual premiums for beneficiaries. The Combined Benefit Fund covers a fixed group of individuals who retired before July 1, 1976, and the average age of the retirees in this fund is over 80 years of age. Because of our union-free status, we are not required to make payments to retired miners under the Coal Act. The Coal Act also created a second benefit fund, the 1992 UMWA Benefit Plan (“1992 Plan”), for miners who retired between July 1, 1976 and September 30, 1994, and whose former employers are no longer in business to provide them retiree medical benefits. Companies with 1992 Plan liabilities also pay premiums into this plan. We are not required to pay any premiums into the 1992 Plan.

Clean Air Act

The federal Clean Air Act and the amendments thereto and state laws that regulate air emissions both directly and indirectly affect coal mining operations. Direct impacts on our coal mining and processing operations include Clean Air Act permitting requirements and control requirements for particulate matter, which includes fugitive dust from roadways, parking lots, and equipment such as conveyors and storage piles.

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

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

• Acid Rain. Title IV of the Clean Air Act requires reductions of SO₂and NOx emissions by electric utilities regulated under the Acid Rain Program (“AR Program”). The AR Program was designed to reduce the electric power sector emissions of SO₂and NOx and was implemented in two phases, Phase II of which commenced in 2000 for both SO₂and NOx. SO₂emissions 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 AR Program, 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 its annual SO₂emissions or pay penalties. The electric power plant can choose to reduce emissions and sell or bank the surplus allowances or purchase allowances. Power plants are allowed to choose to emit or control emissions, emission reductions are encouraged by requiring an allowance to be retired every year for each ton of SO₂emitted. Affected power plants have sought to reduce SO₂emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading SO₂emissions allowances. The AR Program 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

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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, NOx, ozone, and particulate matter, so when any such standard is made stricter, it may indirectly affect our customers’ current or anticipated future costs of using coal. In addition, NAAQSs for particulate matter may affect aspects of our own operations, which can generate such emissions. The EPA has revised and/or proposed to revise a number of such NAAQSs in recent years. For example, in June 2010, the EPA issued a stricter NAAQS for SO₂emissions 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 SO₂concentrations. 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. The CSAPR, which was intended to replace the previously developed CAIR, requires states to reduce power plant emissions that contribute to ozone and/or fine particulate pollution in other states. On August 21, 2012, the D.C. Circuit vacated CSAPR and ordered the EPA to continue administering CAIR, pending the promulgation of a replacement rule. It is unclear what effect, if any, CAIR will have on our operations or results. On October 5, 2012, the EPA filed a petition seeking en banc rehearing of the August 21, 2012, decision regarding CSAPR. On January 24, 2013, the D.C. Circuit denied the EPA’s petition for rehearing, and on March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit’s decision on the CSAPR. The CAIR remains in place pending such ruling.

• 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

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coal-fired power plants. The NSR program requires existing coal-fired power plants, when undertaking certain modifications, to install the same air emissions control equipment as new plants. Enforcement proceedings alleging that such modifications were made without implementing the required control equipment have resulted in a number of settlements involving commitments, including those by coal- fired power plants, to incur extensive air emissions controls involving substantial expenses. Such enforcement, and other changes affecting the scope or interpretation of aspects of the NSR program, may impact demand for coal, but we are unable to predict the magnitude of any such impact on us with any reasonable degree of certainty.

Climate Change

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

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 (“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. 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 effect 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

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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 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.

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Also, litigation to address climate change impacts is being pursued against major emitters of greenhouse gases. A federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of CO₂; while the United States Supreme Court recently reversed the appeals court, it did not reach the question whether state common law is available for such claims because that question had not been addressed by the lower court. A second federal appeals court had earlier dismissed a case seeking damages allegedly caused by climate change that had been filed against scores of large corporate defendants, including a number of electrical power generating companies and coal companies, but the dismissal was on procedural grounds; the case has since been re-filed. Claims seeking remedies to address conditions or losses allegedly caused by climate change that in turn allegedly has resulted from greenhouse gas-generating conduct by the defendants remain pending in the courts. Such claims could continue to be asserted against our customers in the future, and might also be asserted against us; accordingly, such claims could adversely affect us either directly or indirectly.

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

These and other current or future climate change rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to switch from coal to lower greenhouse gas emitting fuels or 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 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 CWA and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including the discharge of dredged or fill materials, into waters of the United States. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease our costs and time spent on CWA compliance.

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

• 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

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a permit for any such discharges and entails regular monitoring, reporting and compliance with performance standards, all of which are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. Failures to comply with the CWA or the NPDES permits can lead to the imposition of penalties, compliance costs and delays in coal production. The CWA and corresponding state laws also protect waters that states have designated for special protections including those designated as: impaired (i.e., as not meeting present water quality standards) through Total Maximum Daily Load (“TMDL”) regulations and “high quality/exceptional use” streams through anti-degradation regulations which restrict or prohibit discharges which result in degradation. Likewise, when water quality in a receiving stream is better than required, states are required to adopt an “anti-degradation policy” by which further “degradation” of the existing water quality is reviewed and possibly limited. In the case of both the TMDL and anti-degradation review, the limits in our NPDES discharge permits could become more stringent, thereby potentially increasing our treatment costs and making it more difficult to obtain new surface mining permits. Other requirements may result in obligations to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; and to take measures intended to protect streams, wetlands, other regulated water sources and associated riparian lands from surface mining and/or the surface impacts of underground mining. Individually and collectively, these requirements may cause us to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.

• 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 (each, an “NWP”) 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 inOhio 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,

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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.

On February 16, 2012, but effective March 19, 2012, the Corps reissued 49 NWPs, including NWP 21, authorizing mining activities in streams and wetlands under Section 404 of the CWA and Section 10 of the Rivers and Harbors Act of 1899. In June 2010, the Corps announced the suspension of the NWP 21 permitting process in the Appalachian region of six states until the Corps took further action on it. The reissued NWP 21 will allow surface mining operations to disturb up to 0.5-acre of waters of the U.S. and 300 linear feet of stream bed. The 300 linear foot limit can be waived by the District Engineer for intermittent and ephemeral streams. Valley fills are specifically excluded from NWP 21. The most frequent use of this permit is most likely to be for placement of sediment control structures in intermittent or ephemeral streams when mining in steep terrain. To qualify for a NWP 21, a Pre-Construction Notification must be submitted to the Corps. If a mining operation has a NWP 21 permit authorized under the 2007 NWP 21 criteria and all or part of the permitted area is undisturbed as of March 18, 2012, the original NWP can be reauthorized by the Corps District Engineer without the newly introduced 0.5-acre limit of waters of the U.S. and 300 linear feet of stream bed. Requests for reauthorization of the 2007 NWP must be submitted to the District Engineer by February 1, 2013, and this reauthorization does not apply to valley fill construction.

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 captionedNational 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 ability to obtain other new permits or to maintain existing permits.

Section 404(q) of the CWA establishes a requirement that the Secretary of the Army and the Administrator of the EPA enter into an agreement assuring that delays in the issuance of permits under Section 404 are minimized. In August 1992, the Department of the Army and the EPA entered into such an agreement. The 1992 Section 404(q) 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

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these cases, the EPA determines that issuance of the permit will result in unacceptable adverse effects to ARNI. Alternately, the EPA may raise concerns over Section 404 program policies and procedures. An ARNI is a resource-based threshold used to determine whether a dispute between the EPA and the Corps regarding individual permit cases are eligible for elevation under the MOA. Factors used in identifying ARNIs, include the economic importance of the aquatic resource, rarity or uniqueness, and/or importance of the aquatic resource to the protection, maintenance, or enhancement of the quality of the waters.

Other Regulations on Stream Impacts

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

Resource Conservation and Recovery Act

The 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. 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

CERCLA 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,

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joint and several liability may be imposed on waste generators, site owners, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we currently own, lease or operate, and sites to which we have sent waste materials. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our mine sites. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we own surface rights.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (“USFWS”), works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. A number of species indigenous to the areas in which we operate are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or delaying us from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. Should more stringent protective measures be applied, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures.

Use of Explosives

We use third party contractors for blasting services and our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to regulatory requirements. We presently do not directly engage in blasting activities; instead, all of our blasting activities are conducted by independent contractors that use certified blasters.

Other Environmental Laws and Matters

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

Other Facilities

We currently lease office space for our headquarters in St. Louis, Missouri, as well as our regional office in Madisonville, Kentucky. We believe our properties are sufficient for our current needs.

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MANAGEMENT

Executive Officers and Directors

Set forth below are the names, ages and positions of our executive officers and directors as of October 1, 2013. All directors are elected for a term of three years and serve until their successors are elected and qualified. All executive officers hold office until their successors are elected and qualified.

Name	Age		Position with the Company
J. Hord Armstrong, III		72	Chairman (Class II) and Chief Executive Officer
Martin D. Wilson		52	President and Director (Class I)
Kenneth E. Allen		66	Executive Vice President of Operations
David R. Cobb, P.E.		65	Executive Vice President of Business Development
J. Richard Gist		57	Senior Vice President, Finance and Administration and Chief Financial Officer
Brian G. Landry		57	Vice President, Information Technology
Anson M. Beard, Jr.		77	Director (Class I)
James C. Crain		65	Director (Class III)
Richard F. Ford		77	Director (Class III)
Bryan H. Lawrence		71	Director (Class III)
Greg A. Walker		57	Director (Class II)

Biographical information concerning the directors and executive officers listed above is set forth below. The term of our Class I directors expires in 2015, the term of our Class II directors expires in 2013, and the term of our Class III directors expires in 2014.

J. Hord Armstrong, III—Mr. Armstrong served as our Predecessor’s Chairman and Chief Executive Officer, and as a member of our Predecessor’s board of managers, from its formation in 2006 until 2011. Since 2011, Mr. Armstrong has been our Chairman and Chief Executive Officer. Previously, Mr. Armstrong worked for the Morgan Guaranty Trust Company and was elected Assistant Treasurer in 1967. He subsequently spent 10 years with White Weld & Company as First Vice President until the firm was acquired by Merrill Lynch in 1978. Mr. Armstrong then joined Arch Mineral Corporation, St. Louis, as Treasurer (1978-1981), and ultimately became its Vice President and Chief Financial Officer (1981-1987). Mr. Armstrong left Arch Mineral in 1987, when he founded D&K Healthcare Resources. Mr. Armstrong served as D&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 our company. The board believes his prior experiences afford him unique insights into our company’s strategies, challenges and opportunities.

Martin D. Wilson—Mr. Wilson served as our Predecessor’s President, and as a member of our Predecessor’s board of managers, from its formation in 2006 until 2011. Since 2011, Mr. Wilson has been our President. From 1985 to 1988, Mr. Wilson was employed by KPMG Peat Marwick. From 1988 until 2005, Mr. Wilson served as President and Chief Operating Officer of D&K Healthcare Resources. Mr. Wilson is a former member of the Board of Directors of Healthcare Distribution Management Association (HDMA). The board selected Mr. Wilson to serve as a director because of his experience in public company management, finance and administration, as well as for his in-depth knowledge of our company.

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Kenneth E. Allen—Mr. Allen served as our Predecessor’s Vice President of Operations from 2007 until 2011. Since 2011, Mr. Allen has been our Executive Vice President of Operations. He started his career with Peabody Coal Company in 1967 and has over 40 years of experience in the coal industry. In 1971, he moved into a supervisory position and continued to hold various supervisory and management positions, including Chief Electrical Engineer, Mine Superintendent, Operations Manager and Vice President of Resource Development and Conservancy. Prior to joining our company in 2007, Mr. Allen held the position of President and General Manager of Bluegrass Coal Company, a subsidiary of Peabody Energy. Mr. Allen is Chairman of the Upper Pond River Conservancy District and a member of the Kentucky Workforce Investment Board of Directors, the West Kentucky Consortium for Energy and Environment, the Madisonville-Hopkins County Economic Development Board of Directors and the Madisonville- Hopkins County Chamber Board of Directors. He is a past member of the Kentucky Coal Council and the Kentucky Governors Council of Economic Advisors. He is past Chairman and current member of the Executive Boards of the Kentucky Coal Association and the Western Kentucky Coal Association.

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

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

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

Anson M. Beard, Jr.—Mr. Beard was appointed to our board in 2011. He joined Morgan Stanley & Co. as a Vice President to found Private Client Services in 1977. He was promoted to Principal in 1979 and Managing Director in 1980. In 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 1994,Mr. Beard retired and became an Advisory Director of Morgan Stanley. He continues to serve in this capacity.

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

Richard F. Ford—Mr. Ford was appointed to our board in 2011. Mr. Ford is the retired general partner of Gateway Associates, L.P., a venture capital management firm that he formed in 1984. Mr. Ford serves as a member of the board of directors and a member of the audit committees of Barry-Wehmiller Company. Until 2012, Mr. Ford served as a director of Stifel Financial Corp. Mr. Ford also serves as a member of the board of directors and chair of the audit committee of Spartan Light Metal Products, Inc., a privately-held company. He currently serves on the board of directors of Washington University in St. Louis, Missouri. The board selected Mr. Ford to serve as a director because of his substantial experience in the financial services industry. He also has considerable board and committee leadership experience at other publicly held and large private companies.

Bryan H. Lawrence—Mr. Lawrence served as a member of our Predecessor’s board of managers from its formation in 2006 until 2011. He was appointed to our board of directors in 2011. He is a founder and principal of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co., Inc. where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in 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 U.S. publicly traded company) and Winstar Resources, Ltd., (a Canadian public company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence serves on our board of directors because of his significant knowledge of all aspects of the energy industry.

Greg A. Walker—Mr. Walker was appointed to our board of directors in 2011. From 2009 to 2011, he served as a Senior Vice President of Alpha Natural Resources, Inc., assisting with integration issues after the merger of Alpha Natural Resources, Inc. and Foundation Coal Holdings, Inc. From 2004 to 2009, Mr. Walker served as the Senior Vice President, General Counsel and Secretary of Foundation Coal Holdings, Inc. From 1999 to 2004, he served as the Senior Vice President, General Counsel and Secretary of RAG American Coal Holdings, Inc., which was the predecessor entity to Foundation Coal Holdings, Inc. From 1989 to 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 to 1986 he held various positions within the law department of Mobil Oil Corporation. From 2005 to 2012, he was a member of the board of directors of the FutureGen Industrial Alliance, Inc., a not-for-profit entity whose global members are working with the U.S. Department of Energy to build and operate a commercial scale oxy-combustion coal-fired power plant with carbon dioxide capture and sequestration. 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 tomatters regarding the production, use and demand for coal on a global basis. The board selected Mr. Walker to

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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

Our board currently consists of seven directors. Our board has established the following committees: an audit committee, 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 our board.

Although our board members are not subject to the independence standards of The NASDAQ Stock Market LLC (“NASDAQ”), we use NASDAQ’s independence standards for purposes of determining our directors’ independence. Applying these standards, a majority of our board members is independent. The board has determined that each of Messrs. Beard, Crain, Ford and Walker is an independent director pursuant to the requirements of NASDAQ. In addition, each of our audit committee members satisfies NASDAQ’s additional conditions for independence for audit committee members.

Audit Committee

Messrs. Crain, Ford and Walker, each an independent director, serve on our audit committee. Mr. Ford is the chair of the audit committee. The committee assists our board in fulfilling its oversight responsibilities relating to (i) the integrity of our financial statements, internal accounting, financial controls, disclosure controls and financial reporting processes, (ii) the independent auditors’ qualifications and independence, (iii) the performance of our independent auditors, and (iv) our compliance with legal and regulatory requirements. The board has determined that Mr. Ford qualifies as an “audit committee financial expert,” as that term is defined in Item 407(d)(5) of Regulation S-K, as promulgated by the SEC.

Compensation Committee

Messrs. Beard, Ford and Walker, each an independent director, serve on our compensation committee. Mr. Beard is the chair of the compensation committee. The committee is responsible for discharging the board’s responsibility relating to compensation of our executive officers and directors, evaluating the performance of our executive officers in light of our goals and objectives and recommending to the board for approval our compensation plans, policies and programs. Each member of the committee is independent, a “non-employee director” for purposes of Rule 16b-3 under the Exchange Act, and an “outside director” for purposes of Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”).

The compensation committee has been tasked with the responsibility to establish and implement our new compensation philosophy and objectives, administrate our executive and director compensation programs and plans, and review and approve the compensation of our named executive officers. The committee is currently in the process of evaluating our historical compensation practices and customizing a new management compensation program for our specific circumstances.

The compensation committee’s responsibilities are specified in its charter. The compensation committee’s functions and authority include, among other things:

• Establishment and annual review of corporate goals and objectives relevant to the compensation of the executive officers, including the chief executive officer;

• Evaluation of the executive officers’ performance;

• Determination and approval of executive officer compensation;

• Administration of equity compensation plans, annual bonus and long-term incentive cash-based compensation plans;

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• Review and approval of employment agreements and severance arrangements of all executive officers; and

• Management of risk relating to incentive compensation.

Nominating, Corporate Governance and Risk Management Committee

Messrs. Beard, Crain and Ford, each an independent director, serve on our nominating, corporate governance and risk management committee. Mr. Crain is the chair of this committee. The committee is responsible for (i) assisting the board by identifying individuals qualified to become board members, and recommending to our board nominees for election as director, (ii) leading the board in its annual performance review, (iii) recommending to the board members and chairpersons for each committee, (iv) monitoring the attendance, preparation and participation of individual directors and conducting a performance evaluation of each director prior to the time he or she is considered for re-nomination to the board of directors, (v) monitoring and evaluating corporate governance issues and trends, and (vi) discharging the board’s responsibilities relating to compensation of our directors by reviewing such compensation annually and then recommending any changes in such compensation to the full board of directors.

Conflicts Committee

Messrs. Beard, Crain and Walker, each an independent director, serve on our conflicts committee. Mr. Walker is the chair of this committee. The committee is responsible for (i) reviewing specific matters that the board believes may involve conflicts of interest, (ii) reviewing specific matters requiring action of the conflicts committee pursuant to any agreement to which we are a party, (iii) advising the board on actions to be taken by us upon the board’s request, and (iv) carrying out any other duties delegated to the conflicts committee by the board of directors.

Compensation Committee Interlocks and Insider Participation

No member of our compensation committee is, or was during the fiscal year ended December 31, 2012, an officer, former officer or employee of us or any of our subsidiaries, or a person having a relationship requiring disclosure by us pursuant to Item 404 of Regulation S-K. None of our executive officers served as a member of (i) the compensation committee of another entity of which one of the executive officers of such entity served on our compensation committee or (ii) the board of directors of another entity of which one of the executive officers of such entity served on our board of directors, during the fiscal year ended December 31, 2012.

Code of Ethics

We have adopted a code of business conduct and ethics applicable to all employees, including executive officers, and directors. A copy of the code of business conduct and ethics is available on our website atwww.armstrongenergyinc.com. Any amendments to, or waivers from, provisions of the code related to certain matters will be disclosed on our website.

Compensation of Directors

Each of our independent directors receives (a) an annual cash retainer of $50,000, and (b) $1,500 per meeting of the board of directors attended by such director ($500 in the case of telephonic participation). Our nominating, corporate governance and risk management committee reviews and makes recommendations to the board regarding compensation of directors, including equity-based plans. We reimburse our non-employee directors for reasonable travel expenses incurred in attending board and committee meetings. We also intend to allow our non-employee directors to participate in the 2011 Long-Term Incentive Plan (the “LTIP”) and any other equity compensation plans that we adopt in the future.

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The following table discloses compensation paid for the fiscal year ended December 31, 2012 to our independent directors for serving as members of the Board.

2012 Director Compensation Table

Name	Fees Earned or Paid in Cash		Total
Anson M. Beard, Jr.	$	52,500	$	52,500
James C. Crain	$	54,500	$	54,500
Richard F. Ford	$	53,000	$	53,000
Greg A. Walker	$	54,500	$	54,500

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EXECUTIVE OFFICER COMPENSATION

2012 Summary Compensation Table

The following table sets forth all compensation paid to our named executive officers for the years ending December 31, 2012 and 2011.

Name and Principal Position	Year		Salary		Bonus		Stock Awards(1)			All Other Compensation			Total
J. Hord Armstrong, III,		2012	$	350,000	$	262,500	$	—		$	119,880	(3)	$	732,380
Chairman and Chief Executive Officer		2011		300,000		225,000		3,340,100	(2)		33,649			3,898,749
Martin D. Wilson,		2012	$	350,000	$	300,000	$	—		$	36,275	(5)	$	686,275
President		2011		300,000		225,000		2,997,600	(4)		38,814			3,561,414
Kenneth E. Allen(6),		2012	$	300,000	$	195,000	$	—		$	398,137	(8)	$	893,137
Executive Vice President of Operations		2011		275,000		157,500		257,600	(7)		370,919			1,061,019
David R. Cobb, P.E.(9),		2012	$	260,000	$	175,000	$	—		$	398,137	(10)	$	833,137
Executive Vice President of Business Development		2011		238,000		139,000		257,600	(7)		368,136			1,002,736
J. Richard Gist(11),		2012	$	235,000	$	120,000	$	—		$	24,250	(12)	$	379,250
Senior Vice President, Finance and Administration and Chief Financial Officer		2011		210,000		105,000		—			13,961			328,961

(1) Amounts disclosed in this column relate to grants of Armstrong Energy common stock and Armstrong Resource Partners common units. The amounts reflect the grant date fair value computed in accordance with FASB Accounting Standards Codification (“ASC”) Topic 718.

(2) Represents the grant date fair value of 18,500 restricted shares of Armstrong Energy common stock granted on June 1, 2011 ($257,600), and the grant date fair value of 22,500 restricted units of limited partner interest granted by Armstrong Resource Partners on October 1, 2011 ($3,082,500).

(3) Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Armstrong ($12,500), an allowance for personal automobile usage ($12,000), the incremental cost to the Company of Mr. Armstrong’s personal use of our corporate aircraft ($82,905), and an allowance for club membership dues ($12,725). Mr. Armstrong’s personal use of the corporate aircraft has been valued based on the incremental costs to us for the personal use of our aircraft. Incremental costs for personal use consist of the variable costs incurred by us to operate the aircraft for such use, including fuel costs; crew expenses, including travel, hotels and meals; in-flight catering; landing, parking and handling fees; communications expenses; certain trip-related maintenance; and other trip-related variable costs. In addition, if the aircraft flies empty before picking up or dropping off a passenger flying for personal reasons, this “deadhead” segment is included in the incremental cost of the personal use. Incremental costs do not include fixed or non-variable costs that would be incurred whether or not there was any personal use of the aircraft, such as crew salaries and benefits, insurance costs, aircraft purchase costs, depreciation and scheduled maintenance. Travel by Mr. Armstrong’s spouse is generally considered personal use and is subject to taxation and disclosure.

(4) Represents the grant date fair value of 18,500 restricted shares of Armstrong Energy common stock granted on June 1, 2011 ($257,600), and the grant date fair value of 20,000 restricted units of limited partner interest granted by Armstrong Resource Partners on October 1, 2011 ($2,740,000).

(5) Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Wilson ($12,250), an allowance for personal automobile usage ($12,000), and an allowance for club membership dues ($12,025).

(6) Mr. Allen was appointed Executive Vice President of Operations effective October 1, 2011. Prior to this time, Mr. Allen was our Vice President of Operations.

(7) Represents the grant date fair value of 18,500 restricted shares of Armstrong Energy common stock granted on June 1, 2011.

(8) Represents overriding royalties paid to Mr. Allen ($373,887) (see “—Overriding Royalty Agreements” for a description of Mr. Allen’s agreement with us regarding the payment of overriding royalties), our

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matching contributions paid to our 401(k) plan on behalf of Mr. Allen ($12,250), and an allowance for personal automobile usage ($12,000).

(9) Mr. Cobb was appointed Executive Vice President of Business Development effective October 1, 2011. Prior to this time, Mr. Cobb was our Vice President of Business Development.

(10) Represents overriding royalties paid to Mr. Cobb ($373,887 (see “—Overriding Royalty Agreements” for a description of Mr. Cobb’s agreement with us regarding the payment of overriding royalties), our matching contributions paid to our 401(k) plan on behalf of Mr. Cobb ($12,250), and an allowance for personal automobile usage ($12,000).

(11) Mr. Gist was appointed Senior Vice President, Finance and Administration and Chief Financial Officer effective October 1, 2011. Prior to this time, Mr. Gist was our Vice President and Controller.

(12) Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Gist ($12,250), and an allowance for personal automobile usage ($12,000).

Elements of Compensation

Historically, our executive officers have received annual salaries as their compensation for services. In addition, our board may grant discretionary cash bonuses and equity to our executive officers in order to align the compensation interests of our executive officers with our short-term and long-term interests. Decisions regarding compensation of our executive officers generally are made by the compensation committee, based upon the recommendations of our president. The base salary for each of our named executive officers is set forth in his employment agreement and is subject to adjustment annually as determined by the board of directors. See “—Employment Agreements.” Historically, we have not set any specific performance targets for Armstrong Energy or for individual executive officers. Determinations regarding salary adjustments are made based on a number of objective and subjective factors, including cost of living increases, our financial performance in a general sense, including our Adjusted EBITDA, and a qualitative analysis of each individual officer’s performance during the preceding year, taking into account such factors as leadership, commitment and execution of corporate initiatives and special projects assigned by the board of directors. We also consider whether there has been any material change in the officer’s title, duties and responsibilities in the preceding year. Finally, we may decide to make a market adjustment in salaries, if we determine that salary levels for one or more of our named executive officers have fallen materially below levels that we consider appropriate in order to maintain a competitive compensation package and to discourage valued executives from leaving their positions with us to pursue other opportunities. In making market adjustments, we informally analyze publicly available data relating to historical compensation paid to certain executive officers at several public coal mining companies. The specific companies included in the analysis may change from year to year. For 2012, we included the following companies in our analysis: Alliance Resource Partners, L.P., Cloud Peak Energy Inc., Hallador Energy Company, James River Coal Company, Oxford Resource Partners, LP, Rhino Resource Partners LP and Westmoreland Coal Company. We do not utilize a compensation consultant.

Each year, the compensation committee determines the amount of any discretionary bonuses to be paid to our named executive officers, based upon the recommendations of our president. The bonuses are determined in a manner similar to the annual base salary adjustments described above, i.e. based on a number of objective and subjective factors, including the target bonus set forth in the respective officer’s employment agreement, if any (see “—Employment Agreements—Armstrong and Wilson Employment Agreements” and “—Employment Agreements—2011 Gist Employment Agreement”), our financial performance in a general sense, and a qualitative analysis of each individual officer’s performance during the preceding year, taking into account such factors as leadership, commitment, and execution of corporate initiatives and special projects assigned by the board. However, no specific pre-established performance objectives are set and, ultimately, the amount of annual bonuses is determined at the final discretion of the compensation committee. The discretionary bonuses are also considered together with the base salary adjustments in ensuring that our executive officers are provided a competitive level of cash compensation each year, but the discretionary bonus portion provides flexibility to adjust total annual cash compensation to align with current performance.

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In making bonus recommendations to the compensation committee for 2012, Mr. Wilson, our president, informally conducted a subjective evaluation considering the target bonus set forth in the respective officer’s employment agreement, if any, internal equity among the named executive officers, current aggregate compensation levels, performance, long-term career goals, future leadership potential, succession planning, and other individual intangible contributions that enhance operating and financial performance. Neither Mr. Wilson nor the compensation committee uses a formula to weight these factors, but instead uses these factors to provide context within which to assess the significance of comparative market data and to differentiate the level of compensation among our named executive officers.

On June 1, 2011, we granted to each of Messrs. Armstrong, Wilson, Allen and Cobb 18,500 restricted shares of common stock of Armstrong Energy, which vested on April 1, 2013. The aggregate grant date fair value of each award was $257,600.

Also, on October 1, 2011, Armstrong Resource Partners granted 22,500 and 20,000 restricted units of limited partner interest to Mr. Armstrong and Mr. Wilson, respectively. The aggregate grant date fair value of Mr. Armstrong’s award was $3,082,500, and the aggregate grant date fair value of Mr. Wilson’s award was $2,740,000. Pursuant to the terms of each of the Restricted Unit Award Agreements, the grantee was required to deliver to us that number of restricted units, valued at the fair market value of such units at the time of such delivery, to satisfy any federal, state or local taxes due in connection with the grant. Effective January 25, 2012, Mr. Armstrong entered into an Assignment of Limited Partnership Units with us, pursuant to which Mr. Armstrong transferred and assigned 9,405 units to us, in exchange for our agreement to pay any federal, state or local taxes arising from the grant, the total amount of which has been determined to be equal to approximately $1.3 million. Also effective January 25, 2012, Mr. Wilson entered into an Assignment of Limited Partnership Units with us, pursuant to which Mr. Wilson transferred and assigned 8,360 units to us, in exchange for our agreement to pay any federal, state or local taxes arising from the grant, the total amount of which has been determined to be equal to approximately $1.1 million.

The LTIP provides for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, performance grants and other equity-based incentive awards to those who contribute significantly to our strategic and long-term performance objectives and growth. No awards were made under the LTIP in 2012 or 2011. The LTIP is more fully described below under “—2011 Long-Term Incentive Plan.”

Other Executive Benefits

Our named executive officers are eligible for the following benefits on the same basis as other eligible employees:

• Health insurance;

• Vacation, personal holidays and sick time;

• Life insurance and supplemental life insurance;

• Short-term and long-term disability; and

• A 401(k) plan with matching contributions.

In addition, we provide our named executive officers with an annual car allowance and a payment equal to the group term life insurance premium paid on each named executive officer’s behalf. Also, we provide Messrs. Armstrong and Wilson with an allowance for club membership dues. Company aircraft may occasionally be used by executive officers for personal travel.

Employment Agreements

2007 Allen and Cobb Employment Agreements

Effective June 1, 2007, we entered into an employment agreement (the “2007 Allen Employment Agreement”) with Mr. Allen. Effective January 1, 2007, we entered into an employment agreement (the “2007

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Cobb Employment Agreement” and together with the Allen Employment Agreement, the “2007 Agreements”) with Mr. Cobb. Pursuant to the 2007 Agreements, we agreed to pay Messrs. Allen and Cobb initial base salaries of $240,000 and $180,000, respectively. The base salaries are subject to adjustment annually as determined by the board of directors. Effective January 1, 2011, the base salaries of Messrs. Allen and Cobb were increased to $275,000 and $238,000, respectively. Effective January 1, 2012, the base salaries of Messrs. Allen and Cobb were increased to $300,000 and $260,000, respectively.

The 2007 Agreements provide that Messrs. Allen and Cobb shall be eligible to participate in such benefits as may be authorized and adopted from time to time by the board of directors for our employees, including, without limitation, any pension plan, profit-sharing plan or other qualified retirement plan and any group insurance plan. The term of each of the 2007 Agreements is three years, and each shall be automatically renewed for additional one-year terms until such time, if any, as we or the respective executive give written notice to the other party that such automatic extension shall cease. In the case of the 2007 Allen Employment Agreement, such notice must be given at least 60 days prior to the expiration of the then current term.

The 2007 Agreements contain non-competition and non-solicitation provisions that endure for a period of 12 months following the executives’ termination of employment with us.

In addition, pursuant to each of the 2007 Agreement and the related overriding royalty agreement, as amended, between Mr. Allen and us, and the 2007 Cobb Employment Agreement and the related overriding royalty agreement, as amended, between Mr. Cobb and us, Messrs. Allen and Cobb each receive an overriding royalty equal to $0.05 per ton sold by us from certain reserves described in those agreements. See “—Overriding Royalty Agreements.”

Pursuant to the 2007 Agreements, we may terminate each agreement at any time for cause, which is defined as: (i) the executive’s failure substantially to perform his duties under the agreement in a manner satisfactory to the board, as determined in good faith by the board, provided that the board has given the executive written notice of the action(s) or omission(s) which are claimed to constitute such failure and the executive does not fully remedy such failure within 10 calendar days after receipt of the written notice, (ii) the executive has engaged in gross misconduct, dishonest, disloyal, illegal or unethical conduct, or any other conduct which has or could reasonably have a detrimental impact on our company or its reputation, all facts to be determined in good faith by the board, (iii) the executive has acted in a dishonest or disloyal manner, or breached any fiduciary duty to our company that, in either case, results or was intended to result in personal profit to the executive at the expense of our company or any of its customers, (iv) the executive has been convicted of or pleads guilty or no contest to any felony, (v) the executive has one or more physical or mental impairments which have substantially impaired his ability to perform the essential functions of his job under the agreement, (vi) the executive’s death, (vii) any breach by the executive of certain obligations under the agreement, (viii) resignation by the executive under circumstances where a termination for “cause” was impending or could have reasonably been foreseen.

We also may terminate each of the 2007 Agreements without cause, as defined above. In the event of such termination without cause, the executive shall be entitled to receive (i) the executive’s base salary for 12 months following termination, at the same rate as was in effect on the day prior to termination, and (ii) health insurance premiums for 12 months. In addition, the respective overriding royalty will run with the land per the provisions of the overriding royalty agreements. See “—Overriding Royalty Agreements.”

Under each of the 2007 Agreements, the executive may resign for good reason, which is defined as a material demotion or reduction, without the executive’s consent, in the executive’s duties. In the event of a resignation for good reason, the executive shall be entitled to receive (i) the executive’s base salary for 12 months following termination, at the same rate as was in effect on the day prior to termination, and (ii) health insurance premiums for 12 months. In addition, the respective overriding royalty will run with the land per the provisions of the overriding royalty agreements. See “—Overriding Royalty Agreements.”

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In the event of a termination of the executive’s employment, other than for cause, within 12 months of a change in control, the executive shall be entitled to receive health insurance premiums for 12 months. In addition, we will pay, promptly following such termination, a lump sum payment equal to one times the executive’s annual base salary at the time of his termination, plus any accrued and unpaid overriding royalty. For this purpose, a change in control means: (i) any purchase or other acquisition by an individual or group of person(s) (including entity(ies)) acting in concert, which results in persons who are our shareholders as of the date of entry into the respective agreement no longer being the legal and beneficial owners of 51% or more of the outstanding equity in our company, (ii) consummation of a reorganization, merger, recapitalization, consolidation, or any other transaction, in each case with respect to which persons who were our shareholders as of the date of entry into the respective agreement do not, immediately thereafter, legally and beneficially own 51% or more of the equity in the newly-organized, merged, recapitalized, consolidated, or other resulting entity, or (iii) the sale of all or substantially all of our assets in a transaction approved by the board.

2009 Gist Employment Agreement

Effective September 17, 2009, we entered into an employment agreement (the “2009 Gist Agreement”) with Mr. Gist. Pursuant to the 2009 Gist Agreement, we agreed to pay Mr. Gist a base salary of $192,500. Effective January 1, 2011, his base salary was increased to $210,000. Pursuant to the 2009 Gist Agreement, Mr. Gist is also eligible to receive a bonus, with a target of 45% of his base compensation. The bonus will be earned based on our company’s achievement of profitability targets and Mr. Gist’s satisfactory achievement of goals and objectives as determined by our President. For 2009, Mr. Gist was to earn a bonus equal to a minimum of 22.5% of base salary, less $15,000. In addition, Mr. Gist received a signing bonus of $15,000 in 2009.

In addition, pursuant to the terms of the 2009 Gist Agreement, Mr. Gist was granted 18,500 restricted shares of Armstrong Energy common stock. Such shares vested on September 30, 2011.

The 2009 Gist Agreement provides that Mr. Gist shall be eligible to participate in any future stock option plans, restricted stock grants, phantom stock, or any other stock compensation programs as approved by the board of directors or our shareholders. Awards will be made at the discretion of the board of directors and our President.

Pursuant to the 2009 Gist Agreement, if we terminate the agreement without cause, Mr. Gist is entitled to receive 12 months of salary, bonus and health benefits. If Mr. Gist resigns for good reason, which is defined as significant diminishing of Mr. Gist’s job responsibilities, change in position or title, etc., Mr. Gist is entitled to receive 12 months of salary, bonus and health benefits. Pursuant to the 2009 Gist Agreement, if there is a change in control and Mr. Gist’s job is eliminated or Mr. Gist resigns for good reason within one year of the change in control, Mr. Gist is entitled to receive 12 months of salary, bonus and health benefits.

2011 Gist Employment Agreement

Effective October 1, 2011, we terminated the 2009 Gist Agreement upon mutual agreement of the parties thereto and entered into a new employment agreement with Mr. Gist (the “2011 Gist Agreement”).

Pursuant to the 2011 Gist Agreement, we agreed to pay Mr. Gist $210,000 for his services as our Senior Vice President, Finance and Administration and Chief Financial Officer. Effective January 1, 2012, Mr. Gist’s base salary was increased to $235,000. In addition, Mr. Gist is entitled to an annual target bonus of 50% of the then annual salary. The bonus will be based upon the achievement of performance criteria established by us and to be awarded at the discretion of our President or board of directors. As of October 1, 2013, the Company has not established any performance criteria pursuant to the 2011 Gist Agreement. However, the board granted Mr. Gist a discretionary cash bonus in the amount of $120,000 for 2012 and $105,000 for 2011.

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The 2011 Gist Agreement provides that Mr. Gist shall be eligible to participate in such benefits as may be authorized and adopted from time to time by the board of directors for our employees, including, without limitation, any pension plan, profit-sharing plan or other qualified retirement plan and any group insurance plan. The term of the 2011 Gist Agreement is one year, and shall be automatically renewed for additional one year terms until such time, if any, as we or Mr. Gist gives written notice to the other party that such automatic extension shall cease. Such notice must be given at least 60 days prior to the expiration of the then current term.

Pursuant to the 2011 Gist Agreement, we may terminate the agreement at any time for cause, which is defined as: (i) Mr. Gist’s failure substantially to perform his duties under the agreement in a manner satisfactory to the board, as determined in good faith by the board, provided that the board has given Mr. Gist written notice of the action(s) or omission(s) which are claimed to constitute such failure and Mr. Gist does not fully remedy such failure within 10 calendar days after receipt of the written notice, (ii) Mr. Gist has engaged in gross misconduct, dishonest, disloyal, illegal or unethical conduct, or any other conduct which has or could reasonably have a detrimental impact on our company or its reputation, all facts to be determined in good faith by the board, (iii) Mr. Gist has acted in a dishonest or disloyal manner, or breached any fiduciary duty to our company that, in either case, results or was intended to result in personal profit to Mr. Gist at the expense of our company or any of its customers, (iv) Mr. Gist has been convicted of or pleads guilty or no contest to any felony, (v) Mr. Gist has one or more physical or mental impairments which have substantially impaired his ability to perform the essential functions of his job under the agreement, (vi) Mr. Gist’s death, (vii) any breach by Mr. Gist of certain obligations under the agreement, (viii) resignation by Mr. Gist under circumstances where a termination for “cause” was impending or could have reasonably been foreseen.

We also may terminate the 2011 Gist Agreement without cause, as defined above. In the event of such termination without cause, the executive shall be entitled to receive (i) the executive’s base salary for 12 months following termination, at the same rate as was in effect on the day prior to termination, plus any accrued but unpaid bonus as of the termination date, and (ii) health insurance premiums for 12 months.

Pursuant to the 2011 Gist Agreement, Mr. Gist may resign for good reason, which is defined as a material demotion or reduction, without Mr. Gist’s consent, in Mr. Gist’s duties. In the event of a resignation for good reason, Mr. Gist shall be entitled to receive (i) his base salary for 12 months following termination, at the same rate as was in effect on the day prior to termination, and (ii) health insurance premiums for 12 months.

In the event of a termination of Mr. Gist’s employment, other than for cause, within 12 months of a change in control, Mr. Gist shall be entitled to receive health insurance premiums for 12 months. In addition, we will pay, promptly following such termination, a lump sum payment equal to one times Mr. Gist’s annual base salary at the time of his termination, plus one year’s bonus in an amount equal to 50% of Mr. Gist’s then existing annual base salary. For this purpose, a change in control means: (i) any purchase or other acquisition by an individual or group of person(s) (including entity(ies)) acting in concert, which results in persons who are our shareholders as of the date of entry into the respective agreement no longer being the legal and beneficial owners of 51% or more of the outstanding equity in our company, (ii) consummation of a reorganization, merger, recapitalization, consolidation, or any other transaction, in each case with respect to which persons who were our shareholders as of the date of entry into the respective agreement do not, immediately thereafter, legally and beneficially own 51% or more of the equity in the newly-organized, merged, recapitalized, consolidated, or other resulting entity, or (iii) the sale of all or substantially all of our assets in a transaction approved by the board.

The 2011 Gist Agreement contains non-competition and non-solicitation provisions that endure for a period of 12 months following Mr. Gist’s termination of employment with us.

Armstrong and Wilson Employment Agreements

Effective October 1, 2011, we entered into an employment agreement (the “2011 Armstrong Agreement”) with each of Messrs. Armstrong and Wilson (together, the “Armstrong and Wilson Agreements”).

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Pursuant to each of the Armstrong and Wilson Agreements, we agreed to pay each of Messrs. Armstrong and Wilson a base salary of $300,000. Effective January 1, 2012, the base salary of each of Messrs. Armstrong and Wilson was increased to $350,000. In addition, each of Messrs. Armstrong and Wilson is entitled to an annual bonus based upon achievement of performance criteria established by us and to be awarded by our board. The target amount will not be less than 75% of the executive’s then annual base salary. The executive’s base salary and bonus will be reviewed from time to time and may be increased. As of October 1, 2013, the Company has not established any performance criteria pursuant to the Armstrong and Wilson Agreements. However, the board granted each of Messrs. Armstrong and Wilson a discretionary cash bonus in the amount of $262,500 and $300,000, respectively, for 2012 and $225,000 for 2011.

The Armstrong and Wilson Agreements provide that Messrs. Armstrong and Wilson shall be entitled to participate in any of our benefit plans made available to other senior executive officers. The term of each of the Armstrong and Wilson Agreements is three years, and each shall automatically renew for successive one-year terms unless either party gives the other a notice of non-renewal at least 90 days before the end of the then current term.

Pursuant to the Armstrong and Wilson Agreements, we may terminate Mr. Armstrong’s and Mr. Wilson’s employment at any time without cause (as defined below), and each of Mr. Armstrong and Mr. Wilson may terminate his own employment at any time for good reason (as defined below). In the event of a termination without cause, failure by us to renew the agreement or termination by the executive for good reason, (i) we will continue to pay the executive’s base salary and provide his other benefits under the respective agreement (including automobile allowance, vacation and health insurance) for 24 months, and (ii) the executive shall also be entitled to a bonus for that year equal to 75% of his base salary then in effect (irrespective of whether performance objectives have been achieved). In addition, (a) we will provide the executive with outplacement services, and (b) the executive shall be entitled to a contribution under our retirement benefit plan for that fiscal year equal to the greater of (x) the amount that would have been contributed for that fiscal year determined in accordance with past practice, or (y) the highest amount contributed by us on behalf of the executive for any of the three prior fiscal years.

For this purpose, cause means (i) the executive’s willful and continued failure substantially to perform his duties under the respective agreement (other than as a result of sickness, injury or other physical or mental incapacity or as a result of termination by the executive for good reason); provided, however, that such failure shall constitute “cause” only if (x) we deliver a written demand for substantial performance to the executive that specifies the manner in which we believe he has failed substantially to perform his duties under the agreement and (y) the executive shall not have corrected such failure within 10 business days after his receipt of such demand; (ii) willful misconduct by the executive in the performance of his duties under the agreement that is demonstrably and materially injurious to our company or any affiliated company for which he is required to perform duties hereunder; (iii) the executive’s conviction of (or plea of nolo contendere to) a financial-related felony or other similarly material crime under the laws of the United States or any state thereof; or (iv) any material violation of the respective agreement by the executive. No action, or failure to act, shall be considered “willful” if it is done by the executive in good faith and with the reasonable belief that the action or omission was in the best interest of our company. If our Board determines in its sole discretion that a cure of the acts or omissions described above is possible and appropriate, we will give the executive written notice of the acts or omissions constituting cause and no termination of the agreement shall be for cause unless and until the executive fails to cure such acts or omissions within 20 business days following receipt of such notice. If the Board determines in its sole discretion that a cure is not possible and appropriate, the executive shall have no notice or cure rights before the agreement is terminated for cause.

For this purpose, good reason means the occurrence of any of the following (other than by reason of a termination of the executive for cause or disability or with the executive’s consent): (i) the authority, duties or responsibilities of the executive are significantly and materially reduced (including, without limitation, by reason of the elimination of the executive’s position or the failure to elect the executive to such position or by reason of a change in the reporting responsibilities to and of such position, or, following a change in control, by reason of a

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substantial reduction in the size of our company or other substantial change in the character or scope of our company’s operations); (ii) the annual base salary is materially reduced (except if such reduction occurs prior to a change in control and is part of an across-the-board reduction applicable to all senior level executives); (iii) the executive is required to change his regular work location to a location that is more than 75 miles from his regular work location prior to such change; or (iv) any other action or inaction that constitutes a material breach by us of the agreement. To exercise his right to terminate for good reason the executive must provide written notice of his belief that good reason exists within 90 days of the initial existence of the condition(s) giving rise to good reason. We shall have 20 days to remedy the good reason condition(s). If not remedied within that 20-day period, the executive may terminate his employment; provided, however, that such termination must occur no later than 180 days after the date of the initial existence of the condition(s) giving rise to the good reason.

Pursuant to the Armstrong and Wilson Agreements, in the event that: (i) we terminate the executive’s employment without cause in anticipation of, or pursuant to a notice of termination delivered to the executive within 24 months after, a change in control (as defined below); (ii) the executive terminates his employment for good reason pursuant to a notice of termination delivered to us in anticipation of, or within 24 months after, a change in control; or (iii) we fail to renew the agreement in anticipation of, or within 24 months after, a change in control:

(a) we shall pay to the executive, within 30 days following the executive’s separation from service (within the meaning of Code Section 409A and the regulations and other guidance promulgated thereunder), a lump-sum cash amount equal to: (x) two times the sum of (A) his salary then in effect and (B) 75% of his then current salary; plus (y) a bonus for the then current fiscal year equal to 75% of his salary (irrespective of whether performance objectives have been achieved); plus (z) if such notice is given within the first 12 months after October 1, 2011, then, the salary the executive should have been paid from the date of termination through the end of such 12-month period; and

(b) during the portion, if any, of the 24-month period commencing on the date of the executive’s separation from service that the executive is eligible to elect and elects to continue coverage for himself and his eligible dependents under our health plan pursuant to COBRA or a similar state law, we shall reimburse the executive for the difference between the amount the executive pays to effect and continue such coverage and the employee contribution amount that our active senior executive employees pay for the same or similar coverage.

For purposes of the Armstrong and Wilson Agreements, a change in control means the occurrence of any of the following: (i) a merger, consolidation, exchange, combination or other transaction involving our company and another entity (or our securities and such other entity) as a result of which the holders of all of the shares of our common stock outstanding prior to such transaction do not hold, directly or indirectly, shares of the outstanding voting securities of, or other voting ownership interest in, the surviving, resulting or successor entity in such transaction in substantially the same proportions as those in which they held the outstanding shares of our common stock immediately prior to such transaction; (ii) the sale, transfer, assignment or other disposition by us in one transaction or a series of transactions within any period of 18 consecutive calendar months (including, without limitation, by means of the sale of capital stock of any subsidiary or subsidiaries of our company) of assets which account for an aggregate of 50% or more of the consolidated revenues of our company and its subsidiaries, as determined in accordance with GAAP, for the fiscal year most recently ended prior to the date of such transaction (or, in the case of a series of transactions as described above, the first such transaction); provided, however, that no such transaction shall be taken into account if substantially all the proceeds thereof (whether in cash or in kind) are used after such transaction in the ongoing conduct by our company and/or its subsidiaries of the business conducted by our company and/or its subsidiaries prior to such transaction; (iii) our company is dissolved; or (iv) a majority of our directors are persons who were not members of the board as of the date which is the more recent of the date hereof and the date which is two years prior to the date on which such determination is made, unless the first election or appointment (or the first nomination for election by our shareholders) of each director who was not a member of the board on such date was approved by a vote of at least two-thirds of the board of directors in office prior to the time of such first election, appointment or nomination.

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Pursuant to the terms of the Armstrong and Wilson Agreement if the executive is a “disqualified individual” (as defined in Section 280G of the Code), and the severance or change of control payments and benefits, together with any other payments which the executive has the right to receive from the Company, would constitute a “parachute payment” (as defined in Section 280G of the Code), the payments provided hereunder shall be reduced (but not below zero) so that the aggregate present value of such payments received by the executive from the Company shall be $1.00 less than three times the executive’s “base amount” (as defined in Section 280G of the Code) and so that no portion of such payments received by the executive shall be subject to the excise tax imposed by Section 4999 of the Code.

The Armstrong and Wilson Agreements contain non-competition provisions that continue for 18 months following a termination of employment with us. In addition, the Armstrong and Wilson Agreements contain non-solicitation provisions that endure for a period of 24 months following the executive’s termination.

Overriding Royalty Agreements

On December 3, 2008, we entered into an amended and restated overriding royalty agreement with Mr. Cobb pursuant to which we agreed to pay Mr. Cobb a royalty of five cents ($0.05) per ton of all coal thereafter mined or extracted and subsequently sold from certain of our reserves. The term of the royalty began on November 22, 2006, and is set to continue until the later of: (i) November 22, 2026, or (ii) such time as all of the mineable and saleable coal from the subject properties has been mined. The agreement also states that the overriding royalty shall constitute an independent and enforceable obligation that shall run with the land and shall be binding on us, our respective assigns and successors, and any subsequent owner of the subject properties.

On December 3, 2008, we entered into an amended and restated overriding royalty agreement with Mr. Allen pursuant to which we agreed to pay Mr. Allen a royalty of five cents ($0.05) per ton of all coal thereafter mined or extracted and subsequently sold from certain of our reserves. The term of the royalty began on February 9, 2007, and is set to continue until the later of: (i) February 9, 2027, or (ii) such time as all of the mineable and saleable coal from the subject properties has been mined. The agreement also states that the overriding royalty shall constitute an independent and enforceable obligation that shall run with the land and shall be binding on us, our respective assigns and successors, and any subsequent owner of the subject properties.

Tax Considerations

In the past, we have not taken into consideration the tax consequences to employees and us when considering the types and levels of awards and other compensation granted to executives and directors. However, we anticipate that the compensation committee will consider these tax implications when determining executive compensation in the future.

Outstanding Equity Awards at 2012 Fiscal Year-End

The following table sets forth information on outstanding option and stock awards held by the named executive officers on December 31, 2012.

Name	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)(1)
J. Hord Armstrong, III		18,500	$	224,035
Martin D. Wilson		18,500		224,035
Kenneth E. Allen		18,500		224,035
David R. Cobb, P.E		18,500		224,035
J. Richard Gist		—		—

(1) The market value for our common stock is based on a valuation prepared by a third party specialist.

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2011 Long-Term Incentive Plan

Our board of directors has adopted the LTIP for our employees and directors, as well as for consultants and independent contractors who perform services for us. The LTIP is administered by the compensation committee, which has the authority to select recipients of awards and determine the type, size, terms and conditions of awards. The maximum aggregate number of shares of common stock available for issuance under the LTIP is 10% of our authorized shares of common stock. No awards were made under the LTIP in 2012 or 2011.

The LTIP provides for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, performance grants and other equity-based incentive awards to those who contribute significantly to our strategic and long-term performance objectives and growth, as the compensation committee may determine.

Except with respect to restricted stock awards and unless otherwise determined by the committee in its discretion, the recipient of an award has no rights as a stockholder until he or she receives a stock certificate or has his or her ownership entered into the books of the Company.

The compensation committee has the authority to administer the LTIP and may determine the type, number and size of the awards, the recipients of awards and the terms and conditions applicable to awards made under the LTIP. The committee may also generally amend the terms and conditions of awards, subject to certain restrictions.

The LTIP will terminate upon the earlier of the adoption of a board resolution terminating the LTIP or 10 years from its effective date.

The following is a brief summary of the types of awards available for issuance under the LTIP:

Stock Options

The committee may grant non-qualified and incentive stock options under the LTIP, provided that incentive stock options shall be granted to employees only. The exercise price of stock options must be no less than the fair market value of the common stock on the date of grant and expire ten years after the date of grant. The exercise price of incentive stock options granted to holders of at least 10% of the Company’s stock must be no less than 110% of such fair market value, and incentive stock options expire five years from the date of grant.

Stock Appreciation Rights

An award of a stock appreciation right entitles the recipient to receive, without payment, the number of shares of common stock having an aggregate value equal to the excess of the fair market value of one share of common stock at the time of exercise over the exercise price, times the number of shares of common stock subject to the award. Stock appreciation rights shall have an exercise price no less than the fair market value of the common stock on the date of grant.

Restricted Stock and Restricted Stock Units

In addition to other terms and conditions applicable to restricted stock and restricted stock unit awards, the compensation committee shall establish the restricted period applicable to such awards. The awards shall vest in one or more increments during the restricted period, which shall not be less than three years; provided, however, that this limitation shall not apply to awards granted to non-employee directors. As may be subject to additional conditions in the committee’s discretion, recipients of such awards shall have voting, dividend and other stockholder rights with respect to the awards from the date of grant.

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Performance Grants

Performance grants shall consist of a right that is (i) denominated in cash, common stock or any other form of award issuable under the LTIP, (ii) valued in accordance with the achievement of certain performance goals applicable to performance periods as the committee may establish, and (iii) payable at such time and in such form as the committee shall determine. The committee may reduce the amount of any performance grant in its discretion if it believes a reduction is necessary based on the recipient’s performance, comparisons with compensation received by similarly-situated recipients within the industry, the Company’s financial results, or any other factors deemed relevant.

Other Share-Based Awards

Other share-based awards may consist of any other right payable in, valued by, or otherwise related to common stock. The awards shall vest in one or more increments during a service period, which shall not be less than three years; provided, however, that this limitation shall not apply to awards granted to non-employee directors.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table shows the amount of our common stock beneficially owned as of October 1, 2013 by (i) each person who is known by us to own beneficially more than 5% of our common stock, (ii) each member of the board of directors, (iii) each of the named executive officers, and (iv) all members of the board of directors and the executive officers, as a group. The percentage of shares beneficially owned shown in the table is based upon 21,961,413 shares of common stock outstanding as of October 1, 2013.

A person is a “beneficial owner” of a security if that person has or shares voting or investment power over the security or if he or she has the right to acquire beneficial ownership within 60 days. Unless otherwise noted, these persons, to our knowledge, have sole voting and investment power over the shares listed. The following table includes equity awards granted to our executive officers on a discretionary basis. Except as otherwise noted, the principal address for the stockholders listed below is c/o Armstrong Energy, Inc., 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105.

	Shares Beneficially Owned(1)
	Number		Percent
J. Hord Armstrong, III		148,201		*
Martin D. Wilson		133,272		*
Kenneth E. Allen		18,500		*
David R. Cobb, P.E.		18,500		*
J. Richard Gist		18,500		*
Anson M. Beard, Jr.		—		—
James C. Crain		—		—
Richard F. Ford		—		—
Bryan H. Lawrence		—		—
Greg A. Walker		—		—
All directors and executive officers as a group (11 persons)		353,623		1.61	%
Yorktown VII Associates LLC(2)(3)		11,562,500		52.65	%
Yorktown VIII Associates LLC(2)(4)		6,012,500		27.38	%
Yorktown IX Associates LLC(2)(5)		2,775,000		12.64	%

* Less than 1%.

(1) Does not reflect any fractional shares beneficially owned.

(2) The address of this beneficial owner is 410 Park Avenue, 19th Floor, New York, New York 10022.

(3) These shares are held of record by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP is the sole general partner of Yorktown Energy Partners VII, L.P. Yorktown VII Associates LLC is the sole general partner of Yorktown VII Company LP. As a result, Yorktown VII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP and Yorktown VII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VII, L.P. in excess of their pecuniary interests therein.

(4) These shares are held of record by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP is the sole general partner of Yorktown Energy Partners VIII, L.P. Yorktown VIII Associates LLC is the sole general partner of Yorktown VIII Company LP. As a result, Yorktown VIII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP and Yorktown VIII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VIII, L.P. in excess of their pecuniary interests therein.

(5) These shares are held of record by Yorktown Energy Partners IX, L.P. Yorktown IX Company LP is the sole general partner of Yorktown Energy Partners IX, L.P. Yorktown IX Associates LLC is the sole general partners of Yorktown IX Company LP. As a result, Yorktown IX Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners IX, L.P. Yorktown IX Company LP and Yorktown IX Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners IX, L.P. in excess of their pecuniary interests therein.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Sale of Coal Reserves

Armstrong Energy is majority-owned by Yorktown. Effective February 9, 2011, Armstrong Energy and several of its affiliates participated in a transaction with Armstrong Resource Partners, an entity also majority-owned by Yorktown, and several of its affiliates. In 2009 and 2010, Armstrong Energy borrowed an aggregate principal amount of $44.1 million from Armstrong Resource Partners. The borrowings were evidenced by promissory notes in favor of Armstrong Resource Partners in the principal amounts of $11.0 million on November 30, 2009, $9.5 million on March 31, 2010, $12.6 million on May 26, 2010 and $11.0 million on November 9, 2010, respectively. The promissory notes had a fixed interest rate of 3%. In addition, contingent interest equal to 7% of revenue would be accrued to the extent it exceeds the fixed interest amount. No payments of principal or interest were due until the earliest of May 31, 2014, or the 91st day after the secured promissory notes had been paid in full. In consideration for Armstrong Resource Partners making these loans, Armstrong Energy granted it a series of options to acquire interests in the majority of coal reserves then held by us in Muhlenberg and Ohio Counties. On February 9, 2011, Armstrong Resources Partners exercised its options, paid Armstrong Energy an additional $5.0 million in cash and offset $12.0 million in accrued advance royalty payments owed by Armstrong Energy to Ceralvo Resources, LLC, and thereby acquired a 39.45% undivided interest as a joint tenant in common with Armstrong Energy’s subsidiaries in the aforementioned coal reserves. The aggregate amount paid by Armstrong Resource Partners to acquire its interest was the equivalent of approximately $69.5 million.

Lease Agreements

On February 9, 2011, Armstrong Energy’s subsidiary, Armstrong Coal, entered into a number of coal mining lease agreements with Western Mineral (a subsidiary of Armstrong Resource Partners) and two of Armstrong Energy’s wholly-owned subsidiaries. Pursuant to these agreements, Western Mineral granted Armstrong Coal a lease to its 39.45% undivided interest in certain mining properties and a license to mine coal on those properties that it had acquired in the above-described option transaction. The initial term of the agreement is ten years, and it renews for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. Armstrong Coal must pay the lessors a production royalty equal to 7% of the sales price of the coal it mines from the properties.

On February 9, 2011, Armstrong Coal also entered into a lease and sublease agreement with Ceralvo Holdings, LLC, a subsidiary of Armstrong Resource Partners (“Ceralvo Holdings”). Pursuant to this agreement, Ceralvo Holdings granted Armstrong Coal leases and subleases, as applicable, to the Elk Creek Reserves and an exclusive license to mine coal on those properties. The initial term of the agreement is ten years, and it automatically renews for ten one-year terms and thereafter until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. Armstrong Coal must pay the lessor a production royalty equal to 7% of the sales price of the coal it mines from the properties. In addition, Armstrong Coal must pay any royalties due for coal leased (not owned in fee) by Ceralvo Holdings. As of June 30, 2013, Armstrong Energy has paid $12 million of advance royalties under the lease, of which $1.7 million is recoupable against future production royalties. See “Description of Other Indebtedness.”

Royalty Deferment and Option Agreement

Effective February 9, 2011, Armstrong Coal, Western Diamond and Western Land, each of which is a wholly owned subsidiary of Armstrong Energy, entered into a Royalty Deferment and Option Agreement with Western Mineral and Ceralvo Holdings, both wholly owned subsidiaries of Armstrong Resource Partners. Pursuant to this agreement, Western Mineral and Ceralvo Holdings agreed to grant to Armstrong Coal and its affiliates the option to defer payment, in whole or in part, of their pro rata share of the 7% production royalty

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described under “Business—Our Mining Operations” above. In consideration for the granting of the option to defer these payments, Armstrong Coal and its affiliates granted to Western Mineral the option to acquire an additional undivided interest in certain of the coal reserves held by Armstrong Energy, Inc. in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which Armstrong Coal and its affiliates would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.

Since this agreement was executed in February 2011, Armstrong Energy and its subsidiaries have not paid any cash royalties to Armstrong Resource Partners but have transferred reserves with a total fair market value, at the time of transfer, of $10.6 million. During this period, Armstrong Resource Partners has also acquired additional reserves from the Company for cash of $20.0 million. If Armstrong Energy continues to satisfy its royalty obligations to Armstrong Resource Partners by additional transfers of coal reserves, Armstrong Energy expects that it will transfer all of its existing fee-owned reserves to Armstrong Resource Partners by 2018.

Administrative Services Agreement

Effective as of January 1, 2011, Armstrong Energy entered into an Administrative Services Agreement with Armstrong Resource Partners (f/k/a Elk Creek LP) and its general partner, Elk Creek GP, LLC, pursuant to which Armstrong Energy will provide Armstrong Resource Partners with general administrative and management services, including, but not limited to, human resources, information technology, financial and accounting services and legal services. Pursuant to the agreement, Armstrong Resource Partners was to pay Armstrong Energy, until December 31, 2011, (i) a monthly fee equal to $60,000 per month, as consideration for the use of Armstrong Energy’s employees and services, and (ii) an aggregate annual fee equal to $279,996 per year, as consideration for certain shared fixed costs, including, but not limited to, overhead expenses, an office lease and telephone and office equipment leases. The annual and monthly fees are subject to adjustment annually in accordance with the terms of the Administrative Services Agreement. For 2011, the fees due to Armstrong Energy were adjusted such that the aggregate amount of the annual and monthly fees paid to Armstrong Energy pursuant to the Administrative Services Agreement was $720,000. For 2012, Armstrong Resource Partners paid Armstrong Energy $750,000 under the Administrative Services Agreement, and for 2013, the parties have agreed that the aggregate amount of the fees due to Armstrong Energy will be $775,000. Armstrong Resource Partners shall also be liable for all taxes that are applicable from time to time to the services Armstrong Energy provides on its behalf.

Investment in Ram Terminals, LLC

On May 26, 2011, Armstrong Energy made a capital contribution in Ram in the amount of $2.47 million. Upon amendment of the Limited Liability Company Agreement of Ram (the “Operating Agreement”) on July 2, 2012, Armstrong Energy’s equity interest in Ram constituted 5.0%. The remaining membership interest is owned by Yorktown Energy Partners IX, L.P., a fund managed by Yorktown. Armstrong Energy is majority-owned by Yorktown. Yorktown Energy Partners IX, L.P. will provide the funds for future capital expenditures related to the development of the site. Armstrong Energy will be involved in the initial design and construction of the terminal and will provide accounting and bookkeeping assistance to Ram. Pursuant to the Operating Agreement, Armstrong Energy will not be liable for the debts, liabilities and other obligations of Ram.

Western Diamond and Western Land Coal Reserves Sale Agreement

On October 11, 2011, two of our subsidiaries, Western Diamond and Western Land (together, the “Sellers”), entered into an agreement with Western Mineral, a subsidiary of Armstrong Resource Partners, pursuant to which the Sellers agreed to sell an additional partial undivided interest in substantially all of the coal reserves and real property owned by the Sellers previously subject to the options exercised by Armstrong Resource Partners on February 9, 2011 (see “—Sale of Coal Reserves”), other than any of Sellers’ real property and related mining rights associated with the Parkway mine.

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Agreement to Enter into Voting and Stockholders’ Agreement

On October 1, 2011, we entered into an agreement to enter into a voting and stockholders’ agreement with all of our stockholders. Pursuant to the terms of this agreement, as amended, we and our stockholders agreed to enter into a voting and stockholders’ agreement in the event that an underwritten offering to the public pursuant to which equity securities of the Company shall be authorized and approved for listing on NASDAQ is not completed on or before January 1, 2014;provided, however, that the deadline may be extended to a date mutually agreed upon by Yorktown and us, which in no event shall be later than July 1, 2014.

Sale of Series A Convertible Preferred Stock

In January 2012, we sold 300,000 shares of Series A convertible preferred stock to Yorktown Energy Partners IX, L.P., one of the investment funds managed by Yorktown Partners LLC, in exchange for $30.0 million. The holders of Series A convertible preferred stock vote together as a single class with the holders of common stock, with each share of Series A convertible preferred stock having one vote per share, on all matters submitted to a vote of the holders of common stock, except that when the Series A convertible preferred stock and the common stock vote together as a single class, then each holder of shares of Series A convertible preferred stock shall be entitled to the number of votes with respect to such holder’s Series A convertible preferred stock equal to the number of whole shares into which such shares of Series A convertible preferred stock would have been converted under the provisions of the certificate of designations at the conversion price then in effect on the record date for determining stockholders entitled to vote on such matters or, if no record date is specified, as of the date of such vote. As a result of the transaction, Yorktown Energy Partners IX, L.P. may have been deemed to be the beneficial owner of more than 5% of our voting securities. In December 2012, we entered into a share exchange agreement with Yorktown, whereby all of the outstanding shares of Series A convertible preferred stock converted into an aggregate of 2,775,000 shares of our common stock. The fair value of our common stock on the date of conversion, based on a third-party valuation, was $12.11 per share. See “—Share Exchange Agreement.”

Share Exchange Agreement

In December 2012, we entered into a share exchange agreement (the “Share Exchange Agreement”) with Yorktown Energy Partners IX, L.P., one of the investment funds managed by Yorktown Partners LLC. Yorktown Energy Partners IX, L.P. was the owner of 300,000 shares of our Series A convertible preferred stock, which represented all of the outstanding Series A convertible preferred stock. Pursuant to the Share Exchange Agreement, all of the outstanding shares of Series A convertible preferred stock held by Yorktown Energy Partners IX, L.P. were converted into an aggregate of 2,775,000 shares of our common stock. The fair value of our common stock on the date of conversion, based on a third-party valuation, was $12.11 per share.

Membership Interest Purchase Agreement

In December 2011, Armstrong Energy entered into a Membership Interest Purchase Agreement with Armstrong Resource Partners pursuant to which Armstrong Energy agreed to sell to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. In exchange for the agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners paid Armstrong Energy $20.0 million. In addition to the cash paid, certain amounts due by us to Armstrong Resource Partners totaling $5.7 million were forgiven by Armstrong Resource Partners, which resulted in aggregate consideration of $25.7 million. The partial undivided interest in additional reserves must be transferred to Armstrong Resource Partners within 90 days after delivery of the purchase price. This transaction, which closed on March 30, 2012, resulted in the transfer by us of an 11.36% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease.

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April 2013 Transfer of Additional Partial Undivided Interest in Reserves

In April 2013, pursuant to the Royalty Deferment and Option Agreement, Armstrong Energy sold to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. See “—Royalty Deferment and Option Agreement.” In exchange for the agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners forgave certain amounts due by us to Armstrong Resource Partners, including cash royalty payments owed to Armstrong Resource Partners, offset by amounts due to us pursuant to the Administrative Services Agreement, totaling approximately $4.9 million. This transaction resulted in the transfer by us of a 2.59% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. As a result of this transaction, Armstrong Resource Partners’ undivided interest in certain of our land and mineral reserves in Muhlenberg and Ohio Counties increased to 53.4%. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease.

Credit and Collateral Support Fee, Indemnification and Right of First Refusal Agreement

Effective February 9, 2011, we and several of our affiliates entered into the Credit and Collateral Support Fee, Indemnification and Right of First Refusal Agreement with Armstrong Resource Partners and several of its affiliates. In exchange for Armstrong Resource Partners and its affiliates agreeing to act as guarantors on our 2011 Credit Facility and to provide collateral support thereunder, we agreed to pay Armstrong Resource Partners a credit and collateral support fee in an amount equal to 1% per annum of the principal amount outstanding under our 2011 Credit Facility. Pursuant to the terms of the Credit and Collateral Support Fee, Indemnification and Right of First Refusal Agreement, such credit and collateral support fee, totaling $1.2 million and $1.2 million for 2012 and 2011, respectively, was accrued and paid following repayment in full of all indebtedness and obligations under the 2011 Credit Facility in December 2012. The Credit and Collateral Support Fee, Indemnification and Right of First Refusal Agreement was terminated in December 2012 in connection with termination of the 2011 Credit Facility.

Thoroughbred Loan

On June 28, 2013, Thoroughbred, an entity wholly owned by Yorktown, acquired approximately 65 million tons of fee-owned underground coal reserves and 40 million tons of leased underground coal reserves from Peabody. The acquired coal reserves are located in Muhlenberg and McLean Counties of Kentucky, contiguous to Armstrong Energy’s reserves. It is intended that these reserves will be leased to us in exchange for a production royalty.

In connection with Thoroughbred’s acquisition of these reserves, we loaned Thoroughbred $17.5 million, which was repaid in July 2013. The proceeds of the loan, which was evidenced by a promissory note, were used to make a portion of the down payment to Peabody for the reserves.

Agreement to Enter into Voting and Stockholders’ Agreement

On October 1, 2011, we entered into an agreement to enter into a voting and stockholders’ agreement with all of our stockholders. Pursuant to the terms of this agreement, as amended, we and our stockholders agreed to enter into a voting and stockholders’ agreement in the event that an underwritten offering to the public pursuant to which equity securities of the Company shall be authorized and approved for listing on NASDAQ is not completed on or before January 1, 2014; provided, however, that the deadline may be extended to a date mutually agreed upon by Yorktown and us, which in no event shall be later than July 1, 2014.

Registration Rights Agreement

In April 2012, Armstrong Energy entered into a registration rights agreement with Yorktown and Armstrong Energy’s other existing stockholders, including certain members of Armstrong Energy’s management team,

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pursuant to which Armstrong Energy granted certain demand and “piggyback” registration rights to such stockholders.

Under the registration rights agreement, such stockholders have the right to require Armstrong Energy to file a shelf registration statement for the public sale of all of the shares of common stock owned by them;provided, however, that Armstrong Energy will not have any obligation to file any such shelf registration statement at any time (i) on or before the date that is 12 months after the closing of the Company’s initial public offering, (ii) on or before 90 days after any other underwritten public offering of our equity securities, or (iii) if Armstrong Energy is not otherwise eligible at such time to file such shelf registration statement on Form S-3. In addition, if Armstrong Energy sells any shares of its common stock in a registered underwritten offering, Yorktown and Armstrong Energy’s other existing stockholders have the right to include its or their shares in that offering. The underwriters of any such offering will have the right to limit the number of shares to be included in such sale.

Armstrong Energy will pay all expenses relating to any such registration, except for underwriters’ or brokers’ commission or discounts. The securities covered by the registration rights agreement will no longer be registrable under the registration rights agreement if they have been sold to the public either pursuant to a registration statement or under Rule 144 promulgated under the Securities Act.

Madisonville Office Lease

Beginning in 2008, pursuant to an oral agreement, Armstrong Coal leased from David R. Cobb, one of our executive officers, and Rebecca K. Cobb, Mr. Cobb’s spouse, certain property to be used by Armstrong Coal as its office space in Madisonville, Kentucky, and the use of Mr. Cobb’s employees. Armstrong Coal agreed to pay $4,700 per month in exchange for the leased property, equipment, furniture, supplies and use of employees. On August 1, 2009, Armstrong Coal entered into a written lease agreement with Mr. and Mrs. Cobb regarding the subject matter of the oral agreement. The terms of the written lease were the same as the terms of the prior oral agreement. The lease term ends on July 31, 2014, but automatically renews for additional 12-month periods unless either party gives written notice of termination no later than 30 days prior to the end of the term or a renewal term.

Loans to Executive Officers and Loan Repayment

During the fiscal years ended December 31, 2006 through 2008, our Predecessor entered into certain transactions with J. Hord Armstrong, III, its Chairman and Chief Executive Officer, and Martin D. Wilson, its President and member of its board of managers, pursuant to which our Predecessor loaned Messrs. Armstrong and Wilson money in connection with their purchase of shares of common stock of our Predecessor. In a series of separate transactions, each of Messrs. Armstrong and Wilson executed promissory notes in favor of our Predecessor in connection with his purchase of shares of common stock, as follows:

	Date		Number of Shares Purchased (1)		Amount of Loan  from Predecessor
J. Hord Armstrong, III		September 28, 2006		23,125	$	250,000
		December 6, 2006		23,125	$	250,000
		March 7, 2007		46,250	$	500,000
		June 6, 2008		11,563	$	125,000
Martin D. Wilson		September 28, 2006		23,125	$	250,000
		December 6, 2006		23,125	$	250,000
		March 7, 2007		46,250	$	500,000

(1) In connection with the Reorganization on October 1, 2011, each of our Predecessor’s issued and outstanding limited liability company units was converted into 9.25 shares of our common stock. In accordance with SEC Staff Accounting Bulletin Topic 4.6, all share information has been retroactively adjusted to reflect the common stock conversion.

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Each of the promissory notes was secured by the shares purchased in each of the transactions, including the shares purchased with cash and those financed by the promissory notes. In addition, each of the promissory notes provided that interest on the unpaid principal balance accrued at 6.00% per annum. Interest was not required to be paid until repayment of the loan.

The largest aggregate amount of principal outstanding and the amount of principal and interest paid on these loans for the periods presented below are as follows:

	Fiscal Year Ended December 31,
(in thousands)	2010		2011		2012
J.HordArmstrong, III
Largest Aggregate Amount of Principal Outstanding	$	1,125	$	1,125	$	—
Amount of Principal Paid		—		—		—
Amount of Interest Paid		—		—		—
MartinD.Wilson
Largest Aggregate Amount of Principal Outstanding	$	1,000	$	1,000	$	—
Amount of Principal Paid		—		—		—
Amount of Interest Paid		—		—		—

Effective September 30, 2011, each of Messrs. Armstrong and Wilson entered into a Unit Repurchase Agreement with our Predecessor, pursuant to which our Predecessor repurchased a number of membership units from Messrs. Armstrong and Wilson in full satisfaction of the loans described above. Pursuant to Mr. Armstrong’s Unit Repurchase Agreement, our Predecessor repurchased 78,424 shares of Mr. Armstrong’s common stock in satisfaction of his total outstanding debt as of September 30, 2011 of approximately $1.43 million. Pursuant to Mr. Wilson’s Unit Repurchase Agreement, our Predecessor repurchased 70,228 shares of Mr. Wilson’s common stock in satisfaction of his total outstanding debt as of September 30, 2011 of approximately $1.28 million. Effective September 30, 2011, these loans were repaid in full.

Policies and Procedures for Related Party Transactions

The conflicts committee must review and approve all transactions between Armstrong Energy and any related person that are required to be disclosed pursuant to Item 404 of Regulation S-K. “Related person” and “transaction” shall have the meanings given to such terms in Item 404 of Regulation S-K, as amended from time to time. In determining whether to approve or ratify a particular transaction, the conflicts committee will take into account any factors it deems relevant.

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DESCRIPTION OF OTHER INDEBTEDNESS

The following generally describes the Revolving Credit Facility but does not purport to be complete and is qualified in its entirety by reference to the provisions of the various agreements related thereto.

General

On December 21, 2012, we entered into the Revolving Credit Facility, an asset-based revolving credit facility that provides for a five-year $50.0 million revolving credit facility that will expire on December 21, 2017. Borrowings under our Revolving Credit Facility may not exceed a borrowing base, as defined in the agreement. In addition, the Revolving Credit Facility includes a $10.0 million letter of credit sub-facility and a $5.0 million swingline loan sub-facility. All borrowings under our Revolving Credit Facility are subject to the satisfaction of customary conditions, including the absence of a default, the accuracy of representations and warranties and certain closing conditions. As of December 31, 2012 and June 30, 2013, there were no borrowings outstanding under the Revolving Credit Facility and we had $20.0 million and $19.7 million, respectively, available for borrowing under the Revolving Credit Facility.

Interest and Fees

Borrowings under our Revolving Credit Facility bear interest, at our option, at a rate based on (i) LIBOR, plus a margin ranging from 3.5% to 4.0%, or (ii) a base rate, plus a margin ranging from 2.5% to 3.0%. Margins may be increased by 2.0% per annum during the existence of any event of default. We are also required to pay certain other fees with respect to our Revolving Credit Facility, including (i) an unused commitment fee ranging from 0.50% to 0.375% in respect of unutilized commitments, (ii) a fronting fee equal to 0.25% per annum of the amount of outstanding letters of credit and (iii) customary annual administration fees.

Collateral and Guarantors

Our Revolving Credit Facility is secured by substantially all of our and our subsidiaries’ assets (other than certain excluded assets), with (i) a first priority lien on the ABL Priority Collateral and (ii) a second priority lien on the Notes Priority Collateral. See “Description of Exchange Notes—Intercreditor Agreement.” Our Revolving Credit Facility is guaranteed on a full and unconditional basis by the same subsidiaries of the Company that guarantee the Notes.

Restrictive Covenants and Other Matters

Our Revolving Credit Facility includes customary covenants that, subject to certain exceptions, restrict our ability and the ability of our subsidiaries to, among other things, incur indebtedness (including capital leases), create liens on assets, make investments, loans, guarantees, advances or acquisitions, pay dividends and distributions, liquidate, merge or consolidate, divest assets, engage in certain transactions with affiliates, create joint ventures or subsidiaries, change the nature of our business, change our fiscal year, issue stock, amend organizational documents, make capital expenditures and provide negative pledges on assets. In addition, at any time when (i) undrawn availability is less than the greater of (a) $10 million or (b) an amount equal to 20% of the borrowing base or (ii) an event of default has occurred and is continuing, we will be required to maintain a fixed charge coverage ratio, calculated as of the end of each calendar month for the 12 months then ended, greater than 1.0 to 1.0.

Our Revolving Credit Facility also contains customary affirmative covenants and events of default. If an event of default occurs, the lenders under our Revolving Credit Facility will be entitled to take various actions, including the acceleration of amounts due under our Revolving Credit Facility and all actions permitted to be taken by a secured creditor.

Prepayments and Commitment Reductions

Voluntary prepayments and commitment reductions are permitted, in whole or in part, in minimum amounts without premium or penalty, other than customary breakage costs with respect to LIBOR loans.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

Pursuant to the registration rights agreement, we agreed to prepare and file with the SEC a registration statement with respect to an offer to exchange the Outstanding Notes for Exchange Notes registered under the Securities Act.

Following the completion of the exchange offer, holders of Outstanding Notes not tendered will not have any further registration rights other than as set forth in the paragraphs below, and, subject to certain exceptions, the Outstanding Notes will continue to be subject to certain restrictions on transfer.

Subject to certain conditions, including the representations set forth below, the Exchange Notes will be issued without a restrictive legend and generally may be reoffered and resold without registration under the Securities Act. In order to participate in the exchange offer, a holder must represent to us in writing, or be deemed to represent to us in writing, among other things, that:

• the holder is acquiring the Exchange Notes in its ordinary course of business;

• at the time of the commencement and consummation of the exchange offer, the holder has not entered into any arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the Exchange Notes in violation of the provisions of the Securities Act;

• if the holder is an “affiliate” of ours within the meaning of Rule 405 of the Securities Act, it will comply with the registration and prospectus delivery requirements of the Securities Act, to the extent applicable;

• if the holder is not a broker-dealer, that it is not engaged in, and does not intend to engage in, the distribution of the Exchange Notes; and

• if such holder is a broker-dealer that acquired the Exchange Notes for its own account in exchange for the Outstanding Notes that were acquired as a result of market-making activities or other trading activities, that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resales of the Exchange Notes.

Under certain circumstances specified in the registration rights agreement, we may be required to file a “shelf” registration statement covering resales of the Outstanding Notes pursuant to Rule 415 under the Securities Act.

Resale of the Exchange Notes

Based on an interpretation by the SEC’s staff set forth in no-action letters issued to third parties unrelated to us, we believe that, with the exceptions set forth below, the Exchange Notes issued in the exchange offer may be offered for resale, resold and otherwise transferred by the holder of Exchange Notes without compliance with the registration and prospectus delivery requirements of the Securities Act, unless the holder:

• is an “affiliate” of ours within the meaning of Rule 405 under the Securities Act;

• is a broker-dealer that purchased Outstanding Notes directly from us for resale under Rule 144A, Regulation S or any other available exemption under the Securities Act;

• acquired the Exchange Notes other than in the ordinary course of the holder’s business;

• has an arrangement or understanding with any person to engage in a distribution of the Exchange Notes;

• is engaged in, or intends to engage in, a distribution of the Exchange Notes; or

• is prohibited by any law or policy of the SEC from participating in the exchange offer.

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Any holder who is an affiliate of ours, is engaging in, or intends to engage in, or has any arrangement or understanding with any person to participate in, a distribution of the Exchange Notes, or is not acquiring the Exchange Notes in the ordinary course of its business cannot rely on this interpretation by the SEC’s staff and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction. Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer, where such Outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will comply with the applicable provisions of the Securities Act (including, but not limited to, delivering a prospectus in connection with any resale of such Exchange Notes). See “Plan of Distribution.” Broker-dealers who acquired Outstanding Notes directly from us and not as a result of market-making activities or other trading activities may not rely on the staff’s interpretations discussed above, and must comply with the prospectus delivery requirements of the Securities Act in order to sell the Exchange Notes.

Terms of the Exchange Offer

Upon the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal, we will accept any and all Outstanding Notes validly tendered and not validly withdrawn prior to 5:00 p.m., New York City time, on November 13, 2013, or such date and time to which we extend the exchange offer. We will issue $1,000 in principal amount of Exchange Notes in exchange for each $1,000 principal amount of Outstanding Notes accepted in the exchange offer. Holders may tender some or all of their Outstanding Notes pursuant to the exchange offer.

Outstanding Notes may be tendered only in a denomination equal to $2,000 and integral multiples of $1,000 in excess thereof. The Exchange Notes will evidence the same debt as the Outstanding Notes and will be issued under the terms of, and entitled to the benefits of, the indenture relating to the Outstanding Notes.

As of the date of this prospectus, $200.0 million in aggregate principal amount of Outstanding Notes are outstanding. This prospectus, together with the letter of transmittal, is being sent to the registered holders of the Outstanding Notes. There will be no fixed record date for determining registered holders of Outstanding Notes that are entitled to participate in the exchange offer. We intend to conduct the exchange offer in accordance with the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC promulgated under the Securities Act and the Exchange Act.

We will be deemed to have accepted validly tendered Outstanding Notes when, as and if we have given oral or written notice thereof to Wells Fargo Bank, National Association, which is acting as the exchange agent. The exchange agent will act as agent for the tendering holders for the purpose of receiving the Exchange Notes from us. If any tendered Outstanding Notes are not accepted for exchange because of an invalid tender, or the occurrence of certain other events set forth under the heading “—Conditions to the Exchange Offer,” any such unaccepted Outstanding Notes will be returned to the tendering holder of those Outstanding Notes as soon as reasonably practicable after the expiration or termination of the exchange offer.

Holders who tender Outstanding Notes in the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of Outstanding Notes in the exchange offer. We will pay all charges and expenses, other than certain applicable taxes, applicable to the exchange offer. See “—Fees and Expenses” and “—Transfer Taxes.”

Expiration Date; Extensions; Amendments

The expiration date and time shall be 5:00 p.m., New York City time, on November 13, 2013, unless we, in our sole discretion, extend the exchange offer, in which case the expiration date shall be the latest date and time to which the exchange offer is extended. In order to extend the exchange offer, we will notify the exchange agent

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by written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. We reserve the right, in our sole discretion:

• to delay accepting any validly tendered Outstanding Notes, to extend the exchange offer or, if any of the conditions set forth under “—Conditions to the Exchange Offer” shall not have been satisfied, to terminate the exchange offer, by giving written notice of that delay, extension or termination to the exchange agent, or

• to amend the terms of the exchange offer in any manner.

In the event of a material change in the offer, including the waiver of a material condition, the Company will extend the offer period if necessary so that at least five business days remain in the offer following notice of the material change. Any delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by a public announcement thereof.

Procedures for Tendering

When a holder of Outstanding Notes tenders, and we accept such Notes for exchange pursuant to that tender, a binding agreement between us and the tendering holder is created, subject to the terms and conditions set forth in this prospectus and the accompanying letter of transmittal. Except as set forth below, a holder of Outstanding Notes who wishes to tender such Notes for exchange must, on or prior to the expiration date:

• transmit a properly completed and duly executed letter of transmittal, including all other documents required by such letter of transmittal, to Wells Fargo Bank, National Association, which will act as the exchange agent, at the address set forth below under the heading “—Exchange Agent”; or

• comply with DTC’s ATOP procedures described below.

In addition, either:

• the exchange agent must receive the certificates for the Outstanding Notes and the letter of transmittal prior to 5:00 p.m., New York City time, on the expiration date;

• the exchange agent must receive, prior to 5:00 p.m., New York City time, on the expiration date, a timely confirmation of the book-entry transfer of the Outstanding Notes being tendered, along with the letter of transmittal or an agent’s message; or

• the holder must comply with the guaranteed delivery procedures described below.

The term “agent’s message” means a message, transmitted by DTC and received by the exchange agent and forming a part of a book-entry transfer, or “book-entry confirmation,” which states that DTC has received an express acknowledgement from the tendering participant, which acknowledgment states that such participant has received the letter of transmittal and agrees to be bound by the terms of, and makes the representations and warranties contained in, the letter of transmittal, and that we may enforce the letter of transmittal against such participant.

The method of delivery of the Outstanding Notes, the letters of transmittal and all other required documents is at the election and risk of the holders. We recommend that instead of delivery by mail, holders use an overnight or hand delivery service, properly insured. In all cases, you should allow sufficient time to assure timely delivery. No letters of transmittal or Outstanding Notes should be sent directly to us.

Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed by an eligible institution unless the Outstanding Notes surrendered for exchange are tendered:

• by a registered holder of the Outstanding Notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

• for the account of an eligible institution.

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An “eligible institution” is a member firm of a registered national securities exchange, a member of the Financial Industry Regulatory Authority, Inc., a commercial bank or trust company having an office or correspondent in the United States or another “eligible guarantor institution” within the meaning of Rule 17Ad-15 under the Exchange Act.

If Outstanding Notes are registered in the name of a person other than the signer of the letter of transmittal, the Outstanding Notes surrendered for exchange must be endorsed or be accompanied by a written instrument or instruments of transfer or exchange in satisfactory form to the exchange agent and as determined by us in our sole discretion, duly executed by the registered holder with the holder’s signature guaranteed by an eligible institution.

We will determine all questions as to the validity, form, eligibility (including time of receipt) and acceptance of Outstanding Notes tendered for exchange in our sole discretion. Our determination will be final and binding. We reserve the absolute right to:

• reject any and all tenders of any Outstanding Note improperly tendered;

• refuse to accept any Outstanding Note if, in our judgment or the judgment of our counsel, acceptance of the Outstanding Note may be deemed unlawful; and

• waive any defects or irregularities or conditions of the exchange offer as to any particular Outstanding Note based on the specific facts.

Notwithstanding the foregoing, we do not expect to treat any holder of Outstanding Notes differently from other holders to the extent they present the same facts or circumstances.

Our interpretation of the terms and conditions of the exchange offer as to any particular Outstanding Notes either before or after the expiration date, including the letter of transmittal and the instructions to it, will be final and binding on all parties. Holders must cure any defects and irregularities in connection with tenders of Outstanding Notes for exchange within such reasonable period of time as we will determine, unless we waive such defects or irregularities.

Neither we, the exchange agent nor any other person shall be under any duty to give notification of any defect or irregularity with respect to any tender of Outstanding Notes for exchange, nor shall any of us incur any liability for failure to give such notification.

If trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity sign the letter of transmittal or any Outstanding Notes or separate written instructions of transfer or exchange, these persons should so indicate when signing, and you must submit proper evidence satisfactory to us of those persons’ authority to so act unless we waive this requirement.

By tendering, each holder will represent to us that the person acquiring Exchange Notes in the exchange offer, whether or not that person is the holder:

• is not an “affiliate” of ours as defined under Rule 405 of the Securities Act;

• is obtaining them in the ordinary course of its business; and

• at the time of the commencement of the exchange offer neither the holder nor, to the knowledge of such holder, that other person receiving Exchange Notes from such holder is engaged in, intends to engage in or has any arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the Exchange Notes issued in the exchange offer.

If any holder or any other person receiving Exchange Notes from such holder is an “affiliate” of ours as defined under Rule 405 of the Securities Act, is not acquiring the Exchange Notes in the ordinary course of business, or is engaged in or intends to engage in or has an arrangement or understanding with any person to

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participate in a distribution (within the meaning of the Securities Act) of the Notes to be acquired in the exchange offer, the holder or any other person:

• may not rely on applicable interpretations of the staff of the SEC; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Each broker-dealer that acquired its Outstanding Notes as a result of market-making activities or other trading activities, and thereafter receives Exchange Notes issued for its own account in the exchange offer, must acknowledge that it will comply with the applicable provisions of the Securities Act (including, but not limited to, delivering this prospectus in connection with any resale of such Exchange Notes issued in the exchange offer). The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. See “Plan of Distribution” for a discussion of the exchange and resale obligations of broker-dealers.

Acceptance of Outstanding Notes for Exchange; Delivery of Exchange Notes Issued in the Exchange Offer

Upon satisfaction or waiver of all the conditions to the exchange offer, promptly after the expiration date or termination of the exchange offer, we either will accept all Outstanding Notes properly tendered and issue Exchange Notes registered under the Securities Act in exchange for the tendered Outstanding Notes, or return any tendered Outstanding Notes not so exchanged. We will return any Outstanding Notes that we do not accept for exchange promptly after expiration or termination of the exchange offer. For purposes of the exchange offer, we shall be deemed to have accepted properly tendered Outstanding Notes for exchange when, as and if we have given oral or written notice to the exchange agent, with written confirmation of any oral notice to be given promptly thereafter, and complied with the applicable provisions of the registration rights agreement. See “—Conditions to the Exchange Offer” for a discussion of the conditions that must be satisfied before we accept any Outstanding Notes for exchange.

For each Outstanding Note accepted for exchange, the holder will receive an Exchange Note registered under the Securities Act having a principal amount equal to that of the surrendered Outstanding Note. Registered holders of Exchange Notes issued in the exchange offer on the relevant record date for the first interest payment date following the consummation of the exchange offer will receive interest accruing from the most recent date on which interest has been paid or, if no interest has been paid, from the issue date of the Outstanding Notes. Holders of Exchange Notes will not receive any payment in respect of accrued interest on Outstanding Notes otherwise payable on any interest payment date, the record date for which occurs on or after the consummation of the exchange offer. Under the registration rights agreement, we may be required to make payments of additional interest or liquidated damages to the holders of the Outstanding Notes under circumstances relating to the timing of the exchange offer.

In all cases, we will issue Exchange Notes for Outstanding Notes that are accepted for exchange only after the exchange agent timely receives:

• certificates for such Outstanding Notes or a timely book-entry confirmation of such Outstanding Notes into the exchange agent’s account at DTC;

• a properly completed and duly executed letter of transmittal or an agent’s message;

• and all other required documents.

If for any reason set forth in the terms and conditions of the exchange offer we do not accept any tendered Outstanding Notes, or if a holder submits Outstanding Notes for a greater principal amount than the holder desires to exchange, we will return such unaccepted or nonexchanged Notes without cost to the tendering holder. In the case of Outstanding Notes tendered by book-entry transfer into the exchange agent’s account at DTC, the nonexchanged Notes will be credited to an account maintained with DTC.

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We will return the Outstanding Notes or have them credited to DTC, promptly after the expiration or termination of the exchange offer.

Book-Entry Delivery Procedures

Promptly after the date of this prospectus, the exchange agent will establish an account with respect to the Outstanding Notes at DTC and, as the book-entry transfer facility, for purposes of the exchange offer. Any financial institution that is a participant in the book-entry transfer facility’s system may make book-entry delivery of the Outstanding Notes by causing the book-entry transfer facility to transfer those Outstanding Notes into the exchange agent’s account at the facility in accordance with the facility’s procedures for such transfer. To be timely, book-entry delivery of Outstanding Notes requires receipt of a book-entry confirmation prior to 5:00 p.m., New York City time, on the expiration date. In addition, although delivery of Outstanding Notes may be effected through book-entry transfer into the exchange agent’s account at the book-entry transfer facility, the letter of transmittal or a manually signed facsimile thereof, together with any required signature guarantees and any other required documents, or an agent’s message in connection with a book-entry transfer, must, in any case, be delivered or transmitted to and received by the exchange agent at its address set forth on the cover page of the letter of transmittal prior to the expiration date to receive Exchange Notes for tendered Outstanding Notes, or the guaranteed delivery procedure described below must be complied with. Tender will not be deemed made until such documents are timely received by the exchange agent. Delivery of documents to the book-entry transfer facility does not constitute delivery to the exchange agent.

Holders of Outstanding Notes who are unable to deliver confirmation of the book-entry tender of their Outstanding Notes into the exchange agent’s account at the book-entry transfer facility or all other documents required by the letter of transmittal to the exchange agent on or prior to the expiration date must tender their Outstanding Notes according to the guaranteed delivery procedures described below.

Guaranteed Delivery Procedures

If a holder of Outstanding Notes desires to tender such Notes and the holder’s Outstanding Notes are not immediately available, or time will not permit the holder’s Outstanding Notes or other required documents to reach the exchange agent before 5:00 p.m., New York City time, on the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected if:

• the holder tenders the Outstanding Notes through an eligible institution;

• prior to 5:00 p.m., New York City time, on the expiration date, the exchange agent receives from such eligible institution a properly completed and duly executed notice of guaranteed delivery, acceptable to us, by facsimile transmission (receipt confirmed by telephone and an original delivered by guaranteed overnight courier), mail or hand delivery, setting forth the name and address of the holder of the Outstanding Notes tendered, the names in which such Outstanding Notes are registered, if applicable, the certificate number or numbers of such Outstanding Notes and the amount of the Outstanding Notes being tendered. The notice of guaranteed delivery shall state that the tender is being made and guarantee that within three New York Stock Exchange trading days after the expiration date, the certificates for all physically tendered Outstanding Notes, in proper form for transfer, or a book-entry confirmation, as the case may be, together with a properly completed and duly executed letter of transmittal or agent’s message with any required signature guarantees and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

• the exchange agent receives the certificates for all physically tendered Outstanding Notes, in proper form for transfer, or a book-entry confirmation, as the case may be, together with a properly completed and duly executed letter of transmittal or agent’s message with any required signature guarantees and any other documents required by the letter of transmittal, within three New York Stock Exchange trading days after the expiration date.

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Withdrawal of Tenders

If not yet accepted, you may withdraw tenders of your Outstanding Notes at any time prior to the expiration of the exchange offer. For a withdrawal to be effective, you must send a written notice of withdrawal to the exchange agent at the address set forth below under “—Exchange Agent.” Any such notice of withdrawal must:

• be received by the exchange agent prior to 5:00 p.m., New York City time, on the expiration date;

• specify the name of the person who tendered the Outstanding Notes to be withdrawn and where certificates for Outstanding Notes are transmitted, specify the name in which Outstanding Notes are registered, if different from that of the withdrawing holder;

• identify the Outstanding Notes to be withdrawn (including the principal amount of such Outstanding Notes, or, if applicable, the certificate numbers shown on the particular certificates evidencing such Outstanding Notes and the principal amount of Outstanding Notes represented by such certificates);

• include a statement that such holder is withdrawing its election to have such Outstanding Notes exchanged; and

• be signed by the holder in the same manner as the original signature on the letter of transmittal (including any required signature guarantee).

If certificates for Outstanding Notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of such certificates, the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution unless such holder is an eligible institution. If Outstanding Notes have been tendered pursuant to the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC, as applicable, to be credited with the withdrawn Notes and otherwise comply with the procedures of such facility.

We will determine all questions as to the validity, form and eligibility (including time of receipt) of notices of withdrawal and our determination will be final and binding on all parties. Any tendered Notes so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offer. Any Outstanding Notes which have been tendered for exchange but which are not exchanged for any reason will be returned to the holder thereof without cost to such holder. In the case of Outstanding Notes tendered by book-entry transfer into the exchange agent’s account at DTC, the Outstanding Notes withdrawn will be credited to an account at the book-entry transfer facility specified by the holder. The Outstanding Notes will be returned promptly after withdrawal, rejection of tender or termination of the exchange offer. Properly withdrawn Outstanding Notes may be retendered by following one of the procedures described under “—Procedures for Tendering” above at any time on or prior to 5:00 p.m., New York City time, on the expiration date.

Conditions to the Exchange Offer

Despite any other term of the exchange offer, we will not be required to accept for exchange, or to issue Exchange Notes in exchange for, any Outstanding Notes and we may terminate or amend the exchange offer as provided in this prospectus prior to the expiration date if in our reasonable judgment:

• the exchange offer or the making of any exchange by a holder violates any applicable law or interpretation of the SEC; or

• any action or proceeding has been instituted or threatened in writing in any court or by or before any governmental agency with respect to the exchange offer that, in our judgment, would reasonably be expected to impair our ability to proceed with the exchange offer.

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In addition, we will not be obligated to accept for exchange the Outstanding Notes of any holder that has not made to us:

• the representations described under “—Purpose and Effect of the Exchange Offer,” “—Procedures for Tendering” and “Plan of Distribution;” or

• any other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the Exchange Notes under the Securities Act.

We expressly reserve the right at any time or at various times to extend the period of time during which the exchange offer is open. Consequently, we may delay acceptance of any Outstanding Notes by giving written notice of such extension to their holders. The Company anticipates that it would only delay acceptance of Outstanding Notes tendered in the offer due to an extension of the expiration date of the offer. We will return any Outstanding Notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

We expressly reserve the right to amend or terminate the exchange offer and to reject for exchange any Outstanding Notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified above. We will give written notice of any extension, amendment, non-acceptance or termination to the holders of the Outstanding Notes as promptly as practicable. In the case of any extension, such notice will be issued no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

The foregoing conditions are for our sole benefit and may be asserted by us regardless of the circumstances giving rise to any such condition or may be waived by us in whole or in part at any time and from time to time. The failure by us at any time to exercise any of the foregoing rights shall not be deemed a waiver of any of those rights and each of those rights shall be deemed an ongoing right which may be asserted at any time and from time to time.

In addition, we will not accept for exchange any Outstanding Notes tendered, and no Exchange Notes will be issued in exchange for those Outstanding Notes, if at such time any stop order shall be threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939, as amended. In any of those events we are required to use every reasonable effort to obtain the withdrawal of any stop order at the earliest possible time.

Effect of Not Tendering

Holders who desire to tender their Outstanding Notes in exchange for Exchange Notes registered under the Securities Act should allow sufficient time to ensure timely delivery. Neither the exchange agent nor we are under any duty to give notification of defects or irregularities with respect to the tenders of Outstanding Notes for exchange.

Outstanding Notes that are not tendered or are tendered but not accepted will, following the consummation of the exchange offer, continue to accrue interest and to be subject to the provisions in the indenture regarding the transfer and exchange of the Outstanding Notes and the existing restrictions on transfer set forth in the legend on the Outstanding Notes. After completion of the exchange offer, we will have no further obligation to provide for the registration under the Securities Act of those Outstanding Notes except in limited circumstances with respect to specific types of holders of Outstanding Notes and we do not intend to register the Outstanding Notes under the Securities Act, and will not be obligated to pay liquidated damages. In general, Outstanding Notes, unless registered under the Securities Act, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

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Exchange Agent

All executed letters of transmittal should be directed to the exchange agent. Wells Fargo Bank, National Association has been appointed as exchange agent for the exchange offer. Questions, requests for assistance and requests for additional copies of this prospectus or of the letter of transmittal should be directed to the exchange agent addressed as follows:

Registered & Certified Mail:	Regular Mail or Courier:	In Person by Hand Only:
Wells Fargo Bank, N.A.	Wells Fargo Bank, N.A.	Wells Fargo Bank, N.A.
Corporate Trust Operations	Corporate Trust Operations	Corporate Trust Services
MAC N9303-121	MAC N9303-121	Northstar East Bldg.—12th Floor
P.O. Box 1517	6th St. & Marquette Avenue	608 Second Avenue South
Minneapolis, MN 55480	Minneapolis, MN 55479	Minneapolis, MN 55402
	By Facsimile (for Eligible Institutions only): (612) 667-6282
	For Information or Confirmation by Telephone: (800) 344-5128

Fees and Expenses

We will not make any payments to brokers, dealers or others soliciting acceptances of the exchange offer. The estimated cash expenses to be incurred in connection with the exchange offer will be paid by us and will include fees and expenses of the exchange agent, legal, printing and related fees and expenses. Notwithstanding the foregoing, holders of the Outstanding Notes shall pay all agency fees and commissions and underwriting discounts and commissions, if any, attributable to the sale of such Outstanding Notes or Exchange Notes.

Accounting Treatment

We will record the Exchange Notes at the same carrying value as the Outstanding Notes, as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes as the terms of the Exchange Notes are substantially identical to those of the Outstanding Notes. The expenses of the exchange offer will be amortized over the terms of the Exchange Notes.

Transfer Taxes

Holders who tender their Outstanding Notes for exchange will not be obligated to pay any transfer taxes in connection with that tender or exchange, except that holders who instruct us to register or issue Exchange Notes in the name of, or request that Outstanding Notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer tax on those Outstanding Notes. If satisfactory evidence of payment of such taxes or exception therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder. Notwithstanding the foregoing, holders of the Outstanding Notes shall pay transfer taxes, if any, attributable to the sale of such Outstanding Notes or Exchange Notes. If a transfer tax is imposed for any reason other than the transfer and exchange of Outstanding Notes to us or our order pursuant to the exchange offer, the amount of any such transfer taxes (whether imposed on the registered holder or any other person) will be payable by the tendering holder.

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DESCRIPTION OF EXCHANGE NOTES

In this “Description of Exchange Notes,” (a) the terms “we,” “our,” “us,” and “Company” refer only to Armstrong Energy, Inc. and any successor obligor, and not to any of its Subsidiaries, as defined herein. The definitions of certain other terms used in this description are set forth throughout the text or under “—Certain Definitions.”

The Company will issue the Exchange Notes under an indenture dated as of December 21, 2012 (the “Indenture”) among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (the “Trustee”). The terms of the Exchange Notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). Unless the context requires otherwise, all references to the “Notes” include the Outstanding Notes and the Exchange Notes. The Exchange Notes and the Outstanding Notes will be treated as a single class for all purposes of the Indenture. When issued, the Exchange Notes will be a new issue of securities with no established trading market. No assurance can be given as to the liquidity of the trading market for the Exchange Notes.

The following is a summary of the material provisions of the Indenture, the Intercreditor Agreement, the Security Documents and the Registration Rights Agreement. Because this is a summary, it may not contain all the information that is important to you. You should read the Indenture, the Intercreditor Agreement, the Security Documents and the Registration Rights Agreement in their entirety because they, and not this description, define the Company’s obligations and your rights as holders of the Exchange Notes. Copies of these documents are being filed with the SEC concurrently with the filing of the registration statement of which this prospectus is a part.

General

The Company will issue an aggregate principal amount of $200.0 million of Exchange Notes in this offering. The Company will issue the Exchange Notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The Exchange Notes will mature on December 15, 2019.

The Notes bear interest commencing at the Issue Date at a rate of 11.75%, payable semiannually on each June 15 and December 15, commencing June 15, 2013, to holders of record on June 1 or December 1 immediately preceding the interest payment date. Interest will be computed on the basis of a 360-day year of twelve 30-day months.

Additional Notes

Subject to the covenants described below, the Company may issue additional Notes in an unlimited amount from time to time under the Indenture having the same terms in all respects as the Notes except that interest will accrue on the additional Notes from their date of issuance and may have different issuance prices. Holders of the Notes and any additional Notes would be treated as a single class for all purposes under the Indenture, including with respect to voting, waivers, redemptions and repurchases. Unless the context requires otherwise, references to “Notes” for all purposes of the Indenture and this “Description of Exchange Notes” include the Outstanding Notes, the Exchange Notes and any additional Notes that are actually issued.

Note Guarantees

Subject to certain customary release provisions, the obligations of the Company pursuant to the Notes and the Indenture are fully and unconditionally guaranteed, jointly and severally by each Wholly Owned Domestic Restricted Subsidiary of the Company (which includes all the Company’s Domestic Restricted Subsidiaries as of the Issue Date, other than Wind-Down Subsidiaries). If (i) the Company creates or acquires a Wholly Owned Domestic Restricted Subsidiary after the Issue Date or (ii) any Restricted Subsidiary that is not a Guarantor Incurs or Guarantees any Indebtedness, suchRestricted Subsidiary shall provide a guarantee of the Notes (each

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such Guarantee, a “Note Guarantee”);provided that any Disposition Subsidiary formed for the sole purpose offacilitating a disposition of coal reserves and/or interests in real property otherwise permitted under the Indenture shall not be required to become a Guarantor.

Each Note Guarantee will be limited to the maximum amount that would not render the relevant Guarantor’s obligations subject to avoidance under applicable fraudulent conveyance provisions of the United States Bankruptcy Code or any comparable provision of state law. By virtue of this limitation, a Guarantor’s obligation under its Note Guarantee could be significantly less than amounts payable with respect to the Notes, or a Guarantor may have effectively no obligation under its Note Guarantee. In a recent Florida bankruptcy case, this kind of provision was found to be unenforceable and, as a result, the subsidiary guarantees in that case were found to be fraudulent conveyances. We do not know if that case will be followed if there is litigation on this point under the Indenture. However, if it is followed, the risk that the Note Guarantees will be found to be fraudulent conveyances will be significantly increased. See “Risk Factors—Risks Related to the Notes—A court could void our subsidiaries’ guarantees of the Notes under fraudulent transfer laws.”

The Note Guarantee of a Guarantor will automatically terminate upon:

(1) a sale or other disposition of Capital Stock (including by way of consolidation or merger) of such Guarantor following which it is no longer a direct or indirect Subsidiary of the Company or the sale or disposition of all or substantially all the assets of the Guarantor (in each case, other than to the Company or a Restricted Subsidiary);

(2) the designation by the Company of such Guarantor as an Unrestricted Subsidiary; or

(3) defeasance or discharge of the Notes, as provided in “Defeasance and Discharge”;

providedthat any such event occurs in accordance with all other applicable provisions of the Indenture.

Upon any occurrence giving rise to a release of a Note Guarantee as specified above, the Company shall deliver to the Trustee an Officers’ Certificate stating the identity of the released Guarantor, the basis for release in reasonable detail, and that such release complies with the Indenture. At the request of the Company, and upon delivery to the Trustee of an Officers’ Certificate and an Opinion of Counsel stating that such release complies with the Indenture, the Trustee will execute any documents reasonably required in order to evidence or effect such release, discharge and termination in respect of such Note Guarantee. None of the Company, the Trustee or any Guarantor will be required to make a notation on the Notes to reflect any Note Guarantee or any such release, termination or discharge.

Ranking

The Notes and the Note Guarantees will be senior secured obligations of the Company and the Guarantors and will:

• rank equal in right of payment with any senior Indebtedness of the Company and the Guarantors;

• rank senior in right of payment to any Indebtedness of the Company and the Guarantors that is expressly subordinated to the Notes and the Guarantees;

• be effectively junior to any secured Indebtedness which is either secured by assets that are not Collateral or which is secured by a prior lien on the Collateral, including the Indebtedness under the Credit Agreement with respect to the ABL Priority Collateral, in each case, to the extent of the value of the assets securing such Indebtedness;

• be effectively senior to any unsecured Indebtedness or Indebtedness with a lien junior to the lien on the Collateral (as defined under “—Security”) securing the Notes and the Guarantees to the extent of the value of the Collateral; and

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• be structurally subordinated to all indebtedness and other liabilities of each of our future Subsidiaries which are not Guarantors.

See “Risk Factors—Risks Related to the Notes—Our subsidiaries hold most of our assets and conduct most of our operations and, unless they are subsidiaries that guarantee the Notes, they are not obligated to make payments on the Notes. The Notes will be structurally junior to debt of our non-guarantor subsidiaries, if any.”

As of June 30, 2013, excluding $104.9 million of certain long-term obligations to Armstrong Resource Partners that are characterized as financing transactions we had $211.0 million of Indebtedness outstanding, consisting of the Notes, capital leases and other long-term obligations.

As of the Issue Date, all of the Company’s Subsidiaries were “Restricted Subsidiaries.” However, under the circumstances described below under the caption “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” the Company is permitted to designate certain of its Subsidiaries as “Unrestricted Subsidiaries.” Unrestricted Subsidiaries are not subject to any of the restrictive covenants in the Indenture. Further, Unrestricted Subsidiaries will not Guarantee the Notes.

Although the Indenture contains limitations on the amount of additional Indebtedness that the Company and the Restricted Subsidiaries may Incur, the amount of such additional Indebtedness could be substantial.

Security

Pursuant to the Security Documents entered into by the Company, the Guarantors and the Collateral Agent for the benefit of the Collateral Agent, the Trustee and the holders of Notes, the Notes, the Guarantees and all other Indenture Obligations will be secured by a Lien on substantially all of the Company’s and the Guarantors’ existing and future tangible and intangible assets (other than Excluded Assets), including (without limitation):

(1) accounts receivables;

(2) equipment, goods, inventory and fixtures;

(3) documents, instruments and chattel paper;

(4) letter-of-credit rights;

(5) investment property, including all Capital Stock of the Company’s Subsidiaries (but excluding the Capital Stock of Wind-Down Subsidiaries);

(6) copyrights and trademarks;

(7) commercial tort claims;

(8) general intangibles;

(9) deposit accounts;

(10) cash;

(11) supporting obligations;

(12) books and records;

(13) real property;

(14) as-extracted collateral (including as-extracted collateral from present and future operations regardless of whether such interests are presently owned or hereafter acquired);

(15) to the extent, if any, not included in clauses (1) through (14) above, present and future contracts, agreements, arrangements, or understandings (A) for the sale, supply, transportation, provision or disposition of any coal or other minerals, or any one or more of its agents, representatives, successors, or assigns, to any purchaser or acquirer thereof, and all products, replacements, and proceeds thereof

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(including without limitation all coal sales contracts) and (B) relating to the mining, drilling or recovery of any mineral reserves and all products and proceeds thereof and payments thereunder;

(16) to the extent, if any, not included in clauses (1) through (15) above, all coal and other minerals severed or extracted from the ground (specifically including all as-extracted collateral and all severed or extracted coal purchased, acquired or obtained from other parties), and all accounts, general intangibles and products and proceeds thereof or related thereto, regardless of whether any such coal or other minerals are in raw form or processed for sale and regardless whether or not the applicable grantor had an interest in the coal or other minerals before extraction or severance;

(17) proceeds and products of each of the foregoing and all accessions to, substitutions and replacements for each of the foregoing, and any and all proceeds of any insurance, indemnity, warranty or guaranty payable to the Company or any Guarantor from time to time with respect to any of the foregoing; and

(18) all other existing and future tangible and intangible assets that from time to time become subject to a Lien securing ABL Obligations (collectively, the “Collateral”).

“Excluded Assets” will include, among other things, the following assets of the Company and the Guarantors:

(a) assets located outside the United States to the extent a Lien on such assets cannot be perfected by the filing of UCC financing statements in the jurisdictions of organization of the Company and the Guarantors;

(b) assets subject to Liens pursuant to clause (1), (11), (12), (13), (16) or (19) (as it relates to any of the foregoing) of the definition of “Permitted Liens” to the extent the documentation relating to such Liens prohibit such assets from being Collateral and only for so long as such Liens remain outstanding;

(c)(x) the voting Capital Stock of Foreign Subsidiaries in excess of 65% of the voting rights of all such Capital Stock in each such Foreign Subsidiary and (y) any Capital Stock of a Person that is not a Subsidiary of the Company to the extent that a pledge of such Capital Stock is prohibited by such Person’s organizational documents or any shareholders agreement or joint venture agreement relating to such Capital Stock;

(d)(x) any owned real property with an associated purchase price of less than $2.5 million and (y) any right, title and interest in any leasehold or other non-fee simple interest in any real property covering less than 250 acres;provided that, notwithstanding the foregoing, any owned or leased real property or coal reserves that are material to the active mining operations or the mining plan of the Company or on which surface facility operations are, or are planned to be, conducted shall constitute “Collateral”;

(e) motor vehicles, aircraft and other assets subject to certificates of title to the extent that a Lien therein cannot be perfected by the filing of UCC financing statements in the jurisdictions of organization of the Company and the Guarantors;

(f) any property to the extent that the grant of a security interest therein would violate applicable law, require a consent not obtained of any governmental authority, or constitute a breach of or default under, or result in the termination of or require a consent not obtained under, any contract, lease, license or other agreement evidencing or giving rise to such property, or result in the invalidation thereof or provide any party thereto with a right of termination;

(g) any Capital Stock or other securities of any Subsidiary of the Company in excess of the maximum amount of such Capital Stock or securities that could be included in the Collateral without creating a requirement pursuant to Rule 3-16 of Regulation S-X under the Securities Act for separate financial statements of such Subsidiary to be included in filings by the Company with the SEC;

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(h)(1) deposit accounts the balance of which consists exclusively of withheld income taxes, employment taxes, or amounts required to be paid over to certain employee benefit plans and (2) segregated deposit accounts constituting, and the balance of which consists solely of funds set aside in connection with, tax, payroll and trust accounts;

(i) any intellectual property if the grant of a security interest therein would result in the invalidation of the grantor’s interest therein; and

(j) proceeds and products of any and all of the foregoing excluded assets described in clauses (a) through (i) above, to the extent such proceeds and products would constitute property or assets of the type described in clauses (a) through (i) above.

For the avoidance of doubt, no assets of any Subsidiary of the Company that is not a Guarantor (including any Capital Stock owned by any such Subsidiary) shall constitute Collateral.

The Collateral is pledged pursuant to one or more security agreements, dated as of the Issue Date, among the Company, the Guarantors and the Collateral Agent (as amended, modified, restated, supplemented or replaced from time to time in accordance with its terms, the “Security Agreements”), and one or more mortgages, deeds of trust or deeds to secure Indebtedness (the “Mortgages”) or other grants or transfers for security executed and delivered by the Company or the applicable Guarantor to the Collateral Agent for the benefit of the Collateral Agent, the Trustee and the holders of the Notes.

So long as no Event of Default has occurred and is continuing, and subject to certain terms and conditions, the Company and the Guarantors are entitled to exercise any voting and other consensual rights pertaining to all Capital Stock pledged pursuant to the Security Agreement and to remain in possession and retain exclusive control over the Collateral (other than as set forth in the Security Documents), to operate the Collateral, to alter or repair the Collateral and to collect, invest and dispose of any income thereon. Upon the occurrence of an Event of Default and to the extent permitted by law and following notice by the Collateral Agent to the Company and the Guarantors:

(1) all of the rights of the Company and the Guarantors to exercise voting or other consensual rights with respect to all Capital Stock included in the Collateral shall cease, and all such rights shall become vested, subject to the terms of the Intercreditor Agreement, in the Collateral Agent, which, to the extent permitted by law, shall have the sole right to exercise such voting and other consensual rights; and

(2) the Collateral Agent may, subject to the terms of the Intercreditor Agreement, take possession of and sell the Collateral or any part thereof in accordance with the terms of the Security Documents.

Upon the occurrence and during the continuance of an Event of Default, the Collateral Agent will be permitted, subject to applicable law and the terms of the Intercreditor Agreement, to exercise remedies and sell the Collateral under the Security Documents only at the direction of the holders of a majority of the Notes voting as a single class.

Intercreditor Agreement

The Collateral Agent (in its capacity as Trustee and Collateral Agent), on behalf of the holders of the Notes, the ABL Facility Collateral Agent, on behalf of the holders of the ABL Obligations, the Company and the Guarantors entered into an intercreditor agreement (the “Intercreditor Agreement”) that sets forth the relative priority of the ABL Liens and the Note Liens, as well as certain other rights, priorities and interests of the holders of the Notes and the holders of the ABL Obligations.

The Intercreditor Agreement provides for, among other things:

Lien Priority and Similar Liens. Notwithstanding the time, order or method of creation or perfection of any ABL Obligations, ABL Liens, obligations under the Notes or the Note Liens, (i) the ABL Liens on the ABL Priority Collateral will rank senior to any Note Liens on the ABL Priority Collateral and (ii) the Note Liens on

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the Notes Priority Collateral will rank senior to any ABL Liens on the Notes Priority Collateral. Except asspecified in clause (g) of the definition of “Excluded Assets,” the collateral of the Company and the Guarantors for the ABL Obligations and the Notes will at all times be substantially the same.

No Payment Subordination. The Intercreditor Agreement provides that the subordination of Liens securing the Indenture Obligations and the ABL Obligations described herein affects only the relative priority of those Liens, and does not subordinate the Indenture Obligations in right of payment to the ABL Obligations or the ABL Obligations in right of payment to the Indenture Obligations except as expressly set forth below under “—Application of Proceeds and Turn-Over Provisions.” Nothing in the Intercreditor Agreement will affect the entitlement of any (x) holder of Notes to receive and retain required payments of interest, principal, and other amounts in respect of the Indenture Obligations unless the receipt is expressly prohibited by, or results from the holder’s breach of, the Intercreditor Agreement or (y) holder of ABL Obligations to receive and retain required payments of interest, principal, and other amounts in respect of the ABL Obligations unless the receipt is expressly prohibited by, or results from such Person’s breach of, the Intercreditor Agreement.

Prohibition on Contesting Liens and Obligations. No holder of any Notes may contest the validity or enforceability of the ABL Liens or the ABL Obligations, and no holder of any ABL Obligations may contest the validity or enforceability of the Note Liens or the Notes.

Exercise of Remedies and Release of Liens. For a period of 270 days (subject to extension for any period during which the ABL Facility Collateral Agent is diligently pursuing remedies against the ABL Priority Collateral or is prohibited by applicable law from pursuing such remedies) commencing on the later of (x) the acceleration of obligations under the Notes and (y) the ABL Facility Collateral Agent receiving notice of acceleration from the Collateral Agent, the ABL Facility Collateral Agent will have the sole power to exercise remedies against the ABL Priority Collateral (subject to the right of the Collateral Agent and the holders of Notes to take limited protective measures with respect to the Note Liens and to take certain actions that would be permitted to be taken by unsecured creditors) and to foreclose upon and dispose of the ABL Priority Collateral. For a period of 270 days (subject to extension for any period during which the Collateral Agent is diligently pursuing remedies against the Notes Priority Collateral or is prohibited by applicable law from pursuing such remedies) commencing on the later of (x) the acceleration of the ABL Obligations and (y) the Collateral Agent receiving notice of acceleration from the ABL Facility Collateral Agent, the Collateral Agent will have the solepower to exercise remedies against the Notes Priority Collateral (subject to the right of the ABL Facility Collateral Agent and the holders of ABL Obligations to take limited protective measures and certain actions permitted to be taken by unsecured creditors) and to foreclose upon and dispose of the Notes Priority Collateral. Upon (x) any disposition of any ABL Priority Collateral in connection with any enforcement action or, following an event of default under the ABL Facility, certain other sales consented to by the ABL Facility Agent including in connection with “going out of business” sales or (y) any disposition of ABL Priority Collateral permitted by the documents governing the ABL Obligations, the Indenture and the Security Documents (including, for the avoidance of doubt, the Company’s use of cash that is withdrawn from deposit accounts for purposes not otherwise prohibited by such documents), in each case, which results in the release of the ABL Lien on such item of ABL Priority Collateral, the Note Lien on such item of ABL Priority Collateral will terminate and be automatically released. Upon (x) any disposition of any Notes Priority Collateral in connection with any enforcement action or (y) any disposition of Notes Priority Collateral permitted by the documents governing the ABL Obligations, the Indenture, and the Security Documents, in each case, which results in the release of the Note Lien on such item of Notes Priority Collateral, the ABL Lien on such item of Notes Priority Collateral will terminate and be automatically released. Notwithstanding the foregoing, during the 270-day blockage period set forth above, the ABL Facility Collateral Agent shall be permitted to seek or consent to the appointment of areceiver for the limited purpose of liquidating the ABL Priority Collateral. In such event, neither the Collateral Agent nor any holders of the Notes shall object to or contest such relief. The ABL Facility Collateral Agent shall have the right to (x) setoff and/or recoup any cash, cash equivalents or securities which constitute ABL Priority Collateral and/or (y) notify account debtors of the Company or any Guarantor to remit accounts payable to the Company or such Guarantor, without any prior notice to the Collateral Agent.

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The Collateral Agent shall not foreclose upon, or sell or grant the right to use, pursuant to the exercise of remedies, any part of any general intangibles which relate to payments owing to the Company or any Guarantor arising from the sale of inventory or as-extracted collateral under any contract, agreement or other general intangible (including all coal supply contracts) which had come into existence prior to such foreclosure or other action or which thereafter come into existence arising from inventory or as-extracted collateral in existence prior to such foreclosure or other action.

Application of Proceeds and Turn-Over Provisions. In connection with any enforcement action with respect to the Collateral or any insolvency or liquidation proceeding, all proceeds of (x) ABL Priority Collateral will first be applied to the repayment of all ABL Obligations before being applied to any obligations under the Notes and (y) Notes Priority Collateral will first be applied to the repayment of all obligations under the Notes before being applied to any ABL Obligations. If any holder of a Note or ABL Obligation receives any proceeds of Collateral in contravention of the foregoing, such proceeds will be turned over to the Collateral Agent or ABL Priority Collateral Agent, as applicable, for application in accordance with the foregoing.

Amendment and Refinancings. The ABL Obligations and the Indenture Obligations may be amended or refinanced in accordance with the Credit Agreement or the Indenture, and may be subject to continuing rights and obligations of the holders of such refinancing Indebtedness under the Intercreditor Agreement.

Plans of Reorganization.Neither the ABL Facility Collateral Agent, the Collateral Agent nor any holder of any ABL Obligations, may support any plan of reorganization in any insolvency or liquidation proceeding which contravenes the intercreditor provisions described below (unless consented to by the ABL Facility Collateral Agent or the Collateral Agent, as applicable, representing the holders of the Liens entitled to the benefit of such contravened intercreditor provisions).

Insolvency and Liquidation Proceedings

The Intercreditor Agreement provides that:

(a) If the Company or any Guarantor is subject to any insolvency proceeding and the ABL Facility Collateral Agent consents to the use of cash collateral (as such term is defined in Section 363(a) of the United States Bankruptcy Code, “Cash Collateral”), which is ABL Priority Collateral or permits the Company or any Guarantor to obtain financing under Section 364 of the United States Bankruptcy Code or any other Person with the consent of the ABL Facility Collateral Agent (such financing, a “DIP Financing”), then the Collateral Agent agrees that it will consent to such Cash Collateral use or raise no objection to such DIP Financing (including objecting on the basis that the Collateral Agent lacks adequate protection or seeking adequate protection in connection with such DIP Financing) and the Collateral Agent will subordinate its Liens in the ABL Priority Collateral to the Liens securing such DIP Financing;providedthat (i) the principal amount of any such DIP Financingplusthe outstanding principal amount of other ABL Obligations does not exceed $60.0 million (providedany such objection shall be limited to such provision), (ii) any such Cash Collateral use or DIP Financing does not compel the Company or any Guarantor to seek confirmation of a specific plan of reorganization for which all or substantially all of the material terms are set forth in the Cash Collateral order or DIP Financing documentation (providedany such objection shall be limited to such provision), (iii) any Cash Collateral order or DIP Financing documentation does not expressly require the liquidation of any Collateral prior to a default under the Cash Collateral order or DIP Financing documentation, and (iv) any such DIP Financing is otherwise subject to the terms of the Intercreditor Agreement. Neither the Collateral Agent nor any holder of Notes may, directly or indirectly, provide, offer to provide, or support any DIP Financing secured by a Lien senior to orpari passuwith the Liens securing the ABL Obligations on the ABL Priority Collateral. If, in connection with any Cash Collateral use or DIP Financing, any Liens on the ABL Priority Collateral held by holders of ABL Obligations are subject to a surcharge or are subordinated to an administrative priority claim, a professional fee “carve out,” or fees owed to the Trustee, then the Liens on the ABL Priority Collateral of holders of Notes Creditors will also be subordinated to such interest or claim and will remain subordinated to the Liens on the ABL Priority Collateral of holders of ABL Obligations consistent with the Intercreditor Agreement.

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(b)(i) The Collateral Agent will consent, and will not object or oppose a motion (including a motion for sale procedures), to dispose of any ABL Priority Collateral free and clear of the Liens or other claims in favor of the Collateral Agent under Section 363 of the United States Bankruptcy Code or pursuant to a plan of reorganization if the requisite holders of ABL Obligations have consented to such disposition of such assets or plan and the ABL Facility Collateral Agent agrees not to object to the rights of holders of Notes under Section 363(k) of the United States Bankruptcy Code (so long as the right of the holders of Notes to offset their claim against the purchase price allocable to ABL Priority Collateral is only after the ABL Obligations have been paid in full in cash).

(ii) The ABL Facility Collateral Agent will consent, and will not object or oppose a motion (including a motion for sale procedures), to dispose of any Note Priority Collateral free and clear of the Liens or other claims in favor of the ABL Facility Collateral Agent under Section 363 of the United States Bankruptcy Code or pursuant to a plan of reorganization if the requisite holders of Notes have consented to such disposition of such assets or plan and the Collateral Agent agrees not to object to the rights of ABL Creditors under Section 363(k) of the United States Bankruptcy Code (so long as the right of the holders of ABL Obligations to offset their claim against the purchase price is only after the Note Priority Obligations have been paid in full in cash).

(c)(i) Until the Discharge of ABL Priority Obligations, the Collateral Agent will agree not to (a) seek (or support any other person seeking) relief from the automatic stay or any other stay in any insolvency proceeding in respect of the ABL Priority Collateral, without the prior written consent of the ABL Facility Collateral Agent, unless and to the extent the ABL Facility Collateral Agent obtains relief from the automatic stay in respect of ABL Priority Collateral or (b) oppose any request by the ABL Facility Collateral Agent or any holder of ABL Obligations to seek relief from the automatic stay or any other stay in any insolvency proceeding in respect of the ABL Priority Collateral.

(ii) Until the Discharge of Indenture Obligations, the ABL Facility Collateral Agent will agree not to (a) seek (or support any other person seeking) relief from the automatic stay or any other stay in any insolvency proceeding in respect of the Note Priority Collateral, without the prior written consent of the Collateral Agent, unless and to the extent the Collateral Agent obtains relief from the automatic stay in respect of Note Priority Collateral, or (b) oppose any request by the Collateral Agent or any holders of Notes to seek relief from the automatic stay or any other stay in any insolvency proceeding in respect of the Note Priority Collateral.

(d)(i) In any insolvency proceeding involving the Company or any Guarantor, no holder of Notes will, except as expressly described herein, seek adequate protection on account of its Note Lien on the ABL Priority Collateral other than in the form of junior priority Liens.

(ii) In any insolvency proceeding involving the Company or any Guarantor, no holder of ABL Obligations will, except as expressly described herein, seek adequate protection on account of its ABL Lien on the Note Priority Collateral other than in the form of junior priority Liens.

(e) In any insolvency proceeding involving the Company or any Guarantor:

(i) if any one or more holders of ABL Obligations are granted adequate protection in the form of a replacement Lien (on existing or future assets of the Company or any Guarantor), then the Collateral Agent will also be entitled to seek, without objection from the holders of ABL Obligations, adequate protection in the form of a replacement Lien (on such existing or future assets of the Company or any Guarantor), which replacement Lien, if obtained, will (x) if such assets consist of ABL Priority Collateral, be subordinate to the Liens on ABL Priority Collateral securing the ABL Obligations (including those under a DIP Financing) on the same basis as the other Liens on the ABL Priority Collateral securing the Indenture Obligations are subordinate to the Liens on ABL Collateral securing ABL Obligations under the Intercreditor Agreement and (y) if such assets consist of Note Priority Collateral, be senior to the Liens on Note Priority Collateral securing the ABL Obligations (including those under a DIP Financing) on the same basis as the other Liens on Note Priority Collateral securing the Indenture Obligations are senior to the Liens on the Note Priority Collateral securing ABL Obligations under the Intercreditor Agreement;

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(ii) if any one or more holders of Notes are granted adequate protection in the form of a replacement Lien (on existing or future assets of the Company or any Guarantor), then the ABL Facility Collateral Agent will also be entitled to seek, without objection from holders of Notes adequate protection in the form of a replacement Lien (on such existing or future assets of the Company or any Guarantor), which replacement Lien, if obtained, will (x) if such assets consist of Note Priority Collateral, be subordinate to the Liens on Note Priority Collateral securing the Indenture Obligations on the same basis as the other Liens on the Note Priority Collateral securing the ABL Obligations are subordinate to the Liens on the Note Priority Collateral securing Indenture Obligations under the Intercreditor Agreement and (y) if such assets consist of ABL Priority Collateral, be senior to the Liens on ABL Priority Collateral securing the Indenture Obligations on the same basis as the other Liens on ABL Priority Collateral securing the ABL Obligations are senior to the Liens on the ABL Priority Collateral securing Indenture Obligations under the Intercreditor Agreement.

(f)(i) Neither the Collateral Agent nor any other holders of Notes will object to, oppose, or challenge any claim by the ABL Facility Collateral Agent or any holders of ABL Obligations for allowance in any insolvency proceeding of ABL Obligations consisting of post-petition interest, fees, or expenses.

(ii) Neither the ABL Facility Collateral Agent nor any other holders of ABL Obligations will object to, oppose, or challenge any claim by the Collateral Agent or any holders of Notes for allowance in any insolvency proceeding of Note Obligations consisting of post-petition interest, fees, or expenses.

Use and Release of Collateral

Unless an Event of Default shall have occurred and be continuing and the Collateral Agent shall have commenced enforcement of remedies under the Security Documents, except to the extent otherwise provided in the Credit Agreement or other documentation governing the ABL Obligations, the Company will have the right to remain in possession and retain exclusive control of the Collateral, to freely operate the Collateral and to collect, invest and dispose of any income thereon.

Release of Collateral

The Indenture and the Security Documents provide that the Note Liens will automatically and without the need for any further action by any Person be released:

(a) in whole or in part, as applicable, as to all or any portion of property subject to such Note Liens which has been taken by eminent domain, condemnation or other similar circumstances;

(b) in whole upon:

(1) discharge of the Indenture as set forth below under “—Discharge and Defeasance”; or

(2) a legal defeasance or covenant defeasance of the Indenture as described below under “—Discharge and Defeasance”;

(c) in part, as to any property that (a) is sold, transferred or otherwise disposed of by the Company or any Guarantor (other than to the Company or another Guarantor) in a transaction not prohibited by the Indenture at the time of such sale, transfer or disposition or (b) is owned or at any time acquired by a Guarantor that has been released from its Guarantee pursuant to paragraph (b) of “—Certain Covenants—Additional Guarantees,” concurrently with the release of such Guarantee;

(d) as to property that constitutes all or substantially all of the Collateral securing the Notes, with the consent of holders of at least 66 2/3% in aggregate principal amount of the Notes then outstanding;

(e) as to property that constitutes less than all or substantially all of the Collateral securing the Notes, with the consent of the holders of at least a majority in aggregate principal amount of the Notes then outstanding; and

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(f) in part, in accordance with the applicable provisions of the Security Documents and as described above with respect to the Intercreditor Agreement.

Certain Bankruptcy Limitations

The right of the Collateral Agent to take possession and dispose of the Collateral following an Event of Default is likely to be significantly impaired by applicable bankruptcy law if a bankruptcy proceeding were to be commenced by or against the Company or the Guarantors prior to the Collateral Agent having taken possession and disposed of the Collateral. Under the U.S. Bankruptcy Code, a secured creditor is prohibited from taking its security from a debtor in a bankruptcy case, or from disposing of security taken from such debtor, without bankruptcy court approval. Moreover, the U.S. Bankruptcy Code permits the debtor in certain circumstances to continue to retain and to use collateral owned as of the date of the bankruptcy filing (and the proceeds, products, offspring, rents or profits of such Collateral) even though the debtor is in default under the applicable debt instruments; provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances. In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary powers of a bankruptcy, court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the Collateral Agent could repossess or dispose of the Collateral, or whether or to what extent holders would be compensated for any delay in payment or loss of value of the Collateral through the requirement of “adequate protection.”

Furthermore, in the event a bankruptcy court determines the value of the Collateral (after giving effect to any prior Liens) is not sufficient to repay all amounts due on the Notes, the holders of the Notes would hold secured claims to the extent of the value of the Collateral, and would hold unsecured claims with respect to any shortfall. Applicable Federal bankruptcy laws permit the payment and/or accrual of post-petition interest, costs and attorneys’ fees during a debtor’s bankruptcy case only to the extent the claims are oversecured or the debtor is solvent at the time of reorganization. In addition, if the Company or the Guarantors were to become the subject of a bankruptcy case, the bankruptcy court, among other things, may avoid certain prepetition transfers made by the entity that is the subject of the bankruptcy filing, including, without limitation, transfers held to be preferences or fraudulent conveyances.

Optional Redemption

Except as set forth in the next three paragraphs, the Notes are not redeemable at the option of the Company.

At any time prior to December 15, 2016, the Company may redeem the Notes, in whole or in part, on not less than 30 nor more than 60 days’ prior notice, by paying a redemption price equal to 100% of the principal amount of the Notes to be redeemed plus the Applicable Premium as of, and accrued and unpaid interest, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

At any time and from time to time on or after December 15, 2016, the Company may redeem the Notes, in whole or in part, at a redemption price equal to the percentage of principal amount set forth below plus accrued and unpaid interest to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date):

12-Month Period Commencing December 15 in Year	Percentage
2016		105.875	%
2017		102.938	%
2018 and thereafter		100.000	%

At any time and from time to time prior to December 15, 2015, the Company may redeem the Notes with the net cash proceeds received by the Company from one or more Equity Offerings at a redemption price equal to 111.75% of the principal amount plus accrued and unpaid interest to the redemption date (subject to the right of

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holders of record on the relevant record date to receive interest due on the relevant interest payment date), in an aggregate principal amount for all such redemptions not to exceed 35% of the original aggregate principal amount of the Notes, including additional Notes,providedthat:

(1) in each case, the redemption takes place not later than 90 days after the closing of the related Equity Offering, and

(2) not less than 65% of the aggregate principal amount of the Notes originally issued under the Indenture (including any additional Notes) remains outstanding immediately thereafter.

If fewer than all of the Notes are being redeemed, the Trustee will select the Notes to be redeemed with respect to the global Notes, by lot or by such other method as may be required by The Depository Trust Company (“DTC”) and otherwise, pro rata, or by any other method the Trustee in its sole discretion deems fair and appropriate, in denominations of $2,000 principal amount and multiples of $1,000 above that amount. Upon surrender of any Note redeemed in part, the holder will receive a replacement Note equal in principal amount to the unredeemed portion of the surrendered Note. Once notice of redemption is sent to the holders, Notes called for redemption become due and payable at the redemption price on the redemption date, and, commencing on the redemption date, Notes redeemed will cease to accrue interest.

Repurchase of Notes upon a Change of Control

Not later than 30 days following a Change of Control, the Company is required to make an Offer to Purchase (as defined below) for all Outstanding Notes at a purchase price equal to 101% of the principal amount of the Notes plus accrued and unpaid interest to the date of purchase;provided, however, that notwithstanding the occurrence of a Change of Control, the Company will not be obligated to purchase the Notes pursuant to this section in the event that, prior to the requirement to commence the Offer to Purchase, the Company has sent the notice to exercise its right to redeem all the Notes under the terms of “Optional Redemption” and redeemed the Notes in accordance with such notice.

An “Offer to Purchase” must be made by written offer to the holders of the Notes, with a copy to the Trustee, which will specify the principal amount of Notes subject to the offer and the purchase price. The offermust specify an expiration date (the “expiration date”) not less than 30 days or more than 60 days after the date of the offer, and a settlement date for purchase (the “purchase date”) not more than five business days after the expiration date. The offer will also contain instructions and materials necessary to enable holders to tender Notes pursuant to the offer. If the Offer to Purchase is sent prior to the occurrence of the Change of Control, it may be conditioned upon the consummation of the Change of Control.

A holder may tender all or any portion of its Notes pursuant to an Offer to Purchase, subject to the requirement that any portion of a Note tendered must be in a multiple of $1,000 principal amount and in a minimum of $2,000 principal amount. Holders are entitled to withdraw Notes tendered up to the close of business on the expiration date. On the purchase date the purchase price will become due and payable on each Note accepted for purchase pursuant to the Offer to Purchase, and interest on Notes purchased will cease to accrue on and after the purchase date so long as the Company purchases all Notes validly tendered in the offer.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the purchase of the Notes pursuant to an Offer to Purchase pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions in the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligation under the Change of Control provisions of the Indenture by virtue of such conflict.

The Credit Agreement also provides that the occurrence of certain change of control events with respect to the Company would constitute a default thereunder.

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Future debt of the Company may prohibit the Company from purchasing Notes in the event of a Change of Control, provide that a Change of Control is a default or require the Company to repurchase such Notes upon a Change of Control. Moreover, the exercise by the holders of Notes of their right to require the Company to purchase the Notes could cause a default under other debt, even if the Change of Control itself does not, due to the effects of the purchase on the Company.

Finally, the Company’s ability to pay cash to the holders of Notes following the occurrence of a Change of Control may be limited by its then-existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make the required purchase of the Notes. See “Risk Factors—Risks Related to the Notes—We may not be able to repurchase the Notes upon a change of control.”

The phrase “all or substantially all,” as used with respect to the assets of the Company in the definition of “Change of Control,” is subject to interpretation under applicable state law and there is no precise established definition of the phrase, and its applicability in a given instance would depend upon the facts and circumstances. As a result, there may be a degree of uncertainty in ascertaining whether a sale or transfer of “all or substantially all” the assets of the Company has occurred in a particular instance, in which case a holder’s ability to obtain the benefit of these provisions could be unclear.

Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the holder of the Notes to require the Company to purchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

The provisions under the Indenture relating to the Company’s obligation to make an offer to repurchase the Notes as a result of a Change of Control may be waived or amended as described in “—Amendments and Waivers.”

No Mandatory Redemption or Sinking Fund

There will be no mandatory redemption or sinking fund payments for the Notes.

Certain Covenants

The Indenture contains covenants including, among others, the following:

Limitation on Indebtedness or Preferred Stock

(a) The Company will not, and will not cause or permit any of its Restricted Subsidiaries to Incur any Indebtedness, including Acquired Indebtedness, or permit any Restricted Subsidiary to Incur Preferred Stock, except that:

(1) the Company or any Guarantor may Incur Indebtedness, including Acquired Indebtedness, and

(2) any Guarantor may Incur Preferred Stock,

if, at the time of and immediately after giving effect to the Incurrence thereof and the receipt and application of the proceeds therefrom, the Fixed Charge Coverage Ratio is not less than 2.0:1.0 (the “Fixed Charge Coverage Ratio Test”).

(b) Notwithstanding the foregoing, the Company and, to the extent provided below, any Restricted Subsidiary may Incur the following (“Permitted Indebtedness”):

(1) Indebtedness of the Company and the Guarantors pursuant to Credit Facilities; provided that the aggregate principal amount at any time outstanding does not exceed $50.0 million, less any permanent repayment thereof or permanent reduction in commitments required thereunder from the proceeds of one or more Asset Sales which are used to repay a Credit Facility pursuant to clause (3)(i) of the covenant ‘‘—Limitation on Asset Sales”;

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(2) Indebtedness of the Company and the Guarantors pursuant to (A) the Notes issued on the Issue Date and any Note Guarantee of the Notes (including additional Notes) and (B) any exchange Notes issued in exchange for Notes pursuant to the Registration Rights Agreement and any Note Guarantee of the exchange Notes;

(3)(i) Indebtedness of the Company or any Restricted Subsidiary owed to the Company or any Restricted Subsidiary so long as such Indebtedness continues to be owed to the Company or a Restricted Subsidiary and which, if the obligor is the Company or a Guarantor and if the Indebtedness is owed to a non-Guarantor, is subordinated in right of payment to the Notes and (ii) Preferred Stock of a Restricted Subsidiary so long as such Preferred Stock continues to be held by the Company or a Guarantor; provided that, at such time as any such outstanding Indebtedness or Preferred Stock ceases to be owed to or held by, as the case may be, the Company or a Restricted Subsidiary (or Guarantor, in the case of Preferred Stock), such Indebtedness or Preferred Stock will be deemed to be Incurred and not permitted by this clause (3);

(4) Indebtedness (“Permitted Refinancing Indebtedness”) constituting an extension or renewal of, replacement of, or substitution for, or issued in exchange for, or the net proceeds of which are used to repay, redeem, repurchase, replace, refinance or refund, including by way of defeasance (all of the above, for purposes of this clause, “refinance”) then outstanding Indebtedness Incurred under clause (a) or clause (b)(2), (b)(4), (b)(8), (b)(11) or (b)(12) of this covenant in an amount not to exceed the principal amount of the Indebtedness so refinanced, plus applicable premiums, fees and expenses incurred in connection with the repayment of such Indebtedness and the Incurrence of the Permitted Refinancing Indebtedness;providedthat:

(A) in case the Notes are refinanced in part or the Indebtedness to be refinanced is pari passu with the Notes, the new Indebtedness, by its terms or by the terms of any agreement or instrument pursuant to which it is outstanding, is made pari passu with, or subordinated in right of payment to, the remaining Notes;

(B) in case the Indebtedness to be refinanced is subordinated in right of payment to the Notes, the new Indebtedness, by its terms or by the terms of any agreement or instrument pursuant to which it is outstanding, is made subordinate in right of payment to the Notes at least to the extent that the Indebtedness to be refinanced is subordinated to the Notes;

(C) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being refinanced;

(D) in no event may Indebtedness of the Company or any Guarantor be refinanced pursuant to this clause by means of any Indebtedness of any Restricted Subsidiary that is not a Guarantor;

(5) Hedging Agreements of the Company or any Restricted Subsidiary entered into in the ordinary course of business and not for speculation;

(6) Indebtedness of the Company or any Restricted Subsidiary in the form of bank guarantees, letters of credit and bankers’ acceptances (except to the extent issued under the Credit Agreement) and bid, performance, reclamation, statutory obligation, surety, appeal and performance bonds and other obligations of a like nature, in each case incurred in the ordinary course of business and not in connection with the borrowing of money or the obtaining of advances or credit;

(7) Indebtedness arising from agreements of the Company or any Restricted Subsidiaries providing for indemnification, adjustment of purchase price, earnouts or similar obligations, in each case, incurred or assumed in connection with the acquisition or disposition of any business, assets or any Subsidiary;

(8) Indebtedness of the Company or any Restricted Subsidiary outstanding on the Issue Date, other than the Notes;

(9) Indebtedness of the Company or any Guarantor consisting of Guarantees of Indebtedness of the Company or any Guarantor otherwise permitted under this covenant; provided that if the Indebtedness Guaranteed is subordinated to the Notes, then such Guarantee will be subordinated to the Notes or the relevant Note Guarantee, as the case may be, to the same extent;

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(10) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds or Indebtedness in respect of netting services, automatic clearinghouse arrangements, overdraft protections and similar arrangements in connection with deposit accounts, in each case in the ordinary course of business;

(11) Acquired Indebtedness, provided that, after giving effect to such acquisition and the Incurrence of such Indebtedness, either (x) the Company would be permitted to Incur at least $1.00 of additional Indebtedness pursuant to clause (a) of the first paragraph of this covenant or (y) the Fixed Charge Coverage Ratio of the Company and its Restricted Subsidiaries would be equal to or greater than immediately prior to such acquisition;

(12) Indebtedness of the Company or any Restricted Subsidiary Incurred to finance the acquisition, construction, development or improvement of any property or assets (including purchase money obligations and Capital Leases and any Indebtedness assumed in connection with the acquisition of any such property and assets or secured by a Lien on any such property and assets before the acquisition thereof); provided that the aggregate principal amount at any time outstanding of any Indebtedness Incurred under this clause (b)(12), together with any Permitted Refinancing Indebtedness Incurred in respect thereof under clause (b)(4), may not exceed $75.0 million;

(13) unsecured Indebtedness owed to an Affiliate that have been characterized as Indebtedness only solely because of the continuing involvement of the Company or a Restricted Subsidiary in mining related to such leases, in an aggregate amount not to exceed $30.0 million at any time outstanding.

(14) unsecured Indebtedness of the Company or any Restricted Subsidiary Incurred on or after the Issue Date not otherwise permitted hereunder in an aggregate principal amount at any time outstanding not to exceed $25.0 million.

Notwithstanding any other provision of this covenant, for purposes of determining compliance with this covenant, increases in Indebtedness solely due to fluctuations in the exchange rates of currencies will not be deemed to exceed the maximum amount that the Company or a Restricted Subsidiary may Incur under this covenant. For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred;providedthat if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtednessbeing refinanced. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such respective Indebtedness is denominated that is in effect on the date of such refinancing.

For purposes of determining compliance with this covenant, in the event that an item of Indebtedness or Preferred Stock meets the criteria of more than one of the categories of Permitted Indebtedness described in clauses (1) through (14) above or is entitled to be Incurred pursuant to paragraph (a) of this covenant, the Company shall, in its sole discretion, classify such item in any manner that complies with this covenant, and such Indebtedness or Preferred Stock will be treated as having been Incurred pursuant to the clauses of Permitted Indebtedness or paragraph (a) hereof, as the case may be, designated by the Company, and from time to time may change the classification of an item of Indebtedness (or any portion thereof) to any other type of Indebtedness described in the “Limitation on Indebtedness or Preferred Stock” covenant at any time, including pursuant toclause (a);providedthat Indebtedness under the Credit Agreement Incurred and outstanding on the Issue Date shall be deemed at all times to be incurred under clause (1) of the definition of “Permitted Indebtedness.”

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Accrual of interest or dividends, the accretion of accreted value, the accretion or amortization of original issue discount and the payment of interest or dividends in the form of additional Indebtedness or Preferred Stock of the same class will not be deemed to be an Incurrence of Indebtedness or Preferred Stock for purposes of this covenant but will be included in subsequent calculations of the amount of outstanding Indebtedness for purposes of Incurring future Indebtedness;providedthat such accrual, accretion, amortization or payment is included in the calculation of Fixed Charges.

Neither the Company nor any Guarantor may Incur any Indebtedness that is subordinated in right of payment to other Indebtedness of the Company or the Guarantor, unless such Indebtedness is also subordinated in right of payment to the Notes or the relevant Note Guarantee on substantially identical terms.

Limitation on Restricted Payments

(a) The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly (the payments and other actions described in the following clauses being collectively “Restricted Payments”):

• declare or pay any dividend or make any distribution on its Equity Interests (other than dividends or distributions paid in the Company’s Qualified Equity Interests) held by Persons other than the Company or any of its Restricted Subsidiaries;

• purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company held by Persons other than the Company or any of its Restricted Subsidiaries;

• repay, redeem, repurchase, defease or otherwise acquire or retire for value, or make any payment on or with respect to, any Subordinated Indebtedness (other than a payment of interest or principal at Stated Maturity thereof or the purchase, repurchase or other acquisition of any Subordinated Indebtedness purchased in anticipation of satisfying a scheduled maturity, sinking fund or amortization or other installment obligation, in each case due within one year of the date of acquisition or any Subordinated Indebtedness Incurred pursuant to clause (b)(3) of “—Limitation on Indebtedness and Preferred Stock”); or

• make any Restricted Investment;

unless, at the time of, and after giving effect to, the proposed Restricted Payment:

(1) no Default has occurred and is continuing,

(2) the Company could Incur at least $1.00 of Indebtedness under the Fixed Charge Coverage Ratio Test, and

(3) the aggregate amount expended for all Restricted Payments made on or after the Issue Date would not, subject to paragraph (c), exceed the sum of:

(A) 50% of the aggregate amount of the Consolidated Net Income (or, if the Consolidated Net Income is a loss, minus 100% of the amount of the loss) accrued on a cumulative basis during the period, taken as one accounting period, beginning on January 1, 2013 and ending on the last day of the Company’s most recently completed fiscal quarter for which internal financial statements are available, plus

(B) subject to paragraph (c), the aggregate net cash proceeds received by the Company (other than from a Subsidiary) on or after the Issue Date:

(i) from the issuance and sale of its Qualified Equity Interests, including by way of issuance of its Disqualified Equity Interests or Indebtedness to the extent since converted into Qualified Equity Interests of the Company, or

(ii) as a contribution to its common equity, plus

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(C) to the extent that any Restricted Investment that was made after the Issue Date is sold for cash or otherwise liquidated or repaid for cash, the lesser of:

(i) the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and

(ii) the initial amount of such Restricted Investment; plus

(D) to the extent that any Unrestricted Subsidiary of the Company designated as such after the Issue Date is redesignated as a Restricted Subsidiary after the Issue Date, the lesser of:

(i) the Fair Market Value of the Company’s Investment in such Subsidiary as of the date of such redesignation and

(ii) such Fair Market Value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary after the Issue Date.

The amount of any Restricted Payment, if other than in cash, will be the Fair Market Value of the assets or securities proposed to be transferred or issued to or by the Company or such Restricted Subsidiary, as the case may be.

(b) The foregoing will not prohibit:

(1) the payment of any dividend or distribution or consummation of an irrevocable redemption within 60 days after the date of declaration thereof if, at the date of declaration, such payment would otherwise be permitted under the Indenture;

(2) dividends or distributions by a Restricted Subsidiary payable, on a pro rata basis or on a basis more favorable to the Company, to all holders of any class of Equity Interests of such Restricted Subsidiary a majority of which is held, directly or indirectly through Restricted Subsidiaries, by the Company;

(3) the repayment, redemption, repurchase, defeasance or other acquisition or retirement for value of Subordinated Indebtedness with the proceeds of, or in exchange for, Permitted Refinancing Indebtedness;

(4) the purchase, redemption or other acquisition or retirement for value of Equity Interests of the Company in exchange for, or out of the proceeds of a substantially concurrent offering (with any offering within 60 days deemed as substantially concurrent) of, Qualified Equity Interests of the Company or of a contribution to the common equity of the Company;

(5) the repayment, redemption, repurchase, defeasance or other acquisition or retirement of Subordinated Indebtedness of the Company or any Guarantor in exchange for, or out of the proceeds of, a cash contribution to the capital of the Company or a substantially concurrent offering (with any offering within 60 days deemed as substantially concurrent) of, Qualified Equity Interests of the Company;

(6) amounts paid for the purchase, redemption or other acquisition or retirement for value of Equity Interests of the Company or any of its Restricted Subsidiaries held by current or former officers, directors or employees (or their estates or beneficiaries under their estates or the applicable agreements or employee benefit plans), of the Company or any of its Restricted Subsidiaries pursuant to any agreement or employee benefit plan under which the Equity Interests were issued;provided that the aggregate consideration paid therefor in any twelve-month period after the Issue Date does not exceed an aggregate amount of $5.0 million (with unused amounts in any twelve-month period being permitted to carry over for the succeeding twelve-month period); provided further that such amount in any twelve-month period may be increased in an amount not to exceed the cash proceeds of key man life insurance policies received by the Company and its Restricted Subsidiaries subsequent to the Issue Date not already applied to make repurchases pursuant to this clause (6);

(7) the repayment, redemption, repurchase, defeasance or other acquisition or retirement for value of any Subordinated Indebtedness or Disqualified Stock at a purchase price not greater than 101% of the principal amount thereof or liquidation preference in the event of (x) a change of control pursuant to a provision no more favorable to the holders thereof than “Repurchase of Notes Upon a Change of Control” or (y) an asset sale pursuant to a provision no more favorable to the holders thereof than “Limitation on Asset

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Sales,”provided that, in each case, prior to the repurchase the Company has made an Offer to Purchase and repurchased all Notes issued under the Indenture that were validly tendered for payment in connection with the Offer to Purchase;

(8) the repurchase of Capital Stock deemed to occur upon the exercise of options or warrants to the extent that such Capital Stock represents all or a portion of the exercise price thereof;

(9) cash payments in lieu of the issuance of fractional shares in connection with the exercise of warrants, options or other securities convertible into or exchangeable for Capital Stock of the Company;

(10) dividends and distributions to holders of any class or series of Disqualified Stock or Preferred Stock of the Company or any of its Restricted Subsidiaries Incurred in accordance with the covenant described above under “—Limitation on Indebtedness or Preferred Stock”;provided, however, that such dividends and distributions are included in Interest Expense;

(11) the payment of dividends on the Company’s common Capital Stock of up to 6% per annum of the net cash proceeds received by the Company from any public equity offering of common Capital Stock of the Company; and

(12) Restricted Payments not otherwise permitted hereby in an aggregate amount not to exceed $15.0 million.

provided that, in the case of clauses (7) and (12), no Default has occurred and is continuing or would occur as a result thereof.

(c) Proceeds of the issuance of Qualified Equity Interests will be included under clause (3) of paragraph (a) only to the extent they are not applied as described in clause (4) or (5) of paragraph (b). Restricted Payments permitted pursuant to clauses (2), (3), (4), (5), (7), (8), (9) and (10) will not be included in making the calculations under clause (3) of paragraph (a).

For purposes of determining compliance with this covenant, in the event that a Restricted Payment permitted pursuant to this covenant or a Permitted Investment meets the criteria of more than one of the categories of Restricted Payment described in clauses (1) through (12) above or one or more clauses of the definition of Permitted Investments, the Company shall be permitted to classify such Restricted Payment or Permitted Investment on the date it is made, or later reclassify all or a portion of such Restricted Payment or Permitted Investment, in any manner that complies with this covenant, and such Restricted Payment or Permitted Investment shall be treated as having been made pursuant to only one of such clauses of this covenant or of the definition of Permitted Investments. For purposes of covenant compliance, the amount of any Investment shall be the amount actually invested, without adjustment for subsequent increases or decreases in the value of such Investment, less any amount paid, repaid, returned, distributed or otherwise received in cash in respect of such Investment.

Limitation on Liens

The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, Incur or permit to exist any Lien of any nature whatsoever on any of its properties or assets, whether owned at the Issue Date or thereafter acquired, to secure any Indebtedness other than Permitted Liens.

Limitation on Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries.

(a) The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or restriction of any kind on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Equity Interests to the Company or any Restricted Subsidiary;

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(2) pay any Indebtedness owed to the Company or any other Restricted Subsidiary;

(3) make loans or advances to the Company or any other Restricted Subsidiary; or

(4) sell, lease or transfer any of its property or assets to the Company or any other Restricted Subsidiary.

(b) The provisions of paragraph (a) do not apply to any encumbrances or restrictions:

(1) existing on the Issue Date in the Credit Agreement or any other agreements in effect on the Issue Date, and any amendments, modifications, restatements, extensions, renewals, replacements or refinancings of any of the foregoing;provided that the encumbrances and restrictions in the amendment, modification, restatement, extension, renewal, replacement or refinancing are, taken as a whole, in the good faith judgment of the Company, no less favorable in any material respect to the holders of Notes than the encumbrances or restrictions being amended, modified, restated, extended, renewed, replaced or refinanced;

(2) existing pursuant to the Indenture, the Notes or the Note Guarantees;

(3) existing under or by reason of applicable law, rule, regulation or order;

(4) existing under any agreements or other instruments of, or with respect to, any Person, or the property or assets of any Person, at the time the Person is acquired by the Company or any Restricted Subsidiary, which encumbrances or restrictions referred to in this clause (b)(4): (i) are not applicable to any other Person or the property or assets of any other Person and (ii) were not put in place in anticipation of such event and any amendments, modifications, restatements, extensions, renewals, replacements or refinancings of any of the foregoing,provided that the encumbrances and restrictions in the amendment, modification, restatement, extension, renewal, replacement or refinancing are, taken as a whole, in the good faith judgment of the Company, no less favorable in any material respect to the holders of Notes than the encumbrances or restrictions being amended, modified, restated, extended, renewed, replaced or refinanced;

(5) of the type described in clause (a)(4) (i) arising or agreed to in the ordinary course of business that restrict in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease, license, conveyance or similar contract, including with respect to intellectual property, (ii) that restrict in a customary manner, pursuant to provisions in partnership agreements, limited liability company organizational governance documents, joint venture agreements and other similar agreements, the transfer of ownership interests in, or assets of, such partnership, limited liability company, joint venture or similar Person or (iii) by virtue of any Lien on, or agreement to transfer, option or similar right with respect to any property or assets of, the Company or any Restricted Subsidiary permitted under the Indenture;

(6) with respect to a Restricted Subsidiary and imposed pursuant to an agreement that has been entered into for the sale or disposition of the Capital Stock of, or property and assets of, the Restricted Subsidiary pending closing of such sale or disposition that is permitted by the Indenture;

(7) existing pursuant to Permitted Refinancing Indebtedness;provided that the encumbrances and restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are, taken as a whole, no less favorable in any material respect to the holders of Notes than those contained in the agreements governing the Indebtedness being refinanced;

(8) consisting of restrictions on cash or other deposits or net worth imposed by customers or suppliers or required by insurance surety bonding companies, in each case, in the ordinary course of business;

(9) existing pursuant to purchase money obligations and Capital Leases or operating leases that impose encumbrances or restrictions discussed in clause (a)(4) above on the property so acquired or covered thereby; or

(10) existing pursuant to customary provisions in joint venture, operating or similar agreements, asset sale agreements and stock sale agreements required in connection with the entering into of such transaction.

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Note Guarantees by Restricted Subsidiaries

If (i) the Company creates or acquires a Wholly Owned Domestic Restricted Subsidiary after the Issue Date or (ii) any Restricted Subsidiary that is not a Guarantor Incurs or Guarantees any Indebtedness, such Restricted Subsidiary shall provide a Note Guarantee within 30 days of such creation, Acquisition, Incurrence or Guarantee;provided that any Disposition Subsidiary formed for the sole purpose of facilitating a disposition of coal reserves and/or interests in real property otherwise permitted under the Indenture shall not be required to become a Guarantor.

Limitation on Asset Sales

The Company will not, and will not permit any Restricted Subsidiary to, make any Asset Sale unless the following conditions are met:

(1) the Asset Sale is for at least Fair Market Value.

(2) at least 75% of the consideration received by the Company or its Restricted Subsidiaries consists of cash, Cash Equivalents or Additional Assets (provided that to the extent that the subject assets constituted Notes Priority Collateral, substantially all of such Additional Assets shall constitute Notes Priority Collateral);

For purposes of this clause (2), each of the following shall be considered cash or Cash Equivalents:

(A) the assumption by the purchaser of Indebtedness or other obligations or liabilities (as shown on the Company’s most recent balance sheet or in the footnotes thereto) (other than Subordinated Indebtedness or other obligations or liabilities subordinated in right of payment to the Notes) of the Company or a Restricted Subsidiary pursuant to operation of law or a customary novation agreement, and

(B) instruments, Notes, securities or other obligations received by the Company or such Restricted Subsidiary from the purchaser that are promptly, but in any event within 90 days of the closing, converted by the Company or such Restricted Subsidiary to cash or Cash Equivalents, to the extent of the cash or Cash Equivalents actually so received.

(3) Within 360 days after the receipt of any Net Cash Proceeds from an Asset Sale or any Net Loss Proceeds from an Event of Loss, the Net Cash Proceeds or Net Loss Proceeds, as applicable, may be used:

(i) to the extent such Net Cash Proceeds or Net Loss Proceeds, as applicable, constitute proceeds from ABL Priority Collateral, to repay permanently any Indebtedness under the Credit Agreement or any other Credit Facility that is secured by Liens on ABL Priority Collateral with the priority set forth in the Intercreditor Agreement then outstanding as required by the terms thereof;

(ii) to acquire (or enter into a legally binding agreement to acquire), all or substantially all of the assets of, or a majority of the Voting Stock of, a Permitted Business (or in the case of an Asset Sale of ABL Priority Collateral, to acquire additional Collateral);provided that to the extent such Net Cash Proceeds or Net Loss Proceeds are received in respect of Notes Priority Collateral, such Net Cash Proceeds or Net Loss Proceeds, as applicable, are applied to acquire assets substantially all of which constitute Notes Priority Collateral;

(iii) to make capital expenditures; provided that to the extent such Net Cash Proceeds or Net Loss Proceeds are received in respect of Notes Priority Collateral, such expenditures shall relate to Notes Priority Collateral; or

(iv) to invest the Net Cash Proceeds or Net Loss Proceeds (or enter into a legally binding agreement to invest) in Additional Assets; provided that to the extent such Net Cash Proceeds or Net Loss Proceeds are received in respect of Notes Priority Collateral, substantially all of such Additional Assets constitute Notes Priority Collateral.

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A binding commitment to make an acquisition referred to in clause (ii) or (iv) shall be treated as a permitted application of the Net Cash Proceeds or Net Loss Proceeds from the date of such commitment;provided that (x) such investment is consummated within 180 days of the end of the 360-day period referred to in the first sentence of this clause (3), and (y) if such acquisition is not consummated within the period set forth in subclause (x) or such binding commitment is terminated, the Net Cash Proceeds or Net Loss Proceeds not so applied will be deemed to be Excess Proceeds (as defined below). For the avoidance of doubt, pending application thereof in accordance with this covenant, the Company or any Restricted Subsidiary may use any Net Cash Proceeds from an Asset Sale or Net Loss Proceeds for general corporate purposes (including a reduction in borrowings under any revolving credit facility) prior to the end of the 360-day period referred to in the first sentence of this clause (3).

(4) The Net Cash Proceeds of an Asset Sale and any Net Loss Proceeds, as applicable, not applied pursuant to clause (3) within 360 days of the receipt of Net Cash Proceeds or Net Loss Proceeds, as applicable, constitute “Excess Proceeds.” Excess Proceeds of less than $15.0 million will be carried forward and accumulated. When the aggregate amount of the accumulated Excess Proceeds equals or exceeds such amount, the Company must, within 30 days, make an Offer to Purchase to all holders of Notes equal to the accumulated Excess Proceeds. The purchase price for the Notes will be 100% of the principal amount plus accrued interest to the date of purchase. If the Offer to Purchase is for less than all of the Outstanding Notes and Notes in an aggregate principal amount in excess of the purchase amount are tendered and not withdrawn pursuant to the offer, the Company will purchase Notes having an aggregate principal amount equal to the purchase amount on a pro rata basis, with adjustments so that only Notes in multiples of $1,000 principal amount (and in a minimum amount of $2,000) will be purchased. Upon completion of the Offer to Purchase, Excess Proceeds will be reset at zero, and any Excess Proceeds remaining after consummation of the Offer to Purchase may be used for any purpose not otherwise prohibited by the Indenture.

The Company shall determine in good faith whether, and to what extent, an Asset Sale or an Event of Loss is in respect of Notes Priority Collateral and to what extent the Net Cash Proceeds in respect of an Asset Sale or Net Loss Proceeds, as applicable, of Notes Priority Collateral are used to acquire or are invested in Notes Priority Collateral taking into account all relevant factors, including without limitation, the existence of structurally senior claims against the Notes Priority Collateral and the assets of an entity whose Capital Stock is subject to such Asset Sale or acquired with such Net Cash Proceeds or is the subject of the Event of Loss.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the purchase of the Notes pursuant to an Offer to Purchase pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions in the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached their obligations under the Asset Sale provisions of the Indenture by virtue of such conflict or compliance.

Limitation on Transactions with Affiliates

(a) The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, enter into, renew or extend any transaction or arrangement including the purchase, sale, lease or exchange of property or assets, or the rendering of any service with any Affiliate of the Company or any Restricted Subsidiary (a “Related Party Transaction”), unless the Related Party Transaction is on fair and reasonable terms that are not materially less favorable (as reasonably determined by the Company) to the Company or the relevant Restricted Subsidiary than those that could be obtained in a comparable arm’s-length transaction with a Person that is not an Affiliate of the Company.

(b) Any Related Party Transaction or series of Related Party Transactions with an aggregate value in excess of $10.0 million must be approved in advance by a majority of the Board of Directors who are disinterested in the subject matter of the transaction pursuant to a Board Resolution. Prior to entering into any Related Party

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Transaction or series of Related Party Transactions with an aggregate value in excess of $25.0 million, the Company must in addition obtain a favorable written opinion from a nationally recognized investment banking firm (or, with respect to transactions involving coal reserves or other mining-related assets, nationally recognized reserve engineers) as to the fairness of the transaction to the Company and its Restricted Subsidiaries from a financial point of view.

(c) The foregoing paragraphs do not apply to:

(1) any transaction between the Company and any of its Restricted Subsidiaries or between Restricted Subsidiaries of the Company;

(2) the payment of reasonable and customary regular fees to directors of the Company who are not employees of the Company;

(3) any Restricted Payments or Permitted Investments that do not violate the provisions of the Indenture described under the “Limitation on Restricted Payments” covenant;

(4) any issuance of Equity Interests (other than Disqualified Equity Interests) of the Company;

(5) loans or advances to officers, directors or employees of the Company in the ordinary course of business of the Company or its Restricted Subsidiaries or Guarantees in respect thereof or otherwise made on their behalf (including payment on such Guarantees) and only to the extent permitted by applicable law;

(6) any employment, consulting, service or termination agreement, or reasonable and customary indemnification arrangements, entered into by the Company or any of its Restricted Subsidiaries with officers, employees or consultants of the Company or any of its Restricted Subsidiaries that are Affiliates of the Company and the payment of fees or compensation to such officers, employees or consultants (including amounts paid pursuant to employee benefit plans, employee stock option or similar plans) so long as such agreement has been entered into in the ordinary course of business;

(7) transactions with a Person (other than an Unrestricted Subsidiary of the Company) that is an Affiliate solely because the Company, directly or through a Restricted Subsidiary, owns Equity Interests in such Person or owes Indebtedness to such Person; or

(8) transactions arising under any contract, agreement, instrument or arrangement in effect on the Issue Date and described in this prospectus, including the Armstrong Resource Partners Lease Agreements, the Royalty Deferment and Option Agreement and the Credit and Collateral Support Fee, Indemnification and Right of First Refusal Agreement.

Designation of Restricted and Unrestricted Subsidiaries

(a) The Company may designate any Subsidiary, including a newly acquired or created Subsidiary, to be an Unrestricted Subsidiary if it meets the following qualifications and the designation would not cause a Default.

(1) Such Subsidiary does not own any Capital Stock of the Company or any Restricted Subsidiary or hold any Indebtedness of, or any Lien on any property of, the Company or any Restricted Subsidiary.

(2) At the time of the designation, the designation would be permitted under the covenant described under “Limitation on Restricted Payments.”

(3) To the extent the Indebtedness of the Subsidiary is not Non-Recourse Indebtedness, any Guarantee or other credit support thereof by the Company or any Restricted Subsidiary is permitted under the covenants described under “Limitation on Indebtedness or Preferred Stock” and “Limitation on Restricted Payments.”

(4) The Subsidiary is not party to any transaction or arrangement with the Company or any Restricted Subsidiary that would not be permitted under the “Limitation on Transactions with Affiliates” covenant after giving effect to the exceptions thereto.

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(5) Neither the Company nor any Restricted Subsidiary has any obligation to subscribe for additional Equity Interests of the Subsidiary or to maintain or preserve its financial condition or cause it to achieve specified levels of operating results, except to the extent permitted by the “Limitation on Indebtedness or Preferred Stock” and “Limitation on Restricted Payments” covenants.

Once so designated the Subsidiary will remain an Unrestricted Subsidiary, subject to paragraph (b).

(b)(1) A Subsidiary previously designated an Unrestricted Subsidiary which fails to meet the qualifications set forth in paragraph (a) will be deemed to become at that time a Restricted Subsidiary, subject to the consequences set forth in paragraph (d).

(2) The Board of Directors may designate an Unrestricted Subsidiary to be a Restricted Subsidiary if the designation would not cause a Default.

(c) Upon a Restricted Subsidiary becoming an Unrestricted Subsidiary,

(1) all existing Investments of the Company and the Restricted Subsidiaries therein (valued at the Company’s proportional share of the Fair Market Value of its assets less liabilities) will be deemed made at that time;

(2) all existing Capital Stock or Indebtedness of the Company or a Restricted Subsidiary held by it will be deemed Incurred at that time, and all Liens on property of the Company or a Restricted Subsidiary held by it will be deemed Incurred at that time;

(3) all existing transactions between it and the Company or any Restricted Subsidiary will be deemed entered into at that time;

(4) it shall be released at that time from its Note Guarantee, if any; and

(5) it will cease to be subject to the provisions of the Indenture as a Restricted Subsidiary.

(d) Upon an Unrestricted Subsidiary becoming, or being deemed to become, a Restricted Subsidiary,

(1) all of its Indebtedness and Disqualified Stock or Preferred Stock will be deemed Incurred at that time for purposes of “Limitation on Indebtedness or Preferred Stock”, but will not be considered the sale or issuance of Equity Interests for purposes of “Limitation on Asset Sales”;

(2) Investments therein previously charged under “Limitation on Restricted Payments” will be credited thereunder;

(3) it may be required to issue a Note Guarantee pursuant to “Note Guarantees by Restricted Subsidiaries”; and

(4) it will thenceforward be subject to the provisions of the Indenture as a Restricted Subsidiary.

(e) Any designation by the Company of a Subsidiary as a Restricted Subsidiary or Unrestricted Subsidiary will be evidenced to the Trustee by promptly filing with the Trustee a copy of the Board Resolution giving effect to the designation and an Officers’ Certificate certifying that the designation complied with the foregoing provisions.

SEC Reports

The Company will furnish to the Trustee and, upon request, to holders of the Notes, beneficial owners of the Notes and prospective investors that certify to the reasonable satisfaction of the Company that they are “qualified institutional buyers” (within the meaning of Rule 144A under the Securities Act) or otherwise eligible to hold the Notes copies of all of the information and reports referred to in clauses (1) and (2) below within the time periods specified in the SEC’s rules and regulations:

(1) all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Company were required to file such Forms, including a

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“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual information only, a report on the annual financial statements by the Company’s certified independent accountants; and

(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports,

in each case in a manner that complies in all material respects with the requirements specified with respect to such information and reports in such forms; provided that nothing contained in the Indenture shall otherwise require the Company to comply with the provisions of the Sarbanes-Oxley Act or the Dodd–Frank Wall Street Reform and Consumer Protection Act at any time when it would not otherwise be subject to such statutes.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by this covenant will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

The Company will also hold a quarterly conference call to discuss financial information delivered to holders. Prior to the conference call, the Company shall issue a press release to the appropriate wire services announcing the time and date of such conference call and, unless the call is to be open to the public, direct holders of Notes, securities analysts and prospective investors to contact the office of the Company’s chief financial officer to obtain access. If the Company is holding a conference call open to the public to discuss the most recent quarter’s financial performance, the Company will not be required to hold a second, separate call just for the holders of the Notes.

In addition, to the extent not satisfied by the foregoing, the Company shall furnish to the holders of the Notes and to securities analysts and prospective investors, upon their request, any information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act so long as the Notes are not freely transferable under the Securities Act.

Consolidation, Merger or Sale of Assets

(a) The Company will not:

• consolidate with or merge with or into any Person; or

• sell, convey, transfer, lease or otherwise dispose of all or substantially all of the Company’s assets (determined on a consolidated basis for the Company and its Restricted Subsidiaries), in one transaction or a series of related transactions, whether effected by the Company and/or one or more of its Restricted Subsidiaries, to any Person;

unless:

(1) either (x) the Company is the continuing Person or (y) the resulting, surviving or transferee Person is a Person organized and validly existing under the laws of the United States of America, any state thereof or the District of Columbia and expressly assumes by supplemental indenture (or other joinder agreement, as applicable) all of the obligations of the Company under the Indenture, the Notes, and the Security Documents;provided that if the Company or the resulting, surviving or transferee Person is not a corporation, there shall be a co-obligor on the Notes that is a corporation organized and validly existing under the laws of the United States of America, any state thereof or the District of Columbia;

(2) immediately after giving effect to the transaction, no Default has occurred and is continuing;

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(3) immediately after giving effect to the transaction on a pro forma basis, the Company or the resulting surviving or transferee Person could Incur at least $1.00 of Indebtedness under the Fixed Charge Coverage Ratio Test; and

(4) the Company delivers to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that the consolidation, merger or transfer and the supplemental indenture (if any) comply with the Indenture and that the supplemental indenture (if any) is the legal, valid and binding obligation of the Company;

provided,that clauses (2) and (3) do not apply (i) to the consolidation, merger, sale, conveyance, transfer or other disposition of the Company with, into or to a Restricted Subsidiary or the consolidation, merger, sale, conveyance, transfer or other disposition of a Restricted Subsidiary with, into or to the Company or (ii) if, in the good faith determination of the Board of Directors of the Company, whose determination is evidenced by a Board Resolution, the sole purpose of the transaction is to change the jurisdiction of incorporation of the Company.

(b) Upon the consummation of any transaction effected in accordance with these provisions, if the Company is not the continuing Person, the resulting, surviving or transferee Person will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture, the Notes and the Security Documents with the same effect as if such successor Person had been named as the Company in the Indenture. Upon such substitution, except in the case of a sale, conveyance, transfer or disposition of less than all its assets, the Company will be released from its obligations under the Indenture and the Notes.

(c) No Guarantor may:

• consolidate with or merge with or into any Person; or

• sell, convey, transfer, lease or dispose of all or substantially all of the Guarantor’s assets, in one transaction or a series of related transactions, to any Person;

unless:

(A) the other Person is the Company or any Restricted Subsidiary that is a Guarantor or becomes a Guarantor concurrently with the transaction; or

(B)(1) either (x) the Guarantor is the continuing Person or (y) the resulting, surviving or transferee Person expressly assumes by supplemental indenture (or other joinder agreement, as applicable) all of the obligations of the Guarantor under its Note Guarantee and the Security Documents, as applicable; and

(2) immediately after giving effect to the transaction, no Default has occurred and is continuing; or

(C) the transaction constitutes a sale or other disposition (including by way of consolidation or merger) of the Guarantor or the sale or disposition of all or substantially all the assets of the Guarantor (in each case other than to the Company or a Restricted Subsidiary) otherwise permitted by the Indenture; and,

(D) in each of (A), (B) and (C) above, the Guarantor delivers to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that the consolidation, merger or transfer and the supplemental indenture (if any) comply with the Indenture, and that the supplemental indenture (if any) is the legal, valid and binding obligation of the Guarantor.

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Default and Remedies

Events of Default.

An “Event of Default” occurs with respect to the Notes if:

(1) the Company defaults in the payment of the principal of any Note when the same becomes due and payable at maturity, upon acceleration or redemption, or otherwise (other than pursuant to an Offer to Purchase);

(2) the Company defaults in the payment of interest on any Note when the same becomes due and payable, and the default continues for a period of 30 days;

(3) the Company fails to make an Offer to Purchase and thereafter accept and pay for Notes tendered when and as required under the “Repurchase of Notes Upon a Change of Control” covenant or the Company fails to comply with the “Consolidation, Merger or Sale of Assets” covenant;

(4) the Company defaults in the performance of or breaches any of its other covenants or agreements in the Indenture or under the Notes (other than a default specified in clauses (1), (2) or (3) above) and the default or breach continues for a period of 60 consecutive days after written notice to the Company by the Trustee or to the Company and the Trustee by the holders of 25% or more in aggregate principal amount of the Notes;

(5) there occurs with respect to any Indebtedness of the Company or any of its Restricted Subsidiaries having an outstanding principal amount of $20.0 million or more in the aggregate for all such Indebtedness of all such Persons (i) an event of default that results in such Indebtedness being due and payable prior to its scheduled maturity or (ii) failure to make a principal payment on such Indebtedness when due and such defaulted payment is not made, waived or extended within the applicable grace period;

(6) one or more final judgments or orders for the payment of money are rendered against the Company or any of its Restricted Subsidiaries and are not paid or discharged, and there is a period of 60 consecutive days following entry of the final judgment or order that causes the aggregate amount for all such final judgments or orders outstanding and not paid or discharged against all such Persons to exceed $20.0 million (in excess of amounts which the Company’s insurance carriers have agreed to pay under applicable policies) during which a stay of enforcement, by reason of a pending appeal or otherwise, is not in effect;

(7) certain bankruptcy defaults occur with respect to the Company or any Restricted Subsidiary;

(8) any Note Guarantee of a Significant Restricted Subsidiary ceases to be in full force and effect, other than in accordance with the terms of the Indenture, or a Guarantor that is a Significant Restricted Subsidiary denies or disaffirms its obligations under its Note Guarantee; or

(9) unless all of the Collateral has been released from the Note Liens in accordance with the provisions of the Security Documents, (x) default by the Company or any Guarantor in the performance of the Security Documents which materially adversely affects the enforceability, validity, perfection or priority of the Note Liens on a material portion of the Collateral, (y) the repudiation or disaffirmation by the Company or any Guarantor of its material obligations under the Security Documents or (z) the determination in a judicial proceeding that the Security Documents are unenforceable or invalid against the Company or any Guarantor party thereto for any reason with respect to a material portion of the Collateral and, in the case of any event described in subclauses (x) through (z), such default, repudiation, disaffirmation or determination is not rescinded, stayed, or waived by the Persons having such authority pursuant to the Security Documents or otherwise cured within 60 days after the Company receives written notice thereof specifying such occurrence from the Trustee or the holders of at least 25% of the outstanding principal amount of the Notes (with a copy to the Trustee) and demanding that such default be remedied.

Consequences of an Event of Default.

If an Event of Default, other than a bankruptcy default with respect to the Company, occurs and is continuing under the Indenture with respect to the Notes, the Trustee or the holders of at least 25% in aggregate

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principal amount of the Notes then outstanding, by written notice to the Company (and to the Trustee if the notice is given by the holders), may, declare the principal of and accrued interest on the Notes to be immediately due and payable. Upon a declaration of acceleration, such principal and accrued interest will become immediately due and payable. If a bankruptcy default occurs with respect to the Company, the principal of and accrued interest on the Notes then outstanding will become immediately due and payable without any declaration or other act on the part of the Trustee or any holder.

The holders of a majority in principal amount of the Outstanding Notes by written notice to the Company and to the Trustee may waive all past defaults and rescind and annul a declaration of acceleration and its consequences if:

(1) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by the declaration of acceleration, have been cured or waived;

(2) the rescission would not conflict with any judgment or decree of a court of competent jurisdiction; and

(3) all amounts owing to the Trustee have been paid;

Except as otherwise provided in “—Consequences of an Event of Default” or “—Amendments and Waivers —Amendments with Consent of Holders,” the holders of a majority in principal amount of the Outstanding Notes may, by written notice to the Trustee, waive an existing Default and its consequences. Upon such waiver, the Default will cease to exist, and any Event of Default arising therefrom will be deemed to have been cured, but no such waiver will extend to any subsequent or other Default or impair any right consequent thereon.

In the event of a declaration of acceleration of the Notes because an Event of Default described in clause (5) under “Events of Default” has occurred and is continuing, the declaration of acceleration of the Notes shall be automatically annulled, without any action by the Trustee or the holders, if the event of default or payment default triggering such Event of Default pursuant to clause (5) shall be remedied or cured, or rescinded or waived by the holders of the Indebtedness, or the Indebtedness that gave rise to such Event of Default shall have been discharged in full, within 30 days after the declaration of acceleration with respect thereto and if (i) the annulment of the acceleration of the Notes would not conflict with any judgment or decree of a court of competent jurisdiction and (ii) all existing Events of Default, except nonpayment of principal, premium or interest on the Notes that became due solely because of the acceleration of the Notes, have been cured or waived.

The holders of a majority in principal amount of the Outstanding Notes may direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee. However, the Trustee may refuse to follow any direction that conflicts with law or the Indenture, that may involve the Trustee in personal liability, or that the Trustee determines in good faith may be unduly prejudicial to the rights of holders of Notes not joining in the giving of such direction. In addition, the Trustee may take any other action it deems proper that is not inconsistent with any such direction received from holders of Notes. The Trustee shall not be obligated to take any action at the direction of holders unless such holders have offered to the Trustee security or indemnity reasonably satisfactory to the Trustee.

A holder may not institute any proceeding, judicial or otherwise, with respect to the Indenture or the Notes, or for the appointment of a receiver or Trustee, or for any other remedy under the Indenture or the Notes, unless:

(1) the holder has previously given to the Trustee written notice of a continuing Event of Default;

(2) holders of at least 25% in aggregate principal amount of Outstanding Notes have made written request to the Trustee to institute proceedings in respect of the Event of Default in its own name as Trustee under the Indenture;

(3) holders have offered to the Trustee security or indemnity satisfactory to the Trustee against any costs, liabilities or expenses to be incurred in compliance with such request;

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(4) the Trustee for 60 days after its receipt of such notice, request and offer of indemnity has failed to institute any such proceeding; and

(5) during such 60-day period, the holders of a majority in aggregate principal amount of the Outstanding Notes have not given the Trustee a direction that is inconsistent with such written request.

Notwithstanding anything to the contrary, the right of a holder of a Note to receive payment of principal of or interest on its Note on or after the Stated Maturities thereof, or to bring suit for the enforcement of any such payment on or after such dates, may not be impaired or affected without the consent of that holder.

If any Default occurs and is continuing and is known to a Responsible Officer of the Trustee, the Trustee will send notice of the Default to each holder within 90 days after it occurs, unless the Default has been cured or waived;providedthat,except in the case of a default in the payment of the principal of or interest on any Note, the Trustee may withhold the notice if and so long as the board of directors, the executive committee or a trust committee of directors and/or Responsible Officers of the Trustee in good faith determine that withholding the notice is in the interest of the holders.

No Personal Liability of Directors, Officers, Employees, Incorporators, Members and Stockholders

No director, officer, employee, incorporator, member or stockholder of the Company or any Guarantor, as such, will have any liability for any obligations of the Company or such Guarantor under the Notes, any Note Guarantee or the Indenture or for any claim based on, in respect of, or by reason of, such obligations. Each holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. This waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Amendments and Waivers

Amendments Without Consent of Holders

The Company and the Trustee may amend or supplement the Indenture, the Security Documents or the Notes without notice to or the consent of any holder of a Note:

(1) to cure any ambiguity, defect, omission or inconsistency in the Indenture or the Notes;

(2) to provide for the assumption of the Company’s or a Guarantor’s obligations to holders of the Notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of the Company’s or such Guarantor’s assets, as applicable;

(3) to comply with any requirements of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;

(4) to evidence and provide for the acceptance of an appointment by a successor Trustee;

(5) to provide for uncertificated Notes in addition to or in place of certificated Notes,provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f)(2)(B) of the Code;

(6) to provide for or confirm the issuance of additional Notes in accordance with the terms of the Indenture;

(7) to make any other change that does not materially and adversely affect the legal rights of any holder;

(8) to conform the text of the Indenture, the Note Guarantees, the Notes or the Security Documents to any provision of this Description of Exchange Notes to the extent that such provision in this Description of Exchange Notes was intended to be a verbatim recitation of a provision of the Indenture, the Note Guarantees, the Notes or the Security Documents;

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(9) to allow any Guarantor to execute a supplemental indenture and/or a Note Guarantee with respect to the Notes and to release any Guarantor from its Note Guarantee in accordance with the terms of the Indenture;

(10) to make, complete or confirm any grant of Collateral permitted or required by the Indenture or any of the Security Documents or any release of Collateral that becomes effective as set forth in the Indenture or any of the Security Documents, as applicable;

(11) if necessary, in connection with any addition or release of Collateral permitted under the terms of the Indenture or the Security Documents;

(12) to evidence or provide for the acceptance of appointment under the Indenture of a successor trustee or the Collateral Agent;

(13) to comply with the rules of any applicable securities depositary; or

(14) to provide for the succession of any parties to the Security Documents (and other supplements or amendments that are administrative or ministerial in nature) in connection with an amendment, renewal, extension, substitution, refinancing, restructuring, replacement, supplement or other modification from time to time of the Credit Agreement or any other agreement that is not prohibited by the Indenture.

Amendments With Consent of Holders

(a) Except as otherwise provided in “—Default and Remedies—Consequences of an Event of Default” or paragraph (b) below, the Company and the Trustee may amend the Indenture, the Security Documents and the Notes with the written consent of the holders of not less than a majority in aggregate principal amount of the Outstanding Notes and the holders of a majority in aggregate principal amount of the Outstanding Notes may waive future compliance by the Company with any provision of the Indenture, the Security Documents or the Notes.

(b) Notwithstanding the provisions of paragraph (a), without the consent of each holder affected, an amendment or waiver may not:

(1) reduce the principal amount of or change the Stated Maturity of any installment of principal of any Note,

(2) reduce the rate of or change the Stated Maturity of any interest payment on any Note,

(3) reduce the amount payable upon the redemption of any Note or change the time of any mandatory redemption or, in respect of an optional redemption, the times at which any Note may be redeemed or, once notice of redemption has been given, the time at which it must thereupon be redeemed,

(4) after the time an Offer to Purchase is required to have been made, reduce the purchase amount or purchase price, or extend the latest expiration date or purchase date thereunder,

(5) make any Note payable in money other than that stated in the Note,

(6) impair the right of any holder of Notes to receive any principal payment or interest payment on such holder’s Notes or Note Guarantee, on or after the Stated Maturity thereof, or to institute suit for the enforcement of any such payment,

(7) make any change in the percentage of the principal amount of the Notes whose holders must consent to an amendment, supplement or waiver,

(8) modify or change any provision of the Indenture affecting the ranking of the Notes or any Note Guarantee in a manner materially adverse to the holders of the Notes, or

(9) release any Guarantor that is a Restricted Subsidiary from any of its Obligations under its Note Guarantee or the Indenture other than in accordance with the provisions of the Indenture, or amend or modify any provision relating to such release.

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In addition, any amendment to, or waiver of, the provisions of the Indenture or any Security Document that has the effect of releasing all or substantially all of the Collateral from the Liens securing the Notes or subordinating Liens securing the Notes (except as permitted by the terms of the Indenture or the Security Documents) will require the consent of at least 66 ²/₃% in aggregate principal amount of the Notes then outstanding.

It is not necessary for holders of Notes to approve the particular form of any proposed amendment, supplement or waiver, but is sufficient if their consent approves the substance thereof.

Discharge and Defeasance

The Company and the Guarantors may discharge their obligations under the Notes and the Indenture by irrevocably depositing in trust with the Trustee money or U.S. Government Obligations sufficient to pay principal of and interest on the Notes to maturity or redemption within one year, subject to meeting certain other conditions.

The Company may also elect to:

(1) discharge most of its obligations in respect of the Notes and the Indenture, not including obligations related to the defeasance trust or to the replacement of Notes or their obligations to the Trustee (“legal defeasance”); or

(2) discharge its obligations under most of the covenants and under clauses (a)(3) and (a)(4) of “Consolidation, Merger or Sale of Assets” with respect to Notes (and the events listed in clauses (3), (4), (5), (6) and (8) under “—Default and Remedies—Events of Default” will no longer constitute Events of Default) (“covenant defeasance”);

if the Company deposits in trust with the Trustee money or U.S. Government Obligations sufficient to pay principal of and interest on the Notes to maturity or redemption and meets certain other conditions, including delivery to the Trustee of an Opinion of Counsel reasonably satisfactory to the Trustee to the effect that the holders will not recognize income, gain or loss for federal income tax purposes as a result of the defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would otherwise have been the case. In the case of legal defeasance, such an opinion must be based on a ruling of the Internal Revenue Service or other change in the applicable United States federal income tax law since the date of the Indenture. The defeasance would in each case be effective when 123 days have passed since the date of the deposit in trust.

In the case of either discharge or defeasance, the Note Guarantees, if any, will terminate with respect to Notes.

Concerning the Trustee and Paying Agent

Wells Fargo Bank, National Association, is the Trustee under the Indenture. Except during the continuance of an Event of Default of which a Responsible Officer of the Trustee shall have actual knowledge, the Trustee need perform or be required to perform only those duties that are specifically set forth in the Indenture and no others, and no implied covenants or obligations will be read into the Indenture against the Trustee. In case an Event of Default of which a Responsible Officer of the Trustee shall have actual knowledge has occurred and is continuing, the Trustee shall exercise those rights and powers vested in it by the Indenture, and use the same degree of care and skill in their exercise, as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. No provision of the Indenture requires the Trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties thereunder, or in the exercise of its rights or powers, unless it receives security or indemnity reasonably satisfactory to it against any loss, liability or expense.

The Indenture and provisions of the Trust Indenture Act incorporated by reference therein contain limitations on the rights of the Trustee, should it become a creditor of any obligor on the Notes, to obtain

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payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee is permitted to engage in other transactions with the Company and its Affiliates;providedthat if it acquires any conflicting interest, as defined in the Trust Indenture Act, it must either eliminate the conflict within 90 days, apply to the SEC for permission to continue or resign. To the extent permitted under the Trust Indenture Act, the Trustee or its Affiliates are each permitted to receive additional compensation that could be deemed to be in the Trustee’s or such Affiliates’ economic self-interest for (i) serving as investment adviser, administrator, servicing agent, custodian or subcustodian with respect to certain investments, (ii) using Affiliates to effect transactions in certain investments and (iii) effecting transactions in certain investments.

The Trustee shall not be responsible for and makes no representation as to the existence, genuineness, value or protection of any Collateral, for the legality, effectiveness or sufficiency of any Security Document, or for the creation, perfection, priority, sufficiency or protection of any Liens securing the Notes. The Trustee shall not be responsible for filing any financing or continuation statements or recording any documents or instruments in any public office at any time or times or otherwise perfecting or maintaining the perfection of any Lien or security interest in the Collateral. The Trustee shall have no responsibility for any act or omission of the Collateral Agent. By their acceptance of the Notes, the Holders will be deemed to have authorized the Trustee to enter into and to perform each of the Security Documents to which it is a party.

The paying agent for the Notes will initially be the Trustee. We may at any time designate additional paying agents or rescind the designation of paying agents or approve a change in the office through which any paying agent acts. We may also choose to act as our own paying agent, but must maintain a paying agency in the continental United States. Whenever there are changes in the paying agent for the Notes we must notify the Trustee in writing. The paying agent will also initially serve as the security registrar, the transfer agent and authentication agent for the Notes.

References to the Trustee shall, as appropriate, refer also to the paying agent, transfer agent, security registrar and authentication agent, depository custodian, and such other entities shall be entitled to the same rights, protections and indemnities granted to the Trustee.

The Trustee or its Affiliates may from time to time in the future provide banking and other services to us in the ordinary course of their business.

Book-Entry, Delivery and Form

The Outstanding Notes were offered and sold to qualified institutional buyers in reliance on Rule 144A (“Rule 144A Notes”). Notes also may be offered and sold in offshore transactions in reliance on Regulation S (“Regulation S Notes”). Except as set forth below, the Notes will be issued in registered, global form inminimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. Notes will be issued at the closing of this offering only against payment in immediately available funds.

Rule 144A Notes initially will be represented by one or more Notes in registered, global form without interest coupons (collectively, the “Rule 144A Global Notes”). Regulation S Notes initially will be represented by one or more Notes in registered, global form without interest coupons (collectively, the “Temporary Regulation S Global Notes”). Beneficial ownership interests in a Temporary Regulation S Global Note will be exchangeable for interests in a Rule 144A Global Note, a permanent global Note (the “Permanent Regulation S Global Note”) or a definitive Note in registered certificated form (a “Certificated Note”) only after the expiration of the period through and including the 40th day after the later of the commencement and the closing of this offering (the “Distribution Compliance Period”) and then only (1) upon certification in form reasonably satisfactory to the Trustee that beneficial ownership interests in such Temporary Regulation S Global Note are owned either by non-U.S. persons or U.S. persons who purchased such interests in a transaction that did not require registration under the Securities Act, and (2) in the case of an exchange for a Certificated Note, in

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compliance with the requirements described under “—Exchange of Global Notes for Certificated Notes.” The Temporary Regulation S Global Note and the Permanent Regulation S Global Note are referred to herein as the “Regulation S Global Notes” and the Rule 144A Global Notes and the Regulation S Global Notes are collectively referred to herein as the “Global Notes.” The Global Notes will be deposited upon issuance with the Trustee as custodian for DTC, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below. Beneficial interests in the Rule 144A Global Notes may not be exchanged for beneficial interests in the Regulation S Global Notes at any time except in the limited circumstances described below. See “—Exchanges Among Global Notes.”

Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may be exchanged for Notes in certificated form. See “—Exchange of Global Notes for Certificated Notes.”

Rule 144A Notes (including beneficial interests in the Rule 144A Global Notes) will be subject to certain restrictions on transfer and will bear a restrictive legend as described under “Notice to Investors.” Regulation S Notes will also be subject to transfer restrictions and will also bear the legend as described under “Notice to Investors.” In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC is provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. Neither the Company nor the Trustee take any responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised the Company that DTC is a limited purpose trust company organized under the laws of the State of New York, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are notParticipants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised the Company that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the Initial Purchasers with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

Investors in the Global Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly

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through organizations (including Euroclear and Clearstream) which are Participants in such system. All interests in a Global Note may be subject to the procedures and requirements of DTC. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of participants, which in turn act on behalf of indirect participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have Notes registered in their names, will not receive physical delivery of Notes in certificated form and will not be considered the registered owners or “holders” thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, the Company and the Trustee will treat the Persons in whose names the Notes, including the Global Notes, are registered as the owners thereof for the purpose of receiving payments and for all other purposes. Consequently, none of the Company, the Trustee or any agent of the Company or the Trustee has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised the Company that its current practices, upon receipt of any payment in respect of securities such as the Notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of Notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or the Company. Neither the Company nor the Trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the Notes, and the Company and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Subject to the transfer restrictions set forth under “Notice to Investors,” transfers between Participants in DTC will be affected in accordance with DTC’s procedures and will be settled in same-day funds.

DTC has advised the Company that it will take any action permitted to be taken by a holder of Notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the Notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the Notes, DTC reserves the right to exchange the Global Notes for legended Notes in certificated form, and to distribute such Notes to its Participants.

Although DTC has agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, it is under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. Neither the Company nor the Trustee nor any of their respective

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agents will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for a Certificated Note if:

(1) DTC (a) notifies the Company that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act, and in each case the Company fails to appoint a successor depositary; or

(2) there will have occurred and be continuing an Event of Default with respect to the Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in “Notice to Investors,” unless that legend is not required by applicable law.

Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the Trustee a written certificate (in the form provided in the Indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such Notes. See “Notice to Investors.”

Exchanges Among Global Notes

Beneficial interests in a Temporary Regulation S Global Note may be exchanged for beneficial interests in a Permanent Regulation Global Note or a Rule 144A Global Note only after the expiration of the Distribution Compliance Period and then only upon certification in form reasonably satisfactory to the Trustee that, among other things, beneficial ownership interests in such Temporary Regulation S Note are owned by or being transferred to either non-U.S. persons or U.S. persons who purchased such interests in a transaction that did not require registration under the Securities Act.

Beneficial interests in a Rule 144A Global Note may be transferred to a Person who takes delivery in the form of an interest in the Regulation S Global Note, whether before or after the expiration of the Distribution Compliance Period, only if the transferor first delivers to the Trustee a written certificate (in the form provided in the Indenture) to the effect that such transfer is being made in accordance with Rule 903 or 904 of Regulation S or Rule 144 (if available).

Transfers involving exchanges of beneficial interests between a Regulation S Global Note and a Rule 144A Global Note will be effected in DTC by means of an instruction originated by the Trustee through the DTC Deposit/Withdraw at Custodian system. Accordingly, in connection with any such transfer, appropriate adjustments will be made to reflect the changes in the principal amounts of the Regulation S Global Notes and the Rule 144A Global Notes, as applicable. Any beneficial interest in one of the Global Notes that is transferred to a Person who takes delivery in the form of an interest in the other Global Note will, upon transfer, cease to be an interest in such Global Note and will become an interest in the other Global Note and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to a beneficial interest in such other Global Note for so long as it remains such an interest.

Same Day Settlement and Payment

The Company will make payments in respect of the Notes represented by the Global Notes (including principal, premium, if any, and interest) by wire transfer of immediately available funds to the accounts specified

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by the Global Note holder. The Company will make all payments of principal, interest and premium, if any, with respect to Certificated Notes by wire transfer of immediate available funds to the accounts specified by the holders thereof or, if no such account is specified, by mailing a check to each such holder’s registered address. The Notes represented by the Global Notes are expected to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity of such Notes will, therefore, be required by DTC to be settled in immediately available funds. The Company expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Registration Rights

The Company and the Guarantors agreed, pursuant to the Registration Rights Agreement, that the Company and the Guarantors shall, at their cost:

(1) use their reasonable best efforts to file a registration statement (the “Exchange Offer Registration Statement”) with the SEC with respect to a registered offer (the “Registered Exchange Offer”) to exchange each Outstanding Note for a new Note (the “Exchange Notes”) having terms substantially identical in all material respects to such Outstanding Note (except that the Exchange Note will not contain terms with respect to transfer restrictions) or the payment of liquidated damages as described below;

(2) use their reasonable best efforts (which shall include filing of all the necessary amendments to such Registration Statement) to cause the Exchange Offer Registration Statement to be declared (or to become automatically) effective under the Securities Act;

(3) promptly following the effectiveness of the Exchange Offer Registration Statement, offer the Exchange Notes in exchange for surrender of the Notes; and

(4) keep the Registered Exchange Offer open for not less than 20 business days (or longer if required by applicable law or any broker-dealer, as described below) after the date notice of the Registered Exchange Offer is mailed to the holders of the Notes.

For each Note tendered pursuant to the Registered Exchange Offer, the Company and the Guarantors will issue to the holder of such Note an Exchange Note having a principal amount equal to that of the surrendered Note. Interest on each Exchange Note will accrue from the last interest payment date on which interest was paid on the Note surrendered in exchange thereof or, if no interest has been paid on such Note, from the Issue Date.

Under existing SEC interpretations, the Exchange Notes will be freely transferable by holders of the Notes other than the Company’s affiliates after the Registered Exchange Offer without further registration under the Securities Act if the holder of the Exchange Notes represents that it is acquiring the Exchange Notes in the ordinary course of its business, that it has no arrangement or understanding with any person to participate in thedistribution of the Exchange Notes and that it is not an affiliate of the Company and the Guarantors, as such terms are interpreted by the SEC;provided,however, that broker-dealers (“Participating Broker-Dealers”) receiving Exchange Notes in the Registered Exchange Offer will have a prospectus delivery requirement with respect to resales of such Exchange Notes. The SEC has taken the position that Participating Broker-Dealers may fulfill their prospectus delivery requirements with respect to Exchange Notes (other than a resale of an unsold allotment from the original sale of the Notes) with the prospectus contained in the Exchange Offer Registration Statement.

In the event that applicable interpretations of the staff of the SEC do not permit us to effect a Registered Exchange Offer, then the Company and the Guarantors will, subject to certain exceptions:

(a) use their reasonable best efforts to file a shelf registration statement (the “Shelf Registration Statement” covering resales of the Notes and to cause the Shelf Registration Statement to be declared (or to become automatically) effective under the Securities Act; and

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(b) keep the Shelf Registration Statement effective until the earliest of (i) the time when the Notes covered by the Shelf Registration Statement can be sold pursuant to Rule 144 without any restrictive legend or volume limitations, (ii) one year from the effective date of the Shelf Registration Statement and (iii) the date on which all Notes registered thereunder are disposed of in accordance therewith.

The Company will, in the event a Shelf Registration Statement is filed, among other things, provide to each Holder for whom such Shelf Registration Statement was filed copies of the prospectus which is a part of the Shelf Registration Statement, notify each such holder when the Shelf Registration Statement has become effective and take certain other actions as are required to permit unrestricted resales of the Notes or the Exchange Notes, as the case may be. A holder selling such Notes or Exchange Notes pursuant to the Shelf Registration Statement generally would be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the Registration Rights Agreement that are applicable to such holder (including certain indemnification obligations).

If the Exchange Offer Registration Statement (or, if required, the Shelf Registration Statement) is not filed and the Registered Exchange Offer is not completed (or, if required, the Shelf Registration Statement is not declared (or does not become automatically) effective) on or before March 31, 2014;provided,however, that such deadline shall be extended until June 30, 2014 if the Company, diligently and in good faith, has attempted to file the Exchange Offer Registration Statement (or, if required, the Shelf Registration Statement) and complete the Registered Exchange Offer (or, if required, to ensure that the Shelf Registration Statement is effective (either of such event, a “Registration Default”), then the Company and the Guarantors agree to pay each holder of Notes liquidated damages in the form of additional interest in an amount equal to 0.25% per annum of the principal amount of Notes held by such holder, with respect to the first 90 days after the date of the Registration Default (which rate shall be increased by an additional 0.25% per annum for each subsequent 90-day period that such liquidated damages continue to accrue) until the Registration Default no longer exists;provided,however, that at no time shall the amount of liquidated damages accruing exceed in the aggregate 1.00% per annum. Upon filing of the Exchange Offer Registration Statement (or, if required, the Shelf Registration Statement), or thecompletion of the Registered Exchange Offer (or, if required, the effectiveness of the Shelf Registration Statement or termination thereof in accordance with the Registration Rights Agreement), the liquidated damages in the form of additional interest described in this paragraph will cease to accrue.

All references in the Indenture and in this “Description of Exchange Notes” in any context, to any interest or other amount payable on or with respect to the Notes, shall be deemed to include any additional interest payable pursuant to the Registration Rights Agreement.

Holders of Notes will be required to make certain representations to the Company (as described in the Registration Rights Agreement) in order to participate in the Registered Exchange Offer, to deliver certain information to be used in connection with the Shelf Registration Statement and to provide comments on the Shelf Registration Statement within the time periods set forth in the Registration Rights Agreement in order to have their Notes included in the Shelf Registration Statement and benefit from the provisions regarding additional interest set forth above. By acquiring Notes, a holder will be deemed to have agreed to indemnify the Company and the Guarantors against certain losses arising out of information furnished by such holder in writing for inclusion in any Shelf Registration Statement. Holders of Notes will also be required to suspend their use of the prospectus included in the Shelf Registration Statement under certain circumstances upon receipt of written notice to that effect from the Company.

In connection with the exchange offer, we have filed with the SEC a registration statement on Form S-4, of which this prospectus is a part, relating to the Exchange Notes to be issued in the exchange offer. As permitted by SEC rules, this prospectus omits certain information included in the registration statement. For a complete understanding of the exchange offer, you should refer to the registration statement, including its exhibits. We refer you to the provisions of the Registration Rights Agreement, a copy of which has been filed as an exhibit to the registration statement.

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Governing Law

The Indenture, the Security Documents, the Intercreditor Agreement, the Notes, the Note Guarantees and the Registration Rights Agreement are governed by and construed in accordance with the laws of the State of New York (other than certain mortgages and control agreements which will be governed by the law of the respective local jurisdiction).

Certain Definitions

Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“ABL Facility Collateral Agent” means PNC Bank, National Association, as collateral agent under the Credit Agreement, and its successors, replacements and/or assigns in such capacity.

“ABL Liens”means all Liens in favor of the ABL Facility Collateral Agent on Collateral securing the ABL Obligations.

“ABL Obligations” means the Indebtedness and other obligations which are secured by a Lien on the Collateral permitted by clause (3) under the definition of “Permitted Liens”.

“ABL Priority Collateral” shall mean the following property of the Company and the Guarantors, whether now owned or hereafter acquired (but excluding Excluded Assets described under “—Security”):

(1) all accounts, other than accounts which constitute identifiable proceeds which arise from the sale, license, assignment or other disposition of Notes Priority Collateral;

(2) all chattel paper, other than chattel paper which constitutes identifiable proceeds of Notes Priority Collateral;

(3) all (x) deposit accounts and money and all cash, checks, other negotiable instruments, funds and other evidences of payments held therein, and (y) securities accounts and security entitlements and securities credited thereto, and, in each case, all cash, checks and other property held therein or credited thereto;

(4) all inventory;

(5) as-extracted collateral (including as-extracted collateral from present and future operations regardless of whether such interests are presently owned or hereafter acquired);

(6) all trademarks and copyrights;

(7) to the extent relating to, evidencing or governing any of the items referred to in the preceding clauses (1) through (6) constituting ABL Priority Collateral, all documents, general intangibles (including coal sales agreements), instruments (including promissory notes) and commercial tort claims;

(8) to the extent relating to any of the items referred to in the preceding clauses (1) through (7) constituting ABL Priority Collateral, all supporting obligations and letter of credit rights;

(9) all books and records relating to the items referred to in the preceding clauses (1) through (8) constituting ABL Priority Collateral (including all books, databases, customer lists, and records, whether tangible or electronic), which contain any information relating to any of the items referred to in the preceding clauses (1) through (8); and

(10) all proceeds of any of the foregoing, including collateral security and guarantees with respect to any of the foregoing and all cash, money, insurance proceeds, instruments, securities, financial assets and deposit accounts.

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“Acquired Indebtedness” means Indebtedness of a Person existing at the time the Person is acquired by, or merges with or into, the Company or any Restricted Subsidiary or becomes a Restricted Subsidiary and not Incurred in contemplation of the acquisition.

“Additional Assets” means all or substantially all of the assets of a Permitted Business, or Voting Stock of another Person engaged in a Permitted Business that will, on the date of acquisition, be a Restricted Subsidiary, or other assets (other than cash and Cash Equivalents, securities (including Equity Interests) or assets classified as current assets under GAAP) that are to be used in a Permitted Business of the Company or one or more of its Restricted Subsidiaries.

“Affiliate” means, with respect to any Person, any other Person who directly or indirectly through one or more intermediaries controls, or is controlled by, or is under common control with, such specified Person. The term “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Applicable Premium” means with respect to any Note on any redemption date the greater of (i) 1.0% of the principal amount of such Note and (ii) the excess (as determined by the Company) (if any) of (a) the present value at such redemption date of (1) the Notes at December 15, 2016, as set forth under “—Optional Redemption” plus (2) all required interest payments due on such Note from the redemption date through December 15, 2016 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate on such redemption date plus 50 basis points over (b) the principal amount of such Note.

“Armstrong Resource Partners” means Armstrong Resource Partners, L.P., a Delaware limited partnership.

“Armstrong Resource Partners Lease Agreements” means (i) the agreements between certain Subsidiaries of the Company and Armstrong Resource Partners as described in this prospectus under “Certain Relationships and Related Party Transactions—Lease Agreements” as in effect on the Issue Date and (ii) amendments, modifications or replacements, so long as the amended, modified or replacement agreements, taken as a whole at the time of execution, relate to the same reserve assets as the agreements in effect as of the Issue Date and are not materially less favorable to the Company and its Restricted Subsidiaries than those in effect on the Issue Date.

“Asset Sale” means any sale, lease (other than Capital Leases), transfer or other disposition of any assets by the Company or any Restricted Subsidiary, including by means of a merger, consolidation or similar transaction and including any sale or issuance of the Equity Interests of any Restricted Subsidiary but not of the Company (each of the above referred to as a “disposition”),providedthat the following are not included in the definition of “Asset Sale”:

(1) a disposition to the Company or a Restricted Subsidiary, including the sale or issuance by the Company or any Restricted Subsidiary of any Equity Interests of any Restricted Subsidiary to the Company or any Restricted Subsidiary;

(2) the sale or discount of accounts receivable arising in the ordinary course of business in connection with the compromise or collection thereof;

(3) operating leases entered into in the ordinary course of a mining business;

(4) a transaction covered by “Consolidation, Merger or Sale of Assets”;

(5) a Restricted Payment permitted under “Limitation on Restricted Payments” or a Permitted Investment;

(6) any transfer of property or assets that consists of grants by the Company or its Restricted Subsidiaries in the ordinary course of business of licenses or sub-licenses, including with respect to intellectual property rights;

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(7) the sale of assets by the Company and its Restricted Subsidiaries consisting of leases and subleases of real property solely to the extent that such real property is not necessary for the normal conduct of operations of the Company and its Restricted Subsidiaries;

(8) the granting of a Lien permitted under the Indenture or the foreclosure of assets of the Company or any of its Restricted Subsidiaries to the extent not constituting a Default;

(9) the sale or other disposition of cash or Cash Equivalents;

(10) the unwinding of any Hedging Agreements;

(11) the surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind;

(12)(a) sales of inventory in the ordinary course of business and (b) the abandonment or allowance to lapse or expire or other disposition of intellectual property by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13) any disposition in a transaction or series of related transactions of assets with a Fair Market Value of less than $2.5 million;

(14) Permitted Reserve Transfers; and

(15) the sale of Equity Interests of an Unrestricted Subsidiary.

“Attributable Indebtedness” in respect of a Sale and Leaseback Transaction means, at any date of determination,

(1) if such Sale and Leaseback Transaction is a Capital Lease, the amount of Indebtedness represented thereby according to the definition of “Capital Lease”; and

(2) in all other circumstances, the present value (discounted at the interest rate implicit in such transaction, determined in accordance with GAAP, compounded annually) of the total Obligations of the lessee for rental payments during the remaining term of the lease included in such Sale and Leaseback Transaction (including any period for which such lease has been extended).

“Average Life” means, as of the date of determination with respect to any Indebtedness, the quotient obtained by dividing (i) the sum of the products of (x) the number of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness and (y) the amount of such principal payment by (ii) the sum of all such principal payments.

“Board of Directors” means with respect to any Person, (i) if the Person is a corporation, the board of directors of the corporation, (ii) if the Person is a partnership, the Board of Directors of the general partner of the partnership and (iii) with respect to any other Person, the board or committee of such Person serving a similar function.

“Capital Lease” means, with respect to any Person, any lease of any property which, in conformity with GAAP, is required to be capitalized on the balance sheet of such Person.

“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

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(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

“Cash Equivalents” means:

(1) United States dollars, or money in other currencies;

(2) U.S. Government Obligations or certificates representing an ownership interest in U.S. Government Obligations with maturities not exceeding two years from the date of acquisition;

(3)(i) demand deposits, (ii) time deposits and certificates of deposit with maturities of one year or less from the date of acquisition, (iii) bankers’ acceptances with maturities not exceeding one year from the date of acquisition, and (iv) overnight bank deposits, in each case with any bank or trust company organized or licensed under the laws of the United States or any state thereof (including any branch of a foreign bank licensed under any such laws) having capital, surplus and undivided profits in excess of $500.0 million (or the foreign currency equivalent thereof) whose short-term debt is rated “A-2” or higher by S&P or “P-2” or higher by Moody’s;

(4) commercial paper maturing within 364 days from the date of acquisition thereof and having, at such date of acquisition, ratings of at least A-2 by S&P or P-2 by Moody’s;

(5) readily marketable direct obligations issued by any state, commonwealth or territory of the United States or any political subdivision thereof (including any agency or instrumentality thereof), in each case rated at least Investment Grade by S&P or Moody’s with maturities not exceeding one year from the date of acquisition;

(6) investment funds substantially all of the assets of which consist of investments of the type described in clauses (1) through (5) above; and

(7) fully collateralized repurchase agreements with a term of not more than 30 days for securities described in clause (2) above and entered into with a financial institution satisfying the criteria described in clause (3) above.

“Change of Control” means:

(1) an event or series of events by which (i) any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than a Permitted Holder, becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or indirectly, of 35% or more of the total voting power of the Voting Stock of the Company on a fully-diluted basis and (ii) the Permitted Holders are not the beneficial owners of a larger percentage of the voting power of such Voting Stock than such person or group;

(2) following the initial public equity offering of common Capital Stock of the Company, during any period of 12 consecutive months, a majority of the members of the Board of Directors of the Company cease to be composed of individuals (i) who were members of the Board of Directors on the first day of such period, (ii) whose election or nomination to the Board of Directors was approved by individuals referred to in clause (i) above constituting at the time of such election or nomination at least a majority of the Board of Directors or (iii) whose election or nomination to the Board of Directors was approved by individuals referred to in clauses (i) and (ii) above constituting at the time of such election or nomination at least a majority of the Board of Directors (excluding, in the case of both clause (ii) and clause (iii), any individual whose initial nomination for, or assumption of office as, a member of the Board of Directors occurs as a result of an actual or threatened solicitation of proxies or consents for the election or removal of one or more directors by any person or group other than a solicitation for the election of one or more directors by or on behalf of the Board of Directors);

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(3) the sale, conveyance, transfer or other disposition of all or substantially all of the assets (whether directly or through one or more Restricted Subsidiaries) of the Company (determined on a consolidated basis for the Company and its Restricted Subsidiaries), except to a Permitted Holder or a transaction permitted by the proviso at the end of clause (a) of “Consolidation, Merger or Sale of Assets”; or

(4) the adoption of a plan of liquidation or dissolution of the Company.

“Code” means the Internal Revenue Code of 1986, as amended from time to time.

“Collateral Agent” means Wells Fargo Bank, National Association.

“common equity”,when used with respect to a contribution of capital to the Company, means a capital contribution to the Company in a manner that does not constitute Disqualified Equity Interests.

“Common Stock” means Capital Stock not entitled to any preference on dividends or distributions, upon liquidation or otherwise.

“Consolidated EBITDA”means, for any Person for any period, Consolidated Net Income for such Person for such period:

(1)plus,without duplication, the following for such Person and its Subsidiaries (Restricted Subsidiaries, in the case of the Company) for such period to the extent deducted in calculating Consolidated Net Income:

(A) federal, state, local and foreign income tax expense for such period,

(B) non-cash compensation expense,

(C) losses on discontinued operations,

(D) Interest Expense,

(E) depreciation, depletion and amortization of property, plant, equipment and intangibles,

(F) debt extinguishment costs and expenses (including, without limitation, any costs or expenses in connection with the transactions contemplated by this prospectus),

(G) other non-cash charges (including, without limitation, FASB ASC 360-10 writedowns, but excluding any non-cash charge which requires an accrual of, or a cash reserve for, anticipated cash charges for any future period),

(H) the excess, if any, of reclamation and remediation obligation expenses determined in accordance with GAAP over reclamation and remediation obligations cash payments (it being understood that reclamation and remediation obligation expenses may not be added back under any other clause in this definition), and

(I) transaction costs, fees and expenses in connection with any acquisition or issuance of Indebtedness or Equity Interests (whether or not successful) by the Company or any Restricted Subsidiary;

providedthat, with respect to any Subsidiary of such Person (Restricted Subsidiary, in the case of the Company), the foregoing such items will be added only to the extent and in the same proportion that such Subsidiary’s net income was included in calculating Consolidated Net Income;

(2)minus,without duplication, the following for such Person and its Subsidiaries (Restricted Subsidiaries in the case of the Company) for such period to the extent added in calculating Consolidated Net Income:

(A) federal, state, local and foreign income tax benefit for such period,

(B) gains on discontinued operations,

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(C) all non-cash items increasing Consolidated Net Income for such Person for such period (including, without limitation, the accretion of sales or purchase contracts),

(D) the excess, if any, of asset retirement obligations cash payments over asset retirement obligations expenses determined in accordance with GAAP (it being understood that asset retirement cash payments need not be added back under any other clause in this definition), and

(E) all cash payments actually made by such Person and its Subsidiaries (Restricted Subsidiaries in the case of the Company) during such period relating to non-cash charges that were added back in determining Consolidated EBITDA in any prior period.

“Consolidated Net Income” means, for any Person for any period, the aggregate net income (or loss) of such Person and its Subsidiaries for such period determined on a consolidated basis in conformity with GAAP (after reduction for minority interests in Subsidiaries of such Person),providedthat the following (without duplication) will be excluded in computing Consolidated Net Income:

(1) the net income (or loss) of any Person other than a Subsidiary of such Person (Restricted Subsidiary, in the case of the Company), except to the extent of dividends or other distributions actually paid in cash to the Company or any of its Restricted Subsidiaries by such Person during such period;

(2) the net income (or loss) of any Subsidiary of such Person (Restricted Subsidiary, in the case of the Company) to the extent that the declaration or payment of dividends or similar distributions by such Subsidiary of its net income is not at the date of determination permitted without any prior governmental approval (which has not been obtained) or, directly or indirectly, by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule, or governmental regulation applicable to that Subsidiary or its stockholders, unless such restriction with respect to the payment of dividends or in similar distributions has been legally waived;

(3) any net after-tax gains or losses (less all fees and expenses or charges relating thereto) attributable to asset sales, other dispositions or the extinguishment of debt, in each case other than in the ordinary course of business;

(4) any net after-tax extraordinary gains or losses; and

(5) the cumulative effect of a change in accounting principles.

“Credit Agreement” means the credit agreement dated as of the Issue Date among the Company, the Guarantors, the various lenders and agents party thereto and PNC Bank, National Association, as administrative agent and Collateral Agent, together with any related documents (including the Security Documents), as such agreement has been amended and restated through the Issue Date and as it may be amended, restated, modified, supplemented, extended, renewed, refunded, restructured, refinanced or replaced or substituted from time to time and whether by the same or any other agent, lender or group of lenders or other party.

“Credit Facilities” means (i) one or more credit facilities (including the Credit Agreement) with banks or other lenders providing for revolving credit loans, term loans, receivables financing or the issuance of letters of credit or bankers’ acceptances or the like, (ii) debt securities, indentures or other forms of debt financing (including convertible or exchangeable debt instruments), or (iii) instruments or agreements evidencing any other Indebtedness, in each case, with the same or different borrowers or issuers and, in each case, as amended, restated, modified, supplemented, extended, renewed, refunded, restructured, refinanced or replaced or substituted in whole or in part from time to time and whether by the same or any other agent, lender or group of lenders or other party.

“Credit and Collateral Support Fee, Indemnification and Right of First Refusal Agreement” means that certain agreement, dated as of February 9, 2011, between the Company and certain of its Affiliates, as in effect on the Issue Date and described under “Certain Relationships and Related Party Transactions.”

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“Default” means any event that is, or after notice or passage of time or both would be, an Event of Default.

“Discharge of ABL Obligations” has the meaning provided in the Intercreditor Agreement and is generally defined to mean (a) the payment in full of each of all outstanding ABL Obligations excluding contingent indemnity obligations with respect to then unasserted claims but including, with respect to amounts available to be drawn under outstanding letters of credit issued thereunder (or indemnities or other undertakings issued pursuant thereto in respect of outstanding letters of credit), the cancellation of such letters of credit or the delivery or provision of money or backstop letters of credit in respect thereof in compliance with the terms of the Credit Agreement (which shall not exceed an amount equal to 105% of the aggregate undrawn amount of such letters of credit), (b) the termination of all commitments to extend credit under the Credit Agreement and related loan documents; provided that in connection with the amendment, renewal, extension, substitution, refinancing, restructuring, replacement, supplement or other modification from time to time of the Credit Agreement in connection with the incurrence of additional ABL Obligations, the Discharge of ABL Obligations shall be deemed to have not occurred and references to the “Credit Agreement” above shall thereafter refer to the agreement under which such additional ABL Obligations are incurred and (c) all contingent indemnification obligations for which claim or demand for payment has been made are cash collateralized in an amount reasonably determined by the ABL Facility Collateral Agent.

“Discharge of Indenture Obligations” means that (a) all of such Indenture Obligations (other than contingent indemnification obligations) have been indefeasibly paid, performed or discharged in full (with all such Indenture Obligations consisting of monetary or payment (including reimbursement) obligations having been paid in full in cash) and (b) all contingent indemnification obligations for which claim or demand for payment has been made are cash collateralized in an amount reasonably determined by the Collateral Agent.

“Disposition Subsidiary” means a temporary, newly-formed direct or indirect Subsidiary of the Company that (i) was created for the sole purpose of facilitating a disposition of coal reserves and/or interests in real property otherwise permitted under the Indenture, (ii) prior to the transaction described in clause (i) above holds no material assets and conducts no operations, (iii) after the transaction described in clause (i) above shall, by merger, sale, consolidation or otherwise, no longer be a Subsidiary of the Company or shall no longer be in existence.

“Disqualified Equity Interests” means Equity Interests that by their terms (or by the terms of any security into which such Equity Interests are convertible, or for which such Equity Interests are exchangeable, in each case at the option of the holder thereof) or upon the happening of any event:

(1) matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or are required to be redeemed or redeemable at the option of the holder prior to the Stated Maturity of the Notes for consideration other than Qualified Equity Interests, or

(2) are convertible at the option of the holder into Disqualified Equity Interests or exchangeable for Indebtedness, in each case prior to the date that is 91 days after the date on which the Notes mature; provided that Equity Interests will not constitute Disqualified Equity Interests solely because of provisions giving holders thereof the right to require the repurchase or redemption upon an “asset sale” or “change of control” occurring prior to the Stated Maturity of the Notes if those provisions:

(A) are no more favorable to the holders of such Equity Interests than “Limitation on Asset Sales” and “Repurchase of Notes Upon a Change of Control,” and

(B) specifically state that repurchase or redemption pursuant thereto will not be required prior to the Company’s repurchase of the Notes as required by the Indenture.

“Disqualified Stock” means Capital Stock constituting Disqualified Equity Interests.

“Domestic Restricted Subsidiary” means any Restricted Subsidiary formed under the laws of the United States of America or any jurisdiction thereof.

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“Equity Interests” means all Capital Stock and all warrants or options with respect to, or other rights to purchase, Capital Stock, but excluding Indebtedness convertible into, or exchangeable for, Capital Stock.

“Equity Offering” means an offer and sale of Qualified Stock of the Company after the Issue Date other than an issuance registered on Form S-4 or S-8 or any successor thereto or any issuance pursuant to employee benefit plans or otherwise relating to compensation to officers, directors or employees.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Excluded Sale and Leaseback Transactions” means (i) the sale and leaseback transactions with certain Affiliates of the Company outstanding as of the Issue Date, and (ii) additional sale and leaseback transactions with Armstrong Resource Partners or a subsidiary thereof pursuant to agreements that have been entered into by the Company or a Restricted Subsidiary in compliance with clause (a) and (b) of the “Limitation on Transactions with Affiliates” covenant along with the associated options and related rights.

“Event of Loss” means, with respect to any property or asset (tangible or intangible, real or personal) constituting Collateral, any of the following:

(i) any loss, destruction or damage of such property or asset;

(ii) any institution of any proceeding for the condemnation or seizure of such property or asset or for the exercise of any right of eminent domain;

(iii) any actual condemnation, seizure or taking by exercise of the power of eminent domain or otherwise of such property or asset, or confiscation of such property or asset or the requisition of the use of such property or asset; or

(iv) any settlement in lieu of clauses (ii) or (iii) above.

“Fair Market Value” means, with respect to any property, the price that could be negotiated in an arm’s length transaction between a willing seller and a willing buyer, neither of whom is under undue pressure orcompulsion to complete the transaction. Fair Market Value shall be determined, except as otherwise provided,(a) if such property has a Fair Market Value equal to or less than $25.0 million, by any Officer; or (b) if such property has a Fair Market Value in excess of $25.0 million, by at least a majority of the disinterested members of the Board of Directors and evidenced by a resolution of the Board of Directors delivered to the Trustee.

“Fixed Charge Coverage Ratio” means, on any date (the “transaction date”) for any Person, the ratio of:

(x) the aggregate amount of Consolidated EBITDA for such Person for the four fiscal quarters immediately prior to the transaction date for which internal financial statements are available (the “reference period”); to

(y) the aggregate Fixed Charges for such Person during such reference period.

In making the foregoing calculation,

(1)pro forma effect will be given to any Indebtedness or Preferred Stock Incurred during or after the reference period to the extent the Indebtedness is outstanding or is to be Incurred on the transaction date as if the Indebtedness, Disqualified Stock or Preferred Stock had been Incurred on the first day of the reference period;

(2)pro forma calculations of interest on Indebtedness bearing a floating interest rate will be made as if the rate in effect on the transaction date (taking into account any Hedging Agreement applicable to the Indebtedness if the Hedging Agreement has a remaining term of at least 12 months) had been the applicable rate for the entire reference period;

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(3) Fixed Charges related to any Indebtedness or Preferred Stock no longer outstanding or to be repaid or redeemed on the transaction date, except for Interest Expense accrued during the reference period under a revolving credit to the extent of the commitment thereunder (or under any successor revolving credit) in effect on the transaction date, will be excluded;

(4)pro forma effect will be given to:

(A) the creation, designation or redesignation of Restricted and Unrestricted Subsidiaries,

(B) the acquisition or disposition of companies, divisions or lines of businesses by such Person and its Subsidiaries (Restricted Subsidiaries in the case of the Company), including any acquisition or disposition of a company, division or line of business since the beginning of the reference period by a Person that became a Subsidiary of such Person (Restricted Subsidiary, in the case of the Company) after the beginning of the reference period, and

(C) the discontinuation of any discontinued operations but, in the case of Fixed Charges, only to the extent that the obligations giving rise to the Fixed Charges will not be obligations of such Person or any of its Subsidiaries (Restricted Subsidiaries in the case of the Company) following the transaction date

that have occurred since the beginning of the reference period as if such events had occurred, and, in the case of any disposition, the proceeds thereof applied, on the first day of the reference period. To the extent thatpro formaeffect is to be given to an acquisition or disposition of a company, division or line of business, thepro formacalculation will be based upon the most recent four full fiscal quarters for which the relevant financial information is available.

For purposes of this definition,pro formacalculations shall be made in accordance with Article 11 of Regulation S-X promulgated under the Securities Act, except that suchpro formacalculations may also include cost savings and operating expense reductions for such period resulting from the acquisition, merger orconsolidation or disposition for whichpro formaeffect is being given (A) that have been realized or (B) for which steps have been taken or are reasonably expected to be taken within six (6) months of the date of suchtransaction and such cost savings and operating expense reductions are reasonably expected to be realized within twelve (12) months of the date of such transaction, are set forth in an officers’ certificate signed by the Company’s chief financial or similar officer that states (i) the amount of such adjustment or adjustments and (ii) that such adjustment or adjustments are based on the reasonable good faith belief of the officers executing such officers’ certificate at the time of such execution.

“Fixed Charges” means, for any Person for any period, the sum of:

(1) Interest Expense for such Person for such period (other than non-cash interest expense related to (i) leased coal reserves and (ii) non-interest bearing seller Indebtedness Incurred by the Company or any of its Restricted Subsidiaries to finance, in whole or in part, the acquisition of coal reserves and related assets); and

(2) the product of:

(x) cash and non-cash dividends paid, declared, accrued or accumulated on any Disqualified Stock or Preferred Stock of the such Person or any of its Subsidiaries (Restricted Subsidiaries in the case of the Company), except for dividends payable in the Company’s Qualified Stock or paid to such Person or any of its Subsidiaries (Restricted Subsidiaries in the case of the Company); and

(y) a fraction, the numerator of which is one and the denominator of which is one minus the sum of the currently effective combined Federal, state, local and foreign tax rate applicable to such Person and its Subsidiaries (Restricted Subsidiaries in the case of the Company) (or, if such Person is a flow-through taxpayer, the Effective Tax Rate).

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“Foreign Subsidiary” means any Restricted Subsidiary of the Company that (x) is not organized under the laws of the United States of America or any State thereof or the District of Columbia or (y) was organized under the laws of the United States of America or any State thereof or the District of Columbia that has no material assets other than Capital Stock of one or more foreign entities of the type described in clause (x) above and is not a guarantor of Indebtedness under the Credit Agreement.

“GAAP” means generally accepted accounting principles in the United States of America as in effect on the Issue Date.

“Guarantee” by any Person (the “guarantor”) means any obligation, contingent or otherwise, of the guarantor guaranteeing any Indebtedness or other obligation of any other Person (the “primary obligor”), whether directly or indirectly, and including any written obligation of the guarantor, (a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or advance or supply funds for the purchase of) any security for the payment thereof, (b) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness or other obligation or (c) as an account party in respect of any letter of credit or letter of guarantee issued to support such Indebtedness or other obligation;providedthat the term “Guarantee” shall not include endorsements for collection or deposit in the ordinary course of business.

“Guarantor” means (i) each Wholly Owned Domestic Restricted Subsidiary of the Company in existence on the Issue Date that signs the Indenture and (ii) each Restricted Subsidiary that executes a supplemental indenture in the form attached to the Indenture providing for the Guarantee of the payment of the Notes, or any successor obligor under its Note Guarantee, in each case unless and until such Guarantor is released from its Note Guarantee pursuant to the Indenture.

“Hedging Agreement” means any and all rate swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, equity or equityindex swaps or options, bond or bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions, interest rate options, forward foreign exchange transactions, captransactions, floor transactions, collar transactions, currency swap transactions, cross-currency rate swap transactions, currency options, spot contracts, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing), whether or not any such transaction is governed by or subject to any master agreement.

“Incur” means, with respect to any Indebtedness or Capital Stock, to incur, create, issue, assume or Guarantee such Indebtedness or Capital Stock. If any Person becomes a Restricted Subsidiary on any date after the date of the Indenture (including by redesignation of an Unrestricted Subsidiary or failure of an Unrestricted Subsidiary to meet the qualifications necessary to remain an Unrestricted Subsidiary), the Indebtedness and Capital Stock of such Person outstanding on such date will be deemed to have been Incurred by such Person on such date for purposes of “Limitation on Indebtedness or Preferred Stock,” but will not be considered the sale or issuance of Equity Interests for purposes of “Limitation on Asset Sales.” Neither the accrual of interest nor the accretion of original issue discount nor the payment of interest in the form of additional Indebtedness (to the extent provided for when the Indebtedness on which such interest is paid was originally issued) shall be considered an Incurrence of Indebtedness.

“Indebtedness” means, with respect to any Person, without duplication,

(1) all Indebtedness of such Person for borrowed money;

(2) all obligations of such Person evidenced by bonds, debentures, Notes or other similar instruments;

(3) all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments;

(4) all obligations of such Person to pay the deferred and unpaid purchase price of property or services provided by third-party service providers which are recorded as liabilities under GAAP, excluding (i) trade

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payables arising in the ordinary course of business and payable in accordance with customary practice, and (ii) accrued expenses, salary and other employee compensation obligations incurred in the ordinary course;

(5) all Obligations in respect of Capital Leases of such Person and all Attributable Indebtedness in respect of a Sale and Leaseback Transaction (other than (i) Excluded Sale and Leaseback Transactions and (ii) obligations relating to Permitted Reserve Transfers, in each case, that are characterized as sale and leaseback transactions solely because of the continuing involvement of such Affiliate in mining related to such leases) entered into by such Person;

(6) Disqualified Equity Interests of such Person;

(7) all Indebtedness of other Persons Guaranteed by such Person to the extent so Guaranteed;

(8) all Indebtedness (excluding prepaid interest thereon) of other Persons secured by a Lien on any property owned or being purchased by (including Indebtedness owing under conditional sales or other title retention agreements) such Person, whether or not such Indebtedness is assumed by such Person or is limited in recourse; and

(9) all obligations of such Person under Hedging Agreements.

Notwithstanding the foregoing, obligations in respect of leases characterized as operating leases in accordance with GAAP as in effect on the Issue Date shall not be included as Indebtedness hereunder regardless of any change in GAAP that would include such obligations as indebtedness.

The amount of Indebtedness of any Person will be deemed to be:

(A) with respect to Indebtedness secured by a Lien on an asset of such Person but not otherwise the obligation, contingent or otherwise, of such Person, the lesser of (x) the fair market value of such asset on the date the Lien attached and (y) the amount of such Indebtedness;

(B) with respect to any Indebtedness issued with original issue discount, the face amount of such Indebtedness less the remaining unamortized portion of the original issue discount of such Indebtedness;

(C) with respect to any Hedging Agreement, the amount payable (determined after giving effect to all contractually permitted netting) if such Hedging Agreement terminated at that time; and

(D) otherwise, the outstanding principal amount thereof.

“Indenture Obligations” means the obligations of the Company and any other obligor under the Indenture or under the Notes, including any Guarantor, to pay principal of, premium, if any, and interest when due and payable, and all other amounts due or to become due under or in connection with the Indenture, the Notes and the performance of all obligations to the Trustee and the holders under the Indenture and the Notes, according to the respective terms thereof.

“Initial Purchasers” means Stifel, Nicolaus & Company, Incorporated, PNC Capital Markets LLC and U.S. Bancorp Investments, Inc.

“Interest Expense” means, for any Person for any period, the consolidated interest expense of such Person and its Subsidiaries (Restricted Subsidiaries in the case of the Company), plus, to the extent not included in such consolidated interest expense, and to the extent Incurred, accrued or payable by such Person or its Subsidiaries (Restricted Subsidiaries in the case of the Company), without duplication: (i) interest expense attributable to Capital Leases, (ii) imputed interest with respect to Attributable Indebtedness, (iii) amortization of debt discount and debt issuance costs, (iv) capitalized interest, (v) non-cash interest expense, (vi) any of the above expenses with respect to Indebtedness of another Person Guaranteed by such Person or any of its Subsidiaries (Restricted Subsidiaries in the case of the Company) or secured by a Lien on the assets of such Person or one of its Subsidiaries (Restricted Subsidiaries in the case of the Company) and (vii) any interest, premiums, fees, discounts, expenses and losses on the sale of accounts receivable (and any amortization thereof) payable by such

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Person or any of its Subsidiaries (Restricted Subsidiaries in the case of the Company) in connection with a Receivables Financing, and any yields or other charges or other amounts comparable to, or in the nature of, interest payable by such Person or any of its Subsidiaries (Restricted Subsidiaries in the case of the Company) under any Receivables Financing. Interest Expense shall be determined for any period after giving effect to any net payments made or received and costs incurred by such Person or any of its Subsidiaries (Restricted Subsidiaries in the case of the Company) with respect to any related interest rate Hedging Agreements.

“Investment” means:

(1) any advance (excluding intercompany liabilities incurred in the ordinary course of business in connection with the cash management operations of the Company or its Restricted Subsidiaries), loan or other extension of credit to another Person (but excluding (i) advances to customers, suppliers or the like in the ordinary course of business that are, in conformity with GAAP, recorded as accounts receivables, prepaid expenses or deposits on the balance sheet of the Company or its Restricted Subsidiaries and endorsements for collection or deposit arising in the ordinary course of business, (ii) commission, travel and similar advances to officers and employees made in the ordinary course of business and (iii) advances, loans or extensions of trade credit in the ordinary course of business by the Company or any of its Restricted Subsidiaries),

(2) any capital contribution to another Person, by means of any transfer of cash or other property or in any other form,

(3) any purchase or acquisition of Equity Interests, bonds, notes or other Indebtedness, or other instruments or securities issued by another Person, including the receipt of any of the above as consideration for the disposition of assets or rendering of services, or

(4) any Guarantee of any obligation of another Person.

If the Company or any Restricted Subsidiary (x) issues, sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary so that, after giving effect to that sale or disposition, such Person is no longer a Subsidiary of the Company, or (y) designates any Restricted Subsidiary as an Unrestricted Subsidiary in accordance with the provisions of the Indenture, all remaining Investments of the Company and the Restricted Subsidiaries in such Person shall be deemed to have been made at such time. The acquisition by the Company or any Restricted Subsidiary of a Person that holds an Investment in a third Person will be deemed to be an Investment by the Person or such Restricted Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investment held by the acquired Person in such third Person on the date of such acquisition.

“Issue Date” means December 21, 2012, the date on which the Notes were issued under the Indenture.

“Lien” means any mortgage, pledge, security interest, encumbrance, lien or charge of any kind (including any conditional sale or other title retention agreement or Capital Lease).

“Moody’s“ means Moody’s Investors Service, Inc. and its successors.

“Net Cash Proceeds” means, with respect to any Asset Sale, the proceeds of such Asset Sale in the form of cash (including (i) payments in respect of deferred payment obligations to the extent corresponding to, principal, but not interest, when received in the form of cash, and (ii) proceeds from the conversion of other consideration received when converted to cash but only when received), net of:

(1) brokerage commissions and other fees and expenses related to such Asset Sale, including fees and expenses of counsel, accountants and investment bankers and any relocation expenses incurred as a result thereof;

(2) provisions for income taxes as a result of such Asset Sale taking into account the consolidated results of operations of the Company and its Restricted Subsidiaries reasonably estimated to actually be payable within two years of the date of the relevant transaction as a result of any gain recognized in

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connection therewith,provided that if the amount of any estimated taxes hereunder exceeds the amount of taxes actually required to be paid in cash in respect of such Asset Sale, the aggregate amount of such excess shall constitute Net Cash Proceeds;

(3) payments required to be made to holders of minority interests in Restricted Subsidiaries as a result of such Asset Sale or to repay Indebtedness outstanding at the time of such Asset Sale that is secured by a Lien on the property or assets sold that is senior in priority to the Lien on such property or assets securing the Notes; and

(4) appropriate amounts to be provided as a reserve against liabilities associated with such Asset Sale, including pension and other post-employment benefit liabilities, liabilities related to environmental matters and indemnification obligations associated with such Asset Sale, with any subsequent reduction of the reserve other than by payments made and charged against the reserved amount to be deemed a receipt of cash.

“Net Loss Proceeds” means the aggregate cash proceeds received by the Company or any Guarantor in respect of any Event of Loss, including, without limitation, insurance proceeds, condemnation awards or damages awarded by any judgment, net of the direct cost in recovery of such Net Loss Proceeds (including, without limitation, legal, accounting, appraisal and insurance adjuster fees and any relocation expenses incurred as a result thereof) and any taxes paid or payable as a result thereof.

“Non-Recourse Indebtedness” means Indebtedness as to which (i) neither the Company nor any Restricted Subsidiary provides any Guarantee and as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Company or any Restricted Subsidiary and (ii) no default thereunder would, as such, constitute a default under any Indebtedness of the Company or any Restricted Subsidiary.

“Note Guarantee” means the Guarantee of the Notes by a Guarantor pursuant to the Indenture.

“Notes Liens” means all Liens in favor of the Collateral Agent on Collateral securing the Indenture Obligations.

“Notes Priority Collateral” means substantially all of the assets (other than ABL Priority Collateral) that are owned or hereafter acquired by the Company and by each of the Guarantors to the extent pledged or required to be pledged to secure the Notes.

“Obligations” means, with respect to any Indebtedness, all obligations (whether in existence on the Issue Date or arising afterwards, absolute or contingent, direct or indirect) for or in respect of principal (when due, upon acceleration, upon redemption, upon mandatory repayment or repurchase pursuant to a mandatory offer to purchase, or otherwise), premium, interest, penalties, fees, indemnification, reimbursement, expenses, damages and other amounts payable and liabilities with respect to such Indebtedness, including all interest accrued or accruing after the commencement of any bankruptcy, insolvency or reorganization or similar case or proceeding at the contract rate (including, without limitation, any contract rate applicable upon default) specified in the relevant documentation, whether or not the claim for such interest is allowed as a claim in such case or proceeding.

“Officer” means, with respect to any Person, the chairman of the board, the chief executive officer, the president, the chief operating officer, the chief financial officer, the treasurer, any assistant treasurer, the controller, the secretary or any vice president of such Person.

“Officers’ Certificate” means a certificate signed on behalf of the Company by two Officers, one of whom must be the chief executive officer, the chief financial officer, or the chief accounting officer of the Company.

“Opinion of Counsel” means a written opinion from legal counsel, who may be an employee of or counsel to the Company, or other counsel who is acceptable to the Trustee.

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“Permitted Business” means any of the businesses in which the Company and its Restricted Subsidiaries are engaged on the Issue Date, and any other businesses the primary purpose of which is reasonably related, incidental, complementary or ancillary thereto.

“Permitted Holder” means Yorktown and each of its Affiliates or funds controlled or managed by it or its Affiliates other than any portfolio companies of any of the foregoing.

“Permitted Investments” means:

(1) any Investment in the Company or in a Guarantor;

(2) any Investment in cash or Cash Equivalents;

(3) any Investment by the Company or any Subsidiary of the Company in a Person, if as a result of such Investment;

(A) such Person becomes a Restricted Subsidiary of the Company, or

(B) such Person is merged or consolidated with or into, or transfers or conveys substantially all its assets to, or is liquidated into, the Company or a Restricted Subsidiary;

(4) Investments received as non-cash consideration in an asset sale made pursuant to and in compliance with “Limitation on Asset Sales”;

(5) any Investment acquired solely in exchange for Qualified Stock of the Company;

(6) Hedging Agreements otherwise permitted under the Indenture;

(7)(i) receivables owing to the Company or any Restricted Subsidiary if created or acquired in the ordinary course of business, (ii) endorsements for collection or deposit in the ordinary course of business, and (iii) securities, instruments or other obligations received in compromise or settlement of debts created in the ordinary course of business, or by reason of a composition or readjustment of debts or reorganization of another Person, or in satisfaction of claims or judgments;

(8) payroll, travel and other loans or advances to, or Guarantees issued to support the obligations of, current or former officers, managers, directors, consultants and employees, in each case in the ordinary course of business, not in excess of $2.0 million outstanding at any time;

(9) Investments in the nature of any Production Payments, royalties, dedication of reserves under supply agreements or similar rights or interests granted, taken subject to, or otherwise imposed on properties with normal practices in the mining industry;

(10) Investments consisting of obligations specified in clause (b)(6) of the definition of “Permitted Indebtedness”;

(11) Investments resulting from pledges and deposits permitted under the definition of “Permitted Liens”;

(12) Investments consisting of purchases and acquisitions, in the ordinary course of business, of inventory, supplies, material or equipment or the licensing or contribution of intellectual property;

(13) Investments in joint ventures or other Persons engaged in a Permitted Business (including, but not limited to, any additional Investments in Ram Terminals, LLC) in an amount not to exceed $10.0 million in the aggregate after the Issue Date;

(14) Investments consisting of indemnification obligations in respect of performance bonds, bid bonds, appeal bonds, surety bonds, reclamation bonds and completion guarantees and similar obligations in respect of coal sales contracts (and extensions or renewals thereof on similar terms) or under applicable law or with respect to workers’ compensation benefits, in each case entered into in the ordinary course of business, and pledges or deposits made in the ordinary course of business in support of obligations under coal sales contracts (and extensions or renewals thereof on similar terms); and

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(15) in addition to Investments listed above, Investments in Persons engaged in Permitted Businesses in an aggregate amount (without taking into account any changes in value after the making of any such Investment), taken together with all other Investments made in reliance on this clause, not to exceed $50.0 million (net of, with respect to the Investment in any particular Person made pursuant to this clause, the cash return thereon received after the Issue Date as a result of any sale for cash, repayment, return, redemption, liquidating distribution or other cash realization (not included in Consolidated Net Income) not to exceed the amount of such Investments in such Person made after the Issue Date in reliance on this clause).

“Permitted Liens” means:

(1) Liens existing on the Issue Date (other than Liens securing the Credit Agreement);

(2) Liens securing the Notes issued on the Issue Date (or any Exchange Notes issued therefor) or any Note Guarantees (including guarantees of Exchange Notes) and other Obligations under the Indenture and any obligations owing to the Trustee under the Indenture;

(3) Liens securing (i) Indebtedness Incurred under clause (b)(1) of the definition of Permitted Indebtedness (and all Obligations incurred, issued or arising under such secured credit facilities that permit borrowings not in excess of the limit set out in such clause (b)(1)),providedthat, in the case of this clause (i), such Liens on ABL Priority Collateral and Notes Priority Collateral have the priorities described under “—Intercreditor Agreement” and (ii) Obligations of the Company and its Subsidiaries under Hedging Agreements and other agreements, including in respect of cash management services provided by Persons who were lenders under the Indebtedness referred to in the preceding clause (i) or their affiliates at the time such agreements were entered into;

(4)(i) pledges or deposits under worker’s compensation laws, unemployment insurance and other social security laws or regulations or similar legislation, or to secure liabilities to insurance carriers under insurance arrangements in respect of such obligations, or good faith deposits, prepayments or cash payments in connection with bids, tenders, contracts or leases, or to secure public or statutory obligations, surety and appeal bonds, customs duties and the like, or for the payment of rent, in each case incurred in the ordinary course of business and (ii) Liens securing obligations specified in clause (b)(6) of the definition of “Permitted Indebtedness,” Incurred in the ordinary course of business to secure performance of obligations with respect to statutory or regulatory requirements, performance or return-of-money bonds, contractual arrangements with suppliers, reclamation bonds, surety bonds or other obligations of a like nature and Incurred in a manner consistent with industry practice, in each case which are not Incurred in connection with the borrowing of money or the obtaining of advances or credit;

(5) Liens imposed by law, such as carriers’, vendors’, warehousemen’s and mechanics’ liens, in each case for sums not yet due or being contested in good faith and by appropriate proceedings and in respect of taxes and other governmental assessments and charges or claims which are not yet due or which are being contested in good faith and by appropriate proceedings;

(6) customary Liens in favor of trustees, paying agents and escrow agents, and netting and setoff rights, banker’s liens and the like in favor of financial institutions and counterparties to financial obligations and instruments, including Hedging Agreements;

(7) Liens on assets pursuant to merger agreements, stock or asset purchase agreements and similar agreements in respect of the disposition of such assets;

(8) options, put and call arrangements, rights of first refusal and similar rights relating to Investments in joint ventures, partnerships and the like;

(9) judgment liens so long as no Event of Default then exists as a result thereof;

(10) Liens incurred in the ordinary course of business securing obligations other than Indebtedness for borrowed money and not in the aggregate materially detracting from the value of the properties or their use in the operation of the business of the Company and its Restricted Subsidiaries;

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(11) Liens (including the interest of a lessor under a Capital Lease) on property that secure Indebtedness Incurred pursuant to clause (b)(12) of the definition of Permitted Indebtedness for the purpose of financing all or any part of the purchase price or cost of construction or improvement of such property or assets;providedthat the Lien does not (x) extend to any additional property or assets or (y) secure any additional obligations, in each case other than the initial property so subject to such Lien and the Indebtedness and other obligations originally so secured;

(12) Liens on property of a Person at the time such Person becomes a Restricted Subsidiary of the Company,providedsuch Liens were not created in contemplation thereof and do not extend to any other property of the Company or any Restricted Subsidiary;

(13) Liens on property at the time the Company or any of the Restricted Subsidiaries acquires such property, including any acquisition by means of a merger or consolidation with or into the Company or a Restricted Subsidiary of such Person,providedsuch Liens were not created in contemplation thereof and do not extend to any other property of the Company or any Restricted Subsidiary;

(14) Liens securing Indebtedness or other obligations of the Company or a Restricted Subsidiary to the Company or a Guarantor;

(15) Liens Incurred or assumed in connection with the issuance of revenue bonds the interest on which is tax-exempt under the Code;

(16) Liens on specific items of inventory, equipment or other goods and proceeds of any Person securing such Person’s obligations in respect thereof or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(17) Liens in favor of collecting or payor banks having a right of setoff, revocation, refund or chargeback with respect to money or instruments of the Company or any Restricted Subsidiary on deposit with or in possession of such bank;

(18) Deposits made in the ordinary course of business to secure liability to insurance carriers;

(19) extensions, renewals or replacements of any Liens referred to in clauses (1), (2), (11), (12) or (13) in connection with the refinancing of the obligations secured thereby,providedthat such Lien does not extend to any other property and, except as contemplated by the definition of “Permitted Refinancing Indebtedness,” the amount secured by such Lien is not increased;

(20) Royalty Agreements that encumber real property and that are in existence as of the Issue Date;

(21) Vendor Liens;

(22) surface use agreements, easements, zoning restrictions, rights of way, encroachments, pipelines, leases (other than Capital Lease Obligations), subleases, rights of use, licenses, special assessments, trackage rights, transmission and transportation lines related to mining leases or mineral right and/or other real property including any re-conveyance obligations to a surface owner following mining, royalty payments, and other obligations under surface owner purchase or leasehold arrangements necessary to obtain surface disturbance rights to access the subsurface coal deposits and similar encumbrances on real property imposed by law or arising in the ordinary course of business which, in the aggregate, are not substantial in amount and which do not materially detract from the value of the affected property or materially interfere with the ordinary conduct of business of the Company or any Restricted Subsidiary;

(23) pledges, deposits or non-exclusive licenses to use intellectual property rights of the Company or its Restricted Subsidiaries to secure the performance of bids, tenders, trade contracts, leases, public or statutory obligations, surety and appeal bonds, reclamation bonds, performance bonds and other obligations of a like nature, in each case in the ordinary course of business;

(24) rights of owners of interests in overlying, underlying or intervening strata and/or mineral interests not owned by the Company or any of its Restricted Subsidiaries, with respect to tracts of real property where

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the Company or the applicable Restricted Subsidiary’s ownership is only surface or severed mineral or is otherwise subject to mineral severances in favor of one or more third parties;

(25) other defects and exceptions to title of real property where such defects or exceptions, in the aggregate, are not substantial in amount and do not materially detract from the value of the affected property;

(26) Liens on shares of Capital Stock of any Unrestricted Subsidiary securing obligations of any Unrestricted Subsidiary;

(27) Production Payments, royalties, dedication of reserves under supply agreements, mining leases, or similar rights or interests granted, taken subject to, or otherwise imposed on properties and any precautionary UCC financing statement filings in respect of leases or consignment arrangements (and not any Indebtedness); and

(28) other Liens securing obligations in an aggregate amount not to exceed $25.0 million.

“Permitted Reserve Transfers” means transfers of interests in coal reserves to Armstrong Resource Partners or a subsidiary thereof (1) to satisfy obligations in respect of the Royalty Deferment and Option Agreement or the Credit and Collateral Support Fee, Indemnification and Right of First Refusal Agreement, each as in effect on the Issue Date or (2) to satisfy deferred royalty obligations owing to Armstrong Resource Partners or a subsidiary thereof relating to coal reserves acquired after the Issue Date pursuant to agreements that have been entered into by the Company or a Restricted Subsidiary in compliance with clause (a) and (b) of the “Limitation on Transactions with Affiliates” covenant.

“Person” means an individual, a corporation, a partnership, a limited liability company, joint venture, an association, a trust or any other entity, including a government or political subdivision or an agency or instrumentality thereof.

“Preferred Stock” means, with respect to any Person, any and all Capital Stock which is preferred as to the payment of dividends or distributions, upon liquidation or otherwise, over another class of Capital Stock of such Person.

“Production Payments” means with respect to any Person, all production payment obligations and other similar obligations with respect to coal and other natural resources of such Person that are recorded as a liability or deferred revenue on the financial statements of such Person in accordance with GAAP.

“Qualified Equity Interests” means all Equity Interests of a Person other than Disqualified Equity Interests.

“Qualified Stock” means all Capital Stock of a Person other than Disqualified Stock.

“Real Property” shall mean, collectively, all right, title and interest of the Company or any other Subsidiary (including any leasehold or mineral estate) in and to any and all parcels of real property owned or operated by the Company or any other Subsidiary, whether by lease, license or other use agreement, including but not limited to, coal leases and surface use agreements, together with, in each case, all improvements and appurtenant fixtures (including all conveyors, preparation plants or other coal processing facilities, silos, shops and load out and other transportation facilities), easements and other property and rights incidental to the ownership, lease or operation thereof, including but not limited to, access rights, water rights and extraction rights for minerals.

“Registration Rights Agreement”means (1) with respect to the Notes issued on the Issue Date, the Registration Rights Agreement, dated the Issue Date, among the Company, the Guarantors on the Issue Date and the Initial Purchasers and (2) with respect to any additional Notes, any registration rights agreement among the Company, the Guarantors and the other parties thereto relating to the registration by the Company and the Guarantors of such additional Notes under the Securities Act.

204

“Responsible Officer” means any vice president, any assistant vice president, any assistant secretary, any assistant treasurer, any trust officer, any assistant trust officer or any other officer associated with the corporate trust department of the Trustee (or any successor group of the Trustee) customarily performing functions similar to those performed by any of the above designated officers and who shall in each case have direct responsibility for the administration of the Indenture, and also means, with respect to a particular corporate trust matter, any other officer to whom such matter is referred because of such person’s knowledge of and familiarity with the particular subject.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than any Unrestricted Subsidiary.

“Royalty Agreements” means all written agreements, however denominated, pursuant to which the Company or a Guarantor is obligated to pay royalties or fees for coal mined or transported from, over or through specified tracts of real property, whether in the nature of percentage royalties, tonnage royalties or similar per-ton fees or obligations, owed to any Person, whether such agreements are part of a coal lease, coal deed, easement, overriding royalty agreement, haulage agreement or similar instrument, together with any obligation for lump-sum advance royalties arising under the foregoing.

“Royalty Deferment and Option Agreement” means that certain agreement, effective February 9, 2011, between Armstrong Coal, Western Diamond and Western Land, Western Mineral and Ceralvo Holdings, as in effect on the Issue Date and described under “Certain Relationships and Related Party Transactions.”

“S&P” means Standard & Poor’s Ratings Services, a division of Standard & Poor’s Financial Services LLC, a subsidiary of The McGraw-Hill Companies, Inc., and its successors.

“Sale and Leaseback Transaction” means, with respect to any Person, an arrangement whereby such Person enters into a lease of property previously transferred by such Person to the lessor.

“SEC” means the U.S. Securities and Exchange Commission.

“Securities Act” means the Securities Act of 1933, as amended.

“Security Documents”means the Security Agreement, the Intercreditor Agreement and all of the security agreements, pledges, collateral assignments, mortgages, deeds of trust, trust deeds or other instruments evidencing or creating or purporting to create any security interests in favor of the Collateral Agent for its benefit and for the benefit of the Trustee and the holders of the Notes, in all or any portion of the Collateral, as amended, modified, restated, supplemented or replaced from time to time.

“Senior Secured Note Documents”means the Indenture, the Notes, the Note Guarantees and the Security Documents.

“Significant Restricted Subsidiary” means any Restricted Subsidiary, or group of Restricted Subsidiaries, that would, taken together, be a “significant subsidiary” as defined in Article 1, Rule 1-02 (w)(1) or (2) of Regulation S-X promulgated under the Securities Act, as such regulation is in effect on the Issue Date.

“Stated Maturity” means (i) with respect to any Indebtedness, the date specified as the fixed date on which the final installment of principal of such Indebtedness is due and payable or (ii) with respect to any scheduled installment of principal of or interest on any Indebtedness, the date specified as the fixed date on which such installment is due and payable as set forth in the documentation governing such Indebtedness, not including any contingent obligation to repay, redeem or repurchase prior to the regularly scheduled date for payment.

205

“Subordinated Indebtedness” means (i) any Indebtedness of the Company or any Guarantor which is subordinated in right of payment to the Notes or the Note Guarantees, as applicable, pursuant to a written agreement to that effect, (ii) unsecured Indebtedness of the Company or any Restricted Subsidiary and (iii) Indebtedness of the Company or any Restricted Subsidiary that is secured by a Lien on the Notes Priority Collateral that is junior in priority to the Notes Liens (other than Indebtedness under the Credit Agreement and other Credit Facilities secured by the Collateral with the priorities set forth in the Intercreditor Agreement).

“Subsidiary” means with respect to any Person, any corporation, association, limited liability company or other business entity of which more than 50% of the outstanding Voting Stock is owned, directly or indirectly, by, or, in the case of a partnership, the sole general partner or the managing partner or the only general partners of which are, such Person and one or more Subsidiaries of such Person (or a combination thereof). Unless otherwise specified, “Subsidiary” means a Subsidiary of the Company. Notwithstanding, Elk Creek GP, LLC shall not be a “Subsidiary” hereunder so long as it holds no assets other than (i) the general partnership interest in Armstrong Resource Partners, (ii) cash in the form of distributions from Armstrong Resource Partners that are promptly distributed or transferred to the Company or a Subsidiary of the Company and (iii) other assets with a Fair Market Value, in the aggregate, of less than $1.0 million.

“Taxes” means any present or future tax, levy, import, duty, charge, deduction, withholding, assessment or fee of any nature (including interest, penalties, and additions thereto) that is imposed by any Governmental Authority or other taxing authority.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to theredemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to December 15, 2016;provided, however,that if the period from the redemption date to such date is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

“UCC”means the Uniform Commercial Code as in effect from time to time in the State of New York;provided, however,that, at any time, if by reason of mandatory provisions of law, any or all of the perfection or priority of the Collateral Agent’s security interest in any item or portion of the Collateral is governed by the Uniform Commercial Code as in effect in a jurisdiction other that the State of New York, the term “UCC” shall mean the Uniform Commercial Code as in effect, at such time, in such other jurisdiction for purposes of the provisions hereof relating to such perfection or priority and for purposes of definitions relating to such provisions.

“U.S. Government Obligations” means obligations issued or directly and fully guaranteed or insured by the United States of America or by any agent or instrumentality thereof,providedthat the full faith and credit of the United States of America is pledged in support thereof.

“Unrestricted Subsidiary” means any Subsidiary of the Company that at the time of determination has previously been designated, and continues to be, an Unrestricted Subsidiary in accordance with “Designation of Restricted and Unrestricted Subsidiaries.”

“Vendor Liens” means existing Liens which encumber real property interests acquired by the Company or any Guarantor prior to the Issue Date for the purpose of securing a portion of the purchase price for such property.

“Voting Stock” means, with respect to any Person, Capital Stock of any class or kind ordinarily having the power to vote for the election of directors, managers or other voting members of the governing body of such Person.

206

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing: (i) the sum of the products obtained by multiplying (a) the amount of each then-remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by (ii) the then-outstanding principal amount of such Indebtedness.

“Wind-Down Subsidiary” means a Subsidiary of the Company with no material assets and no material operations and which, as of the Issue Date, the Company intends to dissolve, liquidate, wind down or merge out of existence within six months after the Issue Date. Notwithstanding the foregoing, upon any Investment by the Company or a Restricted Subsidiary in a Wind-Down Subsidiary, other than any Investment required or reasonably necessary to accomplish such dissolution, liquidation, winding down or merger, shall no longer constitute a Wind-Down Subsidiary and shall promptly execute a Note Guarantee.

“Wholly Owned” means, with respect to any Restricted Subsidiary, a Restricted Subsidiary all of the outstanding Capital Stock of which (other than any director’s qualifying shares) is owned by the Company and one or more Wholly Owned Restricted Subsidiaries (or a combination thereof).

“Yorktown”means, collectively, Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., Yorktown Energy Partners VIII, L.P., Yorktown Energy Partners IX, L.P. and any other investment fund managed by Yorktown Partners LLC.

CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain material U.S. federal income tax considerations relating to the exchange of Outstanding Notes for Exchange Notes pursuant to the exchange offer. This summary is based on the Code, Treasury Regulations, revenue rulings, administrative interpretations and judicial decisions now in effect, all of which are subject to change possibly with retroactive effect. Except as specifically set forth herein, this summary deals only with Outstanding Notes held as capital assets within the meaning of the Code (generally assets held for investment). This summary does not purport to address all federal income tax considerations that may be relevant to holders in light of their particular circumstances or to holders subject to special tax rules, such as banks, insurance companies or other financial institutions, dealers in securities, tax-exempt investors, or persons holding Outstanding Notes as part of a hedging transaction, straddle, conversion transaction, or other integrated transaction.

We have not sought any ruling from the Internal Revenue Service (the “IRS”), or an opinion of counsel with respect to the statements made and the conclusions reached in the following summary. As such, there can be no assurance that the IRS will agree with such statements and conclusions.

All persons that exchange Outstanding Notes for Exchange Notes pursuant to the exchange offer are urged to consult their own tax advisors with regard to the application of the U.S. federal income tax laws to their particular situations as well as any tax consequences arising under the laws of any state, local or foreign jurisdiction.

Consequences to Holders

The exchange of Outstanding Notes for Exchange Notes will not be treated as an exchange or taxable transaction for U.S. federal income tax purposes, but, instead, will be treated as a “non-event” because the Exchange Notes will not be considered to differ materially in kind or extent from Outstanding Notes. As a result, no holder will recognize gain or loss on the exchange, and each holder’s tax basis and holding period in Exchange Notes will be the same as its tax basis and holding period in the Outstanding Notes exchanged therefor.

207

CERTAIN ERISA CONSIDERATIONS

An Exchange Note may be acquired and held by or with the assets of (1) an employee benefit plan that is subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), (2) a plan, individual retirement account or other arrangement that is subject to (a) Section 4975 of the Code or (b) provisions under any other federal, state, local, non U.S., or other laws or regulations that are similar to such provisions of ERISA or the Code, or collectively, Similar Laws, or (3) an entity whose underlying assets are considered to include “plan assets,” within the meaning of 29 C.F.R. 2510.3 101, of any such plan, account, or arrangement under ERISA, the Code, or any Similar Law, or collectively, (a “Plan”).

In considering investing a portion of the assets of a Plan in an Exchange Note, a fiduciary of a Plan subject to ERISA should determine whether the acquisition or holding of the Exchange Note is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code or any Similar Law relating to the fiduciary’s duties to the Plan, including, without limitation, the prudence, diversification, and exclusive purpose provisions of ERISA, the Code and any other applicable Similar Laws.

In addition, a fiduciary of a Plan subject to ERISA, or any other prospective investor subject to Section 4975 of the Code or any Similar Law, must determine that its acquisition and holding of an Exchange Note does not result in a non-exempt prohibited transaction as defined in Section 406 of ERISA or Section 4975 of the Code or a similar violation of any applicable Similar Law (a “Prohibited Transaction”).

The acquisition and/or holding of an Exchange Note by a Plan with respect to which we or any guarantor is considered a party in interest or a disqualified person may constitute or result in a direct or indirect Prohibited Transaction, unless the Exchange Note is acquired and is held in accordance with an applicable statutory, class or individual Prohibited Transaction exemption under the Code, ERISA or Similar Laws.

By its acceptance or acquisition of an Exchange Note, each holder and subsequent transferee of an Exchange Note, or any interest therein, will be deemed to have represented and warranted that either (1) no portion of the assets used by such holder or transferee to acquire or hold the Exchange Note, or any interest therein, constitutes the assets of a Plan and such holder or transferee will not transfer the Exchange Note to a Plan or (2) the acquisition and holding of the Exchange Note or any interest therein does not constitute or give rise to a non-exempt Prohibited Transaction.

Any person considering the acquisition or holding of an Exchange Note on behalf of, or with the assets of, a Plan should consult legal counsel before acquisition of the Exchange Note regarding the applicability of ERISA, including Section 406 of ERISA, Section 4975 of the Code or any Similar Laws, to such investment.

Nothing herein shall be construed as a representation that an investment in an Exchange Note (1) would meet any or all of the relevant legal requirements with respect to investments by a Plan or (2) is appropriate for investment by a Plan.

208

PLAN OF DISTRIBUTION

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer, where such Outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Outstanding Notes where the Outstanding Notes were acquired as a result of market-making activities or other trading activities. To the extent any such broker-dealer participates in the exchange offer, we have agreed to use our commercially reasonable efforts to keep this registration statement effective and amend and supplement the prospectus contained therein, in order to permit this prospectus to be lawfully delivered by such broker-dealer for use in connection with any such resale for such period of time as such broker-dealer must comply with prospective delivery requirements.

We will not receive any proceeds from any sale of Exchange Notes by broker-dealers. Exchange Notes received by broker-dealers for their own accounts pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the Exchange Notes or a combination of these methods of resale, at market prices prevailing at the time of resale, at prices related to the prevailing market prices or at negotiated prices. Any resale may be made directly to purchasers or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer or the purchasers of any Exchange Notes. Any broker-dealer that resells Exchange Notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of the Exchange Notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any resale of Exchange Notes and any commissions or concessions received by these persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that by so acknowledging by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

We will not make any payments to brokers, dealers or others soliciting acceptances of the exchange offer. The estimated cash expenses to be incurred in connection with the exchange offer will be paid by us and will include fees and expenses of the exchange agent and legal, printing and related fees and expenses. Notwithstanding the foregoing, holders of the Outstanding Notes shall pay all agency fees and commissions and underwriting discounts and commissions, if any, attributable to the sale of such Outstanding Notes or Exchange Notes.

LEGAL MATTERS

Armstrong Teasdale LLP will pass on the validity of the Exchange Notes and the guarantees offered hereby. Miller Wells PLLC will pass on certain legal matters of Kentucky law relating to the guarantees by Western Land Company, LLC. Armstrong Teasdale LLP has relied upon the opinion of Miller Wells PLLC as to matters of state law in Kentucky.

COAL RESERVES

The information appearing in, and incorporated by reference in, this prospectus concerning our estimates of proven and probable coal reserves at December 31, 2012 were prepared by Weir International, Inc., an independent mining and geological consultant.

209

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The consolidated financial statements of Armstrong Energy, Inc. and subsidiaries (formerly Armstrong Land Company, LLC and subsidiaries) at December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We are not currently subject to the informational requirements of the Exchange Act. As a result of the offering of the Exchange Notes, we will become subject to the informational requirements of the Exchange Act, and, in accordance therewith, will file reports and other information with the SEC. We have filed a registration statement, of which this prospectus is a part, on Form S-4 with the SEC relating to this offering. This prospectus does not contain all of the information in the registration statement and the exhibits and financial statements included with the registration statement. References in this prospectus to any of our contracts, agreements or other documents are not necessarily complete, and you should refer to the exhibits attached to the registration statement for copies of the actual contracts, agreements or documents.

Our filings with the SEC are available to the public on the SEC’s website atwww.sec.gov. Those filings will also be available to the public on, or accessible through, our corporate website atwww.armstrongenergyinc.com. The information contained on or accessible through our corporate website or any other website that we may maintain is not part of this prospectus or the registration statement of which this prospectus is a part. You may also read and copy, at SEC prescribed rates, any document we file with the SEC, including the registration statement (and its exhibits) of which this prospectus is a part, at the SEC’s Public Reference Room located at 100 F Street, N.E., Washington, D.C. 20549. You can call the SEC at 1-800-SEC-0330 to obtain information on the operation of the Public Reference Room. You may also request a copy of these filings, at no cost, by writing to us at Armstrong Energy, Inc., 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105, Attention: Senior Vice President, Finance and Administration and Chief Financial Officer or telephoning usat (314) 721-8202.

Under the terms of the indenture governing the Notes, we agreed, whether or not we are required to do so by the rules and regulations of the SEC, to furnish to the holders of the Notes (a) all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if we were required to file such reports and (b) all current reports that would be required to be filed with the SEC onForm 8-K if we were required to file such reports, in each case, within the time periods specified in the SEC’s rules and regulations. In addition, to the extent not satisfied by the foregoing, for so long as the Notes are not freely transferable under the Securities Act, we will furnish to the holders of Notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act. See “Description of Exchange Notes.” Copies of such documents are available upon request, without charge, by writing to us at Armstrong Energy, Inc., 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105, Attention: Senior Vice President, Finance and Administration and Chief Financial Officer, or telephoning us at (314) 721-8202.

210

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2012 and 2011		F-3
Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010		F-4
Consolidated Statements of Comprehensive Income (Loss) for the years ended December  31, 2012, 2011 and 2010		F-5
Consolidated Statements of Stockholders’ Equity for the years ended December  31, 2012, 2011 and 2010		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010		F-7
Notes to Audited Consolidated Financial Statements		F-8
Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012		F-41
Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30, 2013 and 2012		F-42
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the six months ended June 30, 2013 and 2012		F-43
Unaudited Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2013		F-44
Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012		F-45
Notes to Unaudited Condensed Consolidated Financial Statements		F-46

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Armstrong Energy, Inc. and Subsidiaries (formerly

Armstrong Land Company, LLC and Subsidiaries)

We have audited the accompanying consolidated balance sheets of Armstrong Energy, Inc. and Subsidiaries (formerly Armstrong Land Company, LLC and Subsidiaries) (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

St. Louis, Missouri

March 21, 2013, except for footnote 25,

as to which the date is September 16, 2013

F-2

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	60,132		$	19,580
Accounts receivable		24,138			22,506
Inventories		9,461			11,409
Prepaid and other assets		3,722			4,260
Deferred income taxes		984			—
Total current assets		98,437			57,755
Property, plant, equipment, and mine development, net		431,225			417,603
Investments		3,323			3,178
Intangible assets, net		573			1,305
Other non-current assets		26,751			28,067
Total assets	$	560,309		$	507,908
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	26,902		$	35,442
Accrued and other liabilities		14,484			14,638
Current portion of capital lease obligations		4,243			4,347
Current maturities of long-term debt		3,935			33,957
Total current liabilities		49,564			88,384
Long-term debt, less current maturities		199,961			125,752
Long-term obligation to related party		98,388			71,047
Related party payable		4,886			25,700
Asset retirement obligations		17,962			17,131
Long-term portion of capital lease obligations		5,474			9,707
Deferred income taxes		984			—
Other non-current liabilities		428			2,049
Total liabilities		377,647			339,770
Stockholders’ equity:
Common stock, $0.01 par value, 70,000,000 shares authorized, 21,870,765 shares and 19,095,763 shares issued and outstanding as of December 31, 2012 and 2011, respectively		219			191
Preferred stock, $0.01 par value, 1,000,000 shares authorized, no shares issued and outstanding as of December 31, 2012 and 2011, respectively		—			—
Additional paid-in-capital		238,713			208,044
Accumulated deficit		(56,289	)		(38,250	)
Accumulated other comprehensive income		—			(1,862	)
Armstrong Energy, Inc.’s equity		182,643			168,123
Non-controlling interest		19			15
Total stockholders’ equity		182,662			168,138
Total liabilities and stockholders’ equity	$	560,309		$	507,908

See accompanying notes to consolidated financial statements.

F-3

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands)

	Year Ended December 31,
	2012			2011			2010
Revenue	$	382,109		$	299,270		$	220,625
Costs and expenses:
Operating costs and expenses, exclusive of items shown separately below		282,569			221,597			151,838
Production royalty to related party		5,695			578			—
Depreciation, depletion, and amortization		33,066			27,661			18,892
Asset retirement obligation expenses		3,977			4,005			3,087
Selling, general, and administrative expenses		50,154			37,494			27,656
Operating income		6,648			7,935			19,152
Other income (expense):
Interest income		68			145			198
Interest expense		(19,268	)		(10,839	)		(11,070	)
Other income (expense), net		(1,534	)		(178	)		(111	)
Gain on deconsolidation		—			311			—
(Loss) gain on extinguishment of debt		(3,953	)		6,954			—
(Loss) income before income taxes		(18,039	)		4,328			8,169
Income taxes		—			856			—
Net (loss) income		(18,039	)		3,472			8,169
Less: income attributable to non-controlling interest		—			7,448			3,351
Net (loss) income attributable to common stockholders	$	(18,039	)	$	(3,976	)	$	4,818

See accompanying notes to consolidated financial statements.

F-4

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

	Year Ended December 31,
	2012			2011			2010
Net (loss) income	$	(18,039	)	$	3,472		$	8,169
Other comprehensive income:
Unrealized loss on derivatives arising during the period, net of tax of zero		—			(1,862	)		—
Less: reclassification adjustments for loss on derivatives included in net income (loss), net of tax of zero		(1,862	)		—			—
Other comprehensive income (loss)		1,862			(1,862	)		—
Comprehensive (loss) income		(16,177	)		1,610			8,169
Less: comprehensive income attributable to non-controlling interests		—			7,448			3,351
Comprehensive (loss) income attributable to common stockholders	$	(16,177	)	$	(5,838	)	$	4,818

See accompanying notes to consolidated financial statements.

F-5

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Amounts in thousands)

	Common Stock						Preferred Stock
	Number of Shares			Amount			Number of Shares			Amount			Additional Paid-in-Capital		Accumulated Deficit			Accumulated Other Comprehensive Loss			Non-Controlling Interest			Total Stockholders’ Equity
Balance at December 31, 2009		19,111		$	191			—		$	—		$	204,809	$	(39,092	)	$	—		$	89,425		$	255,333
Net income		—			—			—			—			—		4,818			—			3,351			8,169
Stock based compensation		—			—			—			—			79		—			—			—			79
Non-controlling interest contributions		—			—			—			—			—		—			—			33,100			33,100
Balance at December 31, 2010		19,111			191			—			—			204,888		(34,274	)		—			125,876			296,681
Net income (loss)		—			—			—			—			—		(3,976	)		—			7,448			3,472
Change in fair value of cash flow hedge		—			—			—			—			—		—			(1,862	)		—			(1,862	)
Stock based compensation		—			—			—			—			450		—			—			—			450
Shares issued under employee plan		19			—			—			—			—		—			—			—			—
Non-controlling interest contributions		—			—			—			—			—		—			—			5,000			5,000
Deconsolidation of non-controlling interest		—			—			—			—			—		—			—			(137,968	)		(137,968	)
Acquisition ofnon-controlling interest		74			1			—			—			472		—			—			(341	)		132
Issuance of stock to non-employees		41			—			—			—			217		—			—			—			217
Repayment of non-recourse notes		—			—			—			—			1,083		—			—			—			1,083
Repurchase of common stock		(149	)		(1	)		—			—			934		—			—			—			933
Balance at December 31, 2011		19,096			191			—			—			208,044		(38,250	)		(1,862	)		15			168,138
Net loss		—			—			—			—			—		(18,039	)		—			—			(18,039	)
Change in fair value of cash flow hedge		—			—			—			—			—		—			1,862			—			1,862
Stock based compensation		—			—			—			—			697		—			—			—			697
Issuance of Series A convertible preferred stock		—			—			300			30,000			—		—			—			—			30,000
Conversion of Series A convertible preferred stock		2,775			28			(300	)		(30,000	)		29,972		—			—			—			—
Non-controlling interest contributions		—			—			—			—			—		—			—			4			4
Balance at December 31, 2012		21,871		$	219			—		$	—		$	238,713	$	(56,289	)	$	—		$	19		$	182,662

See accompanying notes to consolidated financial statements.

F-6

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	Year Ended December 31,
	2012			2011			2010
Operating activities
Net (loss) income	$	(18,039	)	$	3,472		$	8,169
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Non-cash stock compensation expense		697			1,383			79
Non-cash charge related to non-recourse notes		—			217			—
Depreciation, depletion, and amortization		33,066			27,661			18,892
Amortization of debt issuance costs		1,208			668			—
Amortization of original issue discount		18			—			—
Asset retirement obligations		3,977			4,005			3,932
Gain on settlement of asset retirement obligations		(234	)		—			—
(Income) loss from equity affiliate		(15	)		8			—
(Gain) loss on sale of property, plant, and equipment		(38	)		123			(68	)
Loss (gain) on extinguishment of debt		3,953			(6,954	)		—
Gain on deconsolidation		—			(311	)		—
Interest on long-term obligations		215			1,762			12,593
Change in working capital accounts:
(Increase) decrease in accounts receivable		(1,632	)		(8,579	)		4,961
Decrease (increase) in inventories		1,948			1,602			(7,237	)
Increase in prepaid and other assets		(190	)		(2,444	)		(218	)
Decrease (increase) in other non-current assets		8,001			1,907			(3,883	)
(Decrease) increase in accounts payable and accrued and other liabilities		(8,379	)		21,379			1,328
Increase (decrease) in other non-current liabilities		6,213			2,275			(1,354	)
Net cash provided by operating activities		30,769			48,174			37,194
Investing activities
Cash decrease due to deconsolidation		—			(155	)		—
Investment in property, plant, equipment, and mine development		(46,464	)		(73,627	)		(41,755	)
Investment in affiliates		(130	)		(2,470	)		—
Proceeds from sale of fixed assets		70			425			—
Net cash used in investing activities		(46,524	)		(75,827	)		(41,755	)
Financing activities
Payment on capital lease obligations		(4,338	)		(4,115	)		(3,692	)
Payments of long-term debt		(169,872	)		(118,170	)		(33,343	)
Proceeds from long-term debt		211,634			140,000			—
Proceeds from financing obligation with ARP		—			20,000			—
Payment of financing costs and fees		(11,117	)		(4,798	)		—
Proceeds from repayment of non-recourse notes		—			1,083			—
Proceeds from the acquisition of non-controlling interest		—			132			—
Proceeds from the issuance of Series A convertible preferred stock		30,000			—			—
Minority contributions		—			5,000			33,100
Net cash provided by (used in) financing activities		56,307			39,132			(3,935	)
Net increase (decrease) in cash and cash equivalents		40,552			11,479			(8,496	)
Cash and cash equivalents, at beginning of year		19,580			8,101			16,597
Cash and cash equivalents, at end of year	$	60,132		$	19,580		$	8,101
	Year Ended December 31,
	2012			2011			2010
Supplemental cash flow information:
Cash paid for interest	$	7,404		$	17,172		$	30,440
Cash paid for income taxes		—			1,030			—
Non-cash transactions:
Investment in property, plant, and equipment; mine development; and intangibles acquired with debt		2,407			18,927			2,638
Assets acquired by capital lease		—			2,296			1,951
Common stock acquisitions financed		—			452			—
Interest on long-term obligations		—			1,276			12,593

See accompanying notes to consolidated financial statements.

F-7

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share amounts)

1. DESCRIPTION OF BUSINESS AND ENTITY STRUCTURE

Armstrong Energy, Inc. (formerly Armstrong Land Company, LLC) (AE) and subsidiaries (collectively, the Company) commenced business on September 19, 2006 (inception), for the purpose of owning and operating coal reserves (also referred to as mineral rights) and production assets. As of December 31, 2012, all subsidiaries are majority owned. The Company is a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin, operating both surface and underground mines. The Company is majority owned by investment funds managed by Yorktown Partners LLC (Yorktown). AE, which is headquartered in St. Louis, Missouri, markets its coal primarily to electric utility companies as fuel for their steam-powered generators. As of December 31, 2012, the Company had approximately 965 employees, none of whom are under a collective bargain arrangement.

In August 2011, Armstrong Resources Holdings, LLC merged with and into Armstrong Energy, Inc., which subsequently changed its name to Armstrong Energy Holdings, Inc., a wholly owned subsidiary of Armstrong Land Company, LLC (ALC). Subsequently, ALC adopted a Plan of Conversion (the Plan), which resulted in ALC being converted to a C-corporation named Armstrong Land Company, Inc. (ALCI) effective October 1, 2011. Also, effective October 1, 2011, the Plan authorized the conversion of each issued and outstanding membership unit of ALC into 9.25 shares of common stock of AE. Concurrent with the effectiveness of the Plan, ALCI changed its name to Armstrong Energy, Inc. (collectively, the Reorganization).

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Factors Affecting Comparability

Certain prior year amounts have been reclassified to conform to current year presentation, with no effect on the previously reported results of operations. In addition, the reclassifications were not material to the accompanying footnotes to the prior year consolidated financial statements.

Principles of Consolidation

The consolidated financial statements include the accounts of AE and its wholly and majority-owned subsidiaries. All significant intercompany balances and transactions were eliminated.

Prior to September 30, 2011, the Company consolidated the results of Armstrong Resource Partners, L.P. and its subsidiaries (ARP), which were not majority owned, in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810-20,Consolidation—Control of Partnerships and Similar Entities. The Company’s wholly-owned subsidiary, Elk Creek General Partner (ECGP), has an approximate 0.4% ownership in ARP. Beginning in the fourth quarter of 2011, the Company concluded it no longer has control of ARP. Accordingly, it ceased consolidating the results of operations and financial position of ARP and started accounting for its investment in ARP under the equity method of accounting (See Note 3). Therefore, the users of the Company’s consolidated financial statements should consider the effect of deconsolidation when comparing 2012 to prior periods.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

In June 2011, the FASB amended requirements for the presentation of other comprehensive income (loss), requiring presentation of comprehensive income (loss) in either a single, continuous statement of comprehensive income or on separate but consecutive statements, the statement of operations and the statement of other

F-8

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

comprehensive income (loss). The amendment was effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company has reflected the new presentation in its consolidated statements of comprehensive income (loss) with no impact on its results of operations, financial condition 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 was effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not materially affect the Company’s consolidated financial statements.

Use of Estimates

The preparation of consolidated financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of income and loss during the reporting periods. Actual results could differ from those estimates.

Revenue

Coal sales are recognized as revenue when title and risk of loss passes to the customer. Coal sales are made to customers under the terms of supply agreements, most of which are long-term (greater than one year). Under the terms of the Company’s coal supply agreements, title and risk of loss typically transfer to the customer at the mine where coal is loaded on the truck, rail, or barge. Coal sales include the freight charged to the customer on destination contracts.

Other Income (Expense), net

Other income includes farm income, timber income, and other income from the lease of surface property. For the year ended December 31, 2012, other income (expense), net also includes charges of $1,409 for a loss on the settlement of the interest rate swap (see Note 16) and $1,130 for a loss on the deferment of an equity offering. The Company had deferred costs related to amounts incurred on a proposed equity offering. As the offering has been delayed for an extended period of time, a charge was recognized in the fourth quarter of 2012 to write-off all deferred amounts associated with the equity offering.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. The Company considers all cash and temporary investments having an original maturity of less than three months to be cash equivalents.

Accounts and Other Receivables

Accounts receivable are recorded at the invoiced amount and do not bear interest. The Company evaluates the need for an allowance for doubtful accounts based on anticipated recovery and industry data. As of December 31, 2012 and 2011, the Company had not established an allowance for accounts receivable.

F-9

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Inventories

Inventories consist of coal as well as materials and supplies that are valued at the lower of cost or market. Raw coal stockpiles may be sold in their current condition or processed further prior to shipment. Cost is determined using the first-in, first-out method for materials and supplies. Coal inventory costs include labor, supplies, equipment cost, royalties, taxes, other related costs, and, where applicable, preparation plant costs. Stripping costs incurred during the production phase of the mine are considered variable production costs and are included in the cost of coal during the period the stripping costs are incurred.

Property, Plant, Equipment, and Mine Development

Property, plant, and equipment are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2012, 2011, and 2010 was $1,179, $1,545, and $2,830, respectively.

Expenditures that extend the useful lives of existing plant and equipment assets are capitalized, while normal repairs and maintenance that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Plant and equipment are depreciated using the straight-line method over the useful lives of the assets, which are detailed below.

Asset Type	Life (Years)
Buildings and improvements		7-40
Mine equipment		2-10
Vehicles		3-10
Office equipment and software		3-7

Costs to acquire or construct significant new assets are capitalized and amortized using the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited, when placed into service, as a part of the new asset being constructed. These costs include but are not limited to legal fees, permit and license costs, materials cost, associated labor costs, mine design, construction of access roads, shafts, slopes and main entries, and removing overburden to access reserves in a new pit. Where multiple assets are acquired for one purchase price, the cost of the purchase is allocated among the individual assets in proportion to their market value with assistance from a third party specializing in the valuation of the purchased assets.

Mineral rights are recorded at cost as property, plant, equipment, and mine development. Amortization of mineral rights and mine development is provided by the units-of-production method over estimated total recoverable proven and probable reserves.

Costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred. The Company did not incur a significant amount of these costs in 2012, 2011, or 2010. Start-up costs are expensed as incurred. Certain costs incurred to develop coal mines or to expand the capacity of an existing mine are capitalized and amortized using the units-of-production method.

Other Non-Current Assets

Other non-current assets include advance royalties and amounts held by third parties to guarantee performance on the delivery of coal, reclamation bonds, and other performance guarantees. The amounts pledged are restricted for the term of the bonds and cannot be withdrawn without the consent of the bonding companies.

F-10

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Rights to leased coal and the related surface land can be acquired through royalty payments. Where royalty payments represent prepayments recoupable against future production, they are recorded as a prepaid asset, and amounts expected to be recouped within one year are classified as a current asset. As mining occurs on these leases, the prepayment is charged to cost of coal sales. See Note 18 for further details of royalty agreements.

Also included within other non-current assets are deferred financing costs, which are subject to amortization over the term of the associated debt obligation using the effective interest method.

Investments

Investments and ownership interests are accounted for under the equity method of accounting if the Company has the ability to exercise significant influence, but not control, over the entity. If the Company does not have control and cannot exercise significant influence, the investment is accounted for using the cost method.

Long-Lived Assets

If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates the carrying value of the asset will not be recovered, as determined based on projected undiscounted cash flows related to the asset over its remaining life, the carrying value of the asset is reduced to its estimated fair value through an impairment loss. No impairment losses were recognized during the years ended December 31, 2012, 2011, or 2010.

Asset Retirement Obligations (ARO) and Reclamation

The Company’s ARO activities consist of estimated spending related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mining permit. Obligations are incurred when development of a mine commences for underground mines and surface facilities or, in the case of support facilities, refuse areas and slurry ponds when construction begins.

The obligation’s fair value is determined using discounted cash flow techniques and is accreted to its present value at the end of each period. The Company estimates ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate. The Company records an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized using the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited. The ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-fee rate.

Fair Value

For assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

F-11

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivatives

Derivative instruments are accounted for in accordance with the applicable FASB guidance on accounting for derivative instruments and hedging activity. This guidance provides comprehensive and consistent standards for the recognition and measurement of derivative and hedging activities. It also requires that derivatives be recorded on the consolidated balance sheet at fair value and establishes criteria for hedges of changes in fair values of assets, liabilities, or firm commitments; hedges of variable cash flows of forecasted transactions; and hedges of foreign currency exposures of net investments in foreign operations. The Company historically has used derivatives only to hedge the variable cash flows of future interest payments on long-term debt. To the extent a derivative qualifies as a cash flow hedge, the gain or loss associated with the effective portion is recorded as a component of Accumulated Other Comprehensive Income (Loss). Changes in the fair value of derivatives that do not meet the criteria for hedge accounting would be recognized in the consolidated statements of operations. When an interest rate swap agreement terminates, any resulting gain or loss is recognized over the shorter of the remaining original term of the hedging instrument or the remaining life of the underlying debt obligation.

Income Taxes

The Company is subject to taxation. Deferred income taxes are recorded by applying statutory tax rates in effect at the date of the balance sheet to differences between the income tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining whether a valuation allowance is appropriate, projected realization of tax benefits is considered based on expected levels of future taxable income, available tax planning strategies, and the overall deferred tax position. If actual results differ from the assumptions made in the evaluation of the amount of the valuation allowance, the Company records a change in the valuation allowance through income tax expense in the period such determination is made. Certain subsidiaries are disregarded for income tax purposes and are included in each respective parent entity’s tax returns.

The calculations of the Company’s tax liabilities involve dealing with uncertainties in the application of complex tax regulations. The Company recognizes liabilities for uncertain tax positions based on the two-step process prescribed in ASC 740,Income Taxes. The first step is to evaluate the tax position for recognition by determining whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The second step requires the Company to estimate and measure the tax benefit as the largest amount that is more than 50% likely to be realized upon settlement. The Company re-evaluates these uncertain tax positions annually. This evaluation is based on factors including, but not limited to, changes in facts or circumstances, changes in tax law, effectively settled issues under audit, or new audit activity. Such a change in recognition or measurement results in the recognition of a tax benefit or an additional charge to the tax provision.

Workers’ Compensation and Black Lung

The Company has no liabilities under state statutes or the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees, former employees and their dependents. Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to eligible claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax

F-12

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

on production. For the years ended December 31, 2012, 2011, and 2010, the Company recorded $6,411, $4,945 and $4,181, respectively, of expense related to this excise tax.

With regard to workers’ compensation, the Company provides benefits to its employees by being insured through an insurance carrier. Premium expense for workers’ compensation benefits is recognized in the period in which the related insurance coverage is provided.

Investment Credits

For establishing operations in Ohio County, Kentucky, the Company qualified for investment credits totaling $16,000 recoverable from the State of Kentucky to be applied against certain state income and employee payroll taxes paid. Investment credits, which expire in 2021, are accounted for using the deferral method. During the year ended December 31, 2012, the Company recognized $2,417 in investment credits, which were applied against certain employee payroll taxes in the statement of operations. As of December 31, 2012, the Company had $13,583 in investment credit carryforwards available.

Equity Awards

The Company accounts for common stock (and previously, members’ equity units) paid with a note and issued to employees as compensation expense. Amounts are recorded at fair market value. The Company used the Black-Scholes option model in estimating the fair value of awards. Compensation expense is measured on the grant date and recognized over the implied vesting period.

The Company accounts for share-based compensation at the grant date fair value of awards and recognizes the related expense over the vesting period of the award.

3. DECONSOLIDATION OF ARMSTRONG RESOURCE PARTNERS

Through September 30, 2011, the Company consolidated the results of ARP in accordance withASC 810-20, as ECGP was presumed to control the partnership. On October 1, 2011, the partners of ARP entered into the Amended and Restated Agreement of Limited Partnership of Armstrong Resource Partners, L.P. (the ARP LPA). Pursuant to the ARP LPA, effective October 1, 2011, Yorktown, ARP’s largest unit holder, unilaterally may remove the Company’s subsidiary, ECGP, as general partner of ARP or otherwise cause a change of control of ARP without the Company’s consent or the consent of the holders of ARP’s equity units. As a result of the loss of control of ARP by ECGP, the Company no longer consolidates the results of operations of ARP effective October 1, 2011 and accounts for its ownership in ARP under the equity method of accounting. Under the deconsolidation accounting guidelines, the investor’s opening investment was recorded at fair value as of the date of deconsolidation. The difference between this initial fair value of the investment and the net carrying value was recognized as a gain or loss in earnings.

In order to determine the fair value of its initial investment in ARP, the Company completed a valuation analysis based on the income approach using the discounted cash flow method. The discount rate, long-term growth rate, and profitability assumptions are material inputs utilized in the discounted cash flow model. Based on the results of this valuation, the deconsolidation date fair value of the Company’s investment in ARP was determined to be $716. The Company recognized a non-cash gain included as a component of other income (expense), net of approximately $311 in the year ended December 31, 2011 related to the deconsolidation of ARP.

F-13

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. PROPERTY TRANSACTIONS

On December 29, 2011, the Company entered into a transaction in which it acquired additional property and mineral interests contiguous to its existing and planned mines. The rights and interests in certain owned and leased coal reserves located in Muhlenberg County, Kentucky, were acquired in exchange for (i) a cash payment by the Company of approximately $8,871, (ii) a promissory note due June 30, 2012 in the aggregate principal amount of approximately $4,435, and (iii) an overriding royalty to the seller to the extent the Company mines in excess of certain tonnages from the property, as set forth in the purchase agreement. The Company also acquired certain reserves and entered into a lease allowing it the right to mine certain additional reserves in Union County, Kentucky. In consideration of the sale and lease of real property, the Company agreed to deliver (i) approximately $6,007 in cash, (ii) a promissory note due June 30, 2012 in the aggregate principal amount of approximately $3,004, and (iii) an overriding royalty of 2% of the gross selling price on each ton of coal produced and sold from the coal reserves that were purchased (thus excluding the leased coal). The cash utilized for the acquisition was obtained from ARP in exchange for an additional undivided interest in certain land and mineral reserves of the Company (see Note 13). Both promissory notes were repaid during 2012 on their maturity dates.

5. INVENTORIES

Inventories consist of the following amounts:

	December 31,
	2012		2011
Materials and supplies	$	8,547	$	10,371
Coal—raw and saleable		914		1,038
Total	$	9,461	$	11,409

6. PROPERTY, PLANT, EQUIPMENT, AND MINE DEVELOPMENT

Property, plant, equipment, and mine development consist of the following as of December 31, 2012 and 2011:

	2012		2011
Land	$	37,561	$	35,467
Mineral rights		150,667		150,667
Machinery and equipment		167,027		146,166
Buildings and facilities		82,916		75,707
Office equipment, software and other		16,871		14,352
Mine development costs		50,272		45,917
ARO assets		14,962		15,919
Construction-in-progress		16,598		4,136
		536,874		488,331
Less: accumulated depreciation, depletion, and amortization		105,649		70,728
Total	$	431,225	$	417,603

Depreciation expense, including amounts from capitalized leases, for the years ended December 31, 2012, 2011, and 2010, was $22,936, $18,077, and $11,375, respectively. For the years ended December 31, 2012, 2011 and 2010, depletion expense related to mineral rights amounted to $7,133, $6,343, and $4,443, respectively;

F-14

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

amortization expense related to mine development costs amounted to $2,265, $3,241, and $1,707, respectively; and depreciation expense related to the ARO assets amounted to $2,304, $2,157, and $2,241, respectively.

The Company has pledged substantially all buildings and equipment as security under the Notes and 2012 Credit Facility (see Note 15), as well as under certain capital lease obligations.

The Company had outstanding construction commitments as of December 31, 2012, of approximately $4,095. All construction commitments are expected to be completed within the next fiscal year.

7. INTANGIBLE ASSETS

Intangible assets consist of mine plans and permits acquired in certain property acquisitions, as well as a non-compete agreement entered into in conjunction with the acquisition of a minority stockholder’s interest and settlement of litigation. Mine plans and permits are being amortized over five years beginning in the year that mining operations commence on the associated area. The non-compete agreement is being amortized, using the straight-line method, over the five-year term of the agreement. Intangible assets consist of the following as of December 31, 2012 and 2011:

	2012		2011
Mine plans and other intangibles acquired	$	440	$	440
Non-compete agreement		3,354		3,354
		3,794		3,794
Less: accumulated amortization		3,221		2,489
Total	$	573	$	1,305

Amortization expense related to intangible assets amounted to $732, $732, and $705 for the years ended December 31, 2012, 2011, and 2010, respectively. The weighted average remaining period over which intangible assets are being amortized is 1.7 years. The estimated future amortization expense is as follows:

	(In thousands)
2013	$	431
2014		9
2015		26
2016		26
2017		26
2018 and thereafter		55
Total	$	573

8. INVESTMENTS

Survant Mining Company, LLC

On December 29, 2011, the Company formed a joint venture, Survant Mining Company, LLC (Survant), relating to coal reserves near its Parkway mine with a subsidiary of Peabody Energy, Inc. (Peabody). In connection with the joint venture, Peabody agreed to contribute an aggregate of approximately 25 million tons of recoverable coal reserves located in Muhlenberg County, Kentucky, and the Company agreed to contribute certain mining assets to the joint venture. The Company and Peabody also agreed to contribute 51% and 49%,

F-15

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

respectively, of the cash sufficient to complete the development of the mine and sufficient for down payments on mining equipment. The Company will manage the joint venture’s day-to-day operations and the development of the mine in exchange for a management fee of $0.50 per ton sold. Peabody will receive a $0.25 per ton commission on all coal sales by the joint venture. During 2012, Peabody and the Company each contributed $130 to Survant. The Company applies the equity method to account for its investment in Survant, as it has the ability to exercise significant influence over the operating and financial policies of the joint venture.

RAM Terminals, LLC

On June 1, 2011, the Company entered into an agreement to acquire an equity interest in Ram Terminals, LLC (RAM) for $2,470. RAM, whose controlling unitholder is Yorktown, owns approximately 600 acres of Mississippi River front property south of New Orleans and intends to permit, design and construct a seaborne coal export terminal with an annual through-put capacity of up to 10 million tons. The Company has the option to make additional contributions to RAM, but it is expected all future expenditures will be funded by Yorktown and its affiliates and therefore the Company’s equity interest will be significantly reduced in the future. As of December 31, 2012, the Company had an equity interest in RAM of approximately 5.0%. Effective January 1, 2012, the Company and RAM entered into a services agreement, whereby the Company will provide administrative and management services to RAM. In consideration for the services provided, RAM paid the Company $252 for the year ended December 31, 2012. Because of the Company’s limited influence over the investment and future dilution of ownership interest, the cost method is used to account for this investment. It is not practicable to estimate the fair value of this investment. In addition, the Company did not evaluate the investment for impairment as no factors indicating impairment existed during the year.

9. OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following as of December 31, 2012 and 2011:

	2012		2011
Escrows and deposits	$	4,675	$	5,047
Restricted surety and cash bonds		4,306		5,130
Advanced royalties		7,684		13,760
Deferred financing costs, net		10,086		4,130
Total	$	26,751	$	28,067

10. ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following amounts as of December 31, 2012 and 2011:

	2012		2011
Payroll and related benefits	$	6,494	$	6,101
Taxes other than income taxes		4,215		2,892
Interest		708		494
Asset retirement obligations		523		1,821
Royalties		1,171		1,137
Construction retainage		—		375
Other		1,373		1,818
Total	$	14,484	$	14,638

F-16

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures the fair value of assets and liabilities using a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: Level 1—observable inputs such as quoted prices in active markets; Level 2—inputs, other than quoted market prices in active markets, which are observable, either directly or indirectly; and Level 3—valuations derived from valuation techniques in which one or more significant inputs are unobservable. In addition, the Company may use various valuation techniques including the market approach, using comparable market prices; the income approach, using present value of future income or cash flow; and the cost approach, using the replacement cost of assets.

The Company’s financial instruments consist of cash equivalents, accounts receivable, long-term debt, and other long-term obligations. For cash equivalents, accounts receivable and other long-term obligations, the carrying amounts approximate fair value due to the short maturity and financial nature of the balances. The estimated fair market values of the Company’s Notes, 2011 Credit Facility – Term Loan, 2011 Credit Facility – Revolving Credit Facility and cash flow hedge, which were determined using level 2 inputs, and long-term obligation to ARP, which was determined using level 3 inputs, are as follows:

	December 31, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
2019 Notes(1)	$	191,500	$	193,152	$	—	$	—
2011 Credit Facility—Term Loan		—		—		100,000		100,000
2011 Credit Facility—Revolving Credit Facility		—		—		40,000		40,000
Long-term obligation to ARP		103,506		98,388		74,848		71,047
Cash flow hedge		—		—		1,862		1,862
Total	$	295,006	$	291,540	$	216,710	$	212,909

(1) The carrying value of the Notes is net of the unamortized original issue discount as of December 31, 2012.

The fair value of the Notes is based on quoted market prices, while the fair value of the long-term obligation to ARP was based on estimated cash flows discounted to their present value. As the term loan and revolving credit facility under the 2011 Credit Facility bear interest at a variable rate, the carrying value of these debt instruments approximated their fair value.

12. RISKS AND CONCENTRATIONS

Geographical Concentration

The Company’s operations are concentrated in western Kentucky, and a disruption within that geographic region could adversely affect the Company’s performance.

Customer Concentration

The Company has multi-year coal supply agreements with multiple customers. The top two customers accounted for 36% and 27%, respectively, of net sales for the year ended December 31, 2012. The Company seeks to mitigate credit risk by monitoring creditworthiness of these customers and adjusting credit amounts provided accordingly. Significant interruption to these customer facilities covered under force majeure provisions of their contracts could adversely affect the Company’s results.

F-17

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. RELATED-PARTY TRANSACTIONS

Sale of Coal Reserves

On November 30, 2009, and again on March 31, 2010, May 31, 2010, and November 30, 2010, AE entered into promissory notes with ARP (ARP promissory notes) whereby ARP loaned funds to AE for the sole purpose of making the scheduled payments under the secured debt agreements outstanding with various third parties existing at December 31, 2010 (secured promissory notes). The amounts were $11,000 on November 30, 2009; $9,500 on March 31, 2010; $12,600 on May 31, 2010; and $11,000 on November 30, 2010. The ARP promissory notes had a fixed interest rate of 3%. In addition, contingent interest equal to 7% of revenue would be accrued to the extent it exceeds the fixed interest amount. No payments of principal or interest were due until the earliest of May 31, 2014, or the 91st day after the secured promissory notes had been paid in full. Further, ARP, in lieu of payment of the outstanding amounts of principal and interest, had the option to obtain an interest in the mineral reserves of the Company equal to the percentage of the aggregate amount of principal loaned and related accrued interest to the amount paid by the Company to repay or repurchase and retire the ARP promissory notes. This option could only be exercised if all secured promissory notes are repaid in full.

As discussed in Note 15, the secured promissory notes were repaid in full on February 9, 2011, which resulted in ARP exercising its option to convert the ARP promissory notes to a 39.45% undivided interest in its land and mineral reserves, excluding the reserves in Union and Webster Counties. Outstanding principal and interest of the ARP promissory notes totaled $46,620 as of February 9, 2011. As additional consideration for the land and mineral reserves transferred, ARP paid $5,000 cash and certain amounts due ARP totaling $17,871 were forgiven, resulting in aggregate consideration of $69,491. Simultaneous with this transaction, the Company entered into a lease agreement with a subsidiary of ARP, under mutually agreeable terms and conditions, to mine the acquired mineral reserves. The lease is for a term of 10 years and can be extended for additional periods until all the respective merchantable and mineable coal is removed. Due to the Company’s continuing involvement in the land and mineral reserves transferred, this transaction has been accounted for as a financing arrangement. A long-term obligation has been established that will be amortized over a 20 year period, or the estimated life of the mineral reserves, at an annual rate of 7% of the estimated gross revenue generated from the sale of the coal originating from the leased mineral reserves. Based on the Company’s estimates, the effective interest rate of the obligation was 12.5% at the time of the transaction, which will be adjusted prospectively based on changes to the mine plan. As the financial results of ARP had been consolidated in accordance with ASC 810-20 prior to the deconsolidation, which was effective October 1, 2011, this transaction did not have an impact on the consolidated results of operations or financial condition of the Company for the nine months ended September 30, 2011. Subsequent to the deconsolidation, the long-term obligation to ARP and associated interest expense are reflected in the accompanying consolidated financial statements of the Company.

On February 9, 2011, the Company entered into a series of lease agreement with certain subsidiaries of ARP, pursuant to which ARP granted the Company a lease to its 39.45% undivided interest in certain mining properties, as well as certain wholly-owned reserves (Elk Creek Reserves), and licenses to mine coal on those properties. The initial term of the agreements is ten years, and they renew for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. The Company must pay ARP a production royalty equal to 7% of the sales price of the coal it mines from the properties. The Company paid $12,000 of advance royalties under the lease of the Elk Creek Reserves, which are recoupable against production royalties. Mining of the Elk Creek Reserves began in 2011. As of December 31, 2012 and 2011, the remaining balance of the advance royalties to be recouped against future production royalties was $5,683 and $11,378, respectively.

F-18

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effective February 9, 2011, the Company entered into a Royalty Deferment and Option Agreement with certain subsidiaries of ARP, pursuant to which ARP agreed to grant the Company the option to defer payment of their pro rata share of the 7% production royalty described above. In consideration for the granting of the option to defer these payments, the Company granted to ARP the option to acquire an additional undivided interest in certain of its coal reserves in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which the Company would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.

On October 11, 2011, the Company and its wholly owned subsidiaries, Western Diamond and Western Land, entered into a Royalty Deferment and Option Agreement with certain wholly owned subsidiaries of ARP, Western Mineral Holdings, LLC (WMD) and Ceralvo Holdings, LLC (CVH). Pursuant to this agreement, WMD and CVH agreed to grant the Company and its affiliates the option to defer payment of their pro rata share of the 7% production royalty earned on the 39.45% undivided interest in mineral reserves acquired. In consideration for the granting of the option to defer these payments, the Company and its affiliates granted to WMD the option to acquire an additional partial undivided interest in certain of the mineral reserves held by the Company in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which it would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves. The Royalty Deferment and Option Agreement was effective as of February 9, 2011.

On December 29, 2011, the Company entered into a Membership Interest Purchase Agreement with ARP pursuant to which the Company agreed to sell to ARP, indirectly through contribution of a partial undivided interest in certain land and mineral reserves to a limited liability company and transfer of the Company’s membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by AE. In exchange for the Company’s agreement to sell a partial undivided interest in those reserves, ARP paid the Company $20,000. In addition to the cash paid, certain amounts due ARP totaling $5,700 were forgiven, which resulted in aggregate consideration of $25,700. This transaction closed on March 30, 2012, whereby the Company transferred an 11.36% undivided interest in certain of its land and mineral reserves to ARP. The newly transferred mineral reserves were leased back to the Company under the agreement entered into in February 2011 at the same terms. In addition, production royalties earned by ARP from the newly transferred mineral reserves are being deferred under the Royalty Deferment and Option Agreement. Due to the Company’s continuing involvement in the mineral reserves, this transaction is accounted for as an additional financing arrangement and an additional long-term obligation to ARP of $25,700 was recognized in the first quarter of 2012. The effective interest rate of the obligation, adjusted for the additional transfer of land and mineral reserves and updated for the current mine plan, is 10.67%. The cash proceeds from ARP were used to acquire additional land and mineral reserves from a third party in December 2011, as well as for other working capital needs. As of December 31, 2012, ARP has a 50.81% undivided interest in certain land and mineral reserves of the Company and the outstanding long-term obligation to ARP totaled $98,388. Interest expense recognized for the years ended December 31, 2012 and 2011 associated with the long-term obligation to ARP was $9,257 and $2,495, respectively.

F-19

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Based on the current mine plan and estimated selling prices of the coal, estimated payments under the obligation are as follows:

Year ending December 31:
2013	$	8,691
2014		9,447
2015		11,421
2016		9,385
2017		11,116
2018 and thereafter		248,120
Total payments	$	298,180

In March 2013, the Company agreed to sell an additional 2.59% interest in certain land and mineral reserves to ARP. In exchange for the undivided interest in the land and reserves, ARP will forgive amounts owed by the Company as of December 31, 2012, totaling $4,886. This transaction is expected to close in the first half of 2013. In addition, the transferred mineral reserves will be leased back to the Company on terms similar to those applicable to the previous transfers. As the Company will have a continuing involvement in the reserves, the transaction will be accounted for as a financing arrangement and an additional long-term obligation to ARP will be recognized upon closing.

Administrative Services Agreement

Effective as of January 1, 2011, the Company entered into an Administrative Services Agreement with ARP and its general partner, ECGP, pursuant to which the Company agreed to provide ARP 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 the Company’s employees and services, and for certain shared fixed costs, ARP paid the Company $750, $720, and $700 for the years ended December 31, 2012, 2011, and 2010, respectively.

Credit Support Fee

ARP was a co-borrower under the 2011 Credit Facility—Term Loan and guarantor on both the 2011 Credit Facility—Revolving Credit Facility and the 2011 Credit Facility—Term Loan, and substantially all of its assets were pledged as collateral. ARP received, as compensation for these restrictions, a fee of 1% of the weighted-average outstanding balance under the 2011 Credit Facility, which totaled $1,183, and $1,150 for the years ended December 31, 2012 and 2011, respectively. This arrangement ended in December 2012 upon the termination of the 2011 Credit Facility.

Other

The Company rented office space from a key employee of the Company. Expenses of $61, $56, and $56 were paid during the years ended December 31, 2012, 2011, and 2010, respectively.

In 2006 and 2007, the Company entered into overriding royalty agreements with two key executive employees to compensate them $0.05/ton of coal mined and sold from properties owned by certain subsidiaries of the Company. The agreements remain in effect for the later of 20 years from the date of the agreement or until

F-20

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

all salable coal has been extracted. Both royalty agreements transfer with the property regardless of ownership or lease status. The royalties are payable the month following the sale of coal mined from the specified properties. The Company accounts for these royalty arrangements as expense in the period in which the coal is sold. Expense recorded in the years ended December 31, 2012, 2011, and 2010, was $748, $684, and $569, respectively.

On May 26, 2011, the Company made a capital contribution of $2,470 for a minority equity interest in RAM. The remaining membership interest is owned by the Company’s majority shareholder, Yorktown (see Note 8).

14. ACQUISITION OF NON-CONTROLLING INTEREST

Prior to the Reorganization in August 2011, the Company acquired all of the outstanding common stock held by certain third parties in the former Armstrong Energy, Inc. and Armstrong Resources Holdings, LLC. A portion of the outstanding shares were acquired in exchange for membership interests in ALC, which totaled 7,957.5 units of membership interest (73,606 shares of common stock of AE). In addition, the Company had outstanding non-recourse promissory notes with these third parties related to a portion of their original purchase of shares in the former Armstrong Energy, Inc. in December 2006 and March 2007. The non-recourse notes, including all accrued and unpaid interest, were repaid in full through the payment of cash of $125 and the sale of their remaining shares in the former Armstrong Energy, Inc. to the Company. Simultaneous with the above, the Company sold 4,520 units of membership interest in ALC (41,810 shares of common stock of AE) to these third party investors financed with new non-recourse promissory notes due 2015 totaling $452, which are not recorded within the consolidated balance sheet as these notes are non-recourse. Each of the promissory notes carries a stated interest rate of 6% per annum and are collateralized by the unpaid ownership interest. No portions of the promissory notes are subject to release until full payment has been tendered on the applicable note. In the event of default, the notes shall bear interest at 12% per annum.

The units purchased with non-recourse notes are accounted for as options. As the options were fully vested at the date of issuance, the Company recognized a non-cash charge included as a component of other income (expense), net within the results of operations for the year ended December 31, 2011 of $217, which represents the total fair value of the options awarded. The assumptions used in determining the grant date fair value of $5.19 per share, using a Black-Scholes option pricing model, were as follows:

Risk-free rate	0.78	%
Expected unit price volatility	68.29	%
Expected term (years)	3.6
Expected dividends	—

F-21

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. LONG-TERM DEBT

The Company’s total indebtedness consisted of the following:

	As of December 31,
Type	2012		2011
11.75% Senior Secured Notes due 2019	$	193,152	$	—
2012 Credit Facility		—		—
2011 Credit Facility—Term Loan		—		100,000
2011 Credit Facility—Revolving Credit Facility		—		40,000
Other		10,744		19,709
		203,896		159,709
Less: current maturities		3,935		33,957
Total long-term debt	$	199,961	$	125,752

Senior Secured Notes due 2019

On December 21, 2012, the Company completed a $200,000 offering of 11.75% Senior Secured Notes due 2019 (the Notes). The Notes were issued at an original issue discount (OID) of 96.567%. The OID was recorded on the Company’s balance sheet as a component of long-term debt, and is being amortized to interest expense over the life of the notes. As of December 31, 2012, the unamortized OID was $6,848. The Company incurred $8,358 of deferred financing fees related to the Notes, which have been capitalized and will be amortized over the life of the Notes.

Interest on the Notes is due semiannually on June 15 and December 15 of each year, beginning on June 15, 2013. The Company may redeem all or part of the Notes at any time prior to December 15, 2016, at a redemption price of 100% of the notes redeemed plus a “make-whole” premium and accrued and unpaid interest to the applicable redemption date. The Company may redeem the Notes, in whole or in part, at any time during the twelve months commencing on December 15, 2016 at 105.875% of the principal amount redeemed, at any time during the twelve months commencing December 15, 2017 at 102.938% of the principal amount redeemed, and at any time after December 15, 2018 at 100.000% of the principal amount redeemed, in each case plus accrued and unpaid interest to the applicable redemption date. In addition, at any time prior to December 15, 2015, the Company may redeem Notes with the net cash proceeds received from one or more Equity Offerings (as defined in the indenture governing the Notes) at a redemption price equal to 111.75% of the principal amount redeemed plus accrued and unpaid interest to the applicable redemption date, in an aggregate principal amount for all such redemptions not to exceed 35% of the original aggregate principal amount of the Notes.

Upon the occurrence of an event of a Change in Control (as defined in the indenture governing the Notes), unless the Company has exercised its right to redeem the Notes, the Company will be required to make an offer to purchase the Notes at a redemption price of 101.000%, plus accrued and unpaid interest to the date of repurchase.

Subject to certain customary release provisions, the Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by the Company and substantially all of its current and future domestic restricted subsidiaries (as defined). They are also secured, subject to certain exceptions and permitted liens, on a first-priority basis by substantially all of the assets of the Company and the guarantors’ that do not secure the

F-22

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2012 Credit Facility (see below) on a first-priority basis. Subject to certain exceptions and permitted liens, the Notes are also secured on a second-priority basis by a lien on the assets securing the Company’s obligations under the 2012 Credit Facility on a first-priority basis.

The indenture governing the Notes contains restrictive covenants which, among other things, limit the ability (subject to exceptions) of the Company and its restricted subsidiaries (as defined) to (a) incur additional indebtedness or issue preferred equity; (b) pay dividends or distributions on or purchase the Company’s stock or the Company’s restricted subsidiaries’ stock; (c) make certain investments; (d) use assets as security in other transactions; (e) create guarantees of indebtedness by restricted subsidiaries; (f) enter into agreements that restrict dividends, distributions, or other payment by restricted subsidiaries; (g) sell certain assets or merge with or into other companies; and (h) enter into transactions with affiliates.

The Company and the guarantor subsidiaries entered into a registration rights agreement (the “Registration Rights Agreement”) in connection with the issuance and sale of the Notes. Pursuant to the Registration Rights Agreement, the Company and the guarantor subsidiaries agreed to file a registration statement with the Securities and Exchange Commission to register an exchange offer pursuant to which the Company will offer to exchange a like aggregate principal amount of senior notes identical in all material respects to the Notes, except for terms relating to transfer restrictions, for any or all of the outstanding Notes. Pursuant to the Registration Rights Agreement, the Company must use commercially reasonable efforts to cause the registration statement to become effective as soon as practicable and to complete the exchange offer no later than June 30, 2014. Should those events not occur within the specified time frame, the applicable interest rates on the Notes shall be increased by 0.25% per annum for the first 90 days following the occurrence of such failure. Such interest rate will increase by an additional 0.25% per annum thereafter at the end of each subsequent 90-day period up to a maximum aggregate increase of 1.0% per annum. Once any of the required events occurs, the interest rates will revert to the rate specified in the indenture governing the Notes.

2012 Credit Facility

Concurrently with the closing of the Notes offering on December 21, 2012, the Company entered into a new asset based revolving credit facility (the 2012 Credit Facility). The 2012 Credit Facility provides for a five-year $50,000 revolving credit facility that will expire on December 21, 2017. Borrowings under the 2012 Credit Facility may not exceed a borrowing base, as defined within the agreement. In addition, the 2012 Credit Facility includes a $10,000 letter of credit sub-facility and a $5,000 swingline loan sub-facility. As of December 31, 2012, there were no borrowings outstanding under the 2012 Credit Facility and the Company had $20,000 available for borrowing under the facility. The Company incurred $1,198 of deferred financing fees related to the 2012 Credit Facility that have been capitalized and are being amortized to interest expense over the life of the facility.

Interest and Fees

Borrowings under the 2012 Credit Facility bear interest, at the Company’s option, at a rate based on (i) LIBOR, plus a margin ranging from 3.5% to 4.0%, or (ii) a base rate, plus a margin ranging from 2.5% to 3.0%. Margins may be increased by 2.0% per annum during the existence of any event of default. The Company is also required to pay certain other fees with respect to the 2012 Credit Facility, including (i) an unused commitment fee ranging from 0.50% to 0.375% in respect of unutilized commitments, (ii) a fronting fee equal to 0.25% per annum of the amount of outstanding letters of credit and (iii) customary annual administration fees.

F-23

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Collateral and Guarantors

The 2012 Credit Facility is secured by substantially all of the Company’s and its subsidiaries’ assets (other than certain excluded assets), with (i) a first priority lien on the ABL Priority Collateral (as defined) and (ii) a second priority lien on the Notes Priority Collateral (as defined). The 2012 Credit Facility is also guaranteed on a full and unconditional basis by the same subsidiaries of the Company that guarantee the 2019 Notes.

Restrictive Covenants and Other Matters

The 2012 Credit Facility includes customary covenants that, subject to certain exceptions, restrict the Company’s ability and the ability of the Company’s subsidiaries to, among other things, incur indebtedness (including capital leases), create liens on assets, make investments, loans, guarantees, advances or acquisitions, pay dividends and distributions, liquidate, merge or consolidate, divest assets, engage in certain transactions with affiliates, create joint ventures or subsidiaries, change the nature of the Company’s business, change the Company’s fiscal year, issue stock, amend organizational documents, make capital expenditures and provide negative pledges on assets. In addition, at any time when (i) undrawn availability is less than the greater of (a) $10,000 or (b) an amount equal to 20% of the borrowing base or (ii) an event of default has occurred and is continuing, the Company will be required to maintain a fixed charge coverage ratio, calculated as of the end of each calendar month for the twelve months then ended, greater than 1.0 to 1.0.

The 2012 Credit Facility also contains customary affirmative covenants and events of default. If an event of default occurs, the lenders under the 2012 Credit Facility will be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.

Prepayments and Commitment Reductions

Voluntary prepayments and commitment reductions will be permitted, in whole or in part, in minimum amounts without premium or penalty, other than customary breakage costs with respect to LIBOR loans.

2011 Credit Facility

On February 9, 2011, the Company entered into a senior secured credit facility (the 2011 Credit Facility), which was comprised of a $100,000 term loan (2011 Credit Facility—Term Loan) and a $50,000 revolving credit facility (2011 Credit Facility—Revolving Credit Facility). The 2011 Credit Facility—Term Loan was a five-year term loan that required principal payments in the amount of $5,000 on the first day of each quarter commencing on January 1, 2012 through January 1, 2016, with the remaining outstanding principal and interest balance due upon maturity on February 9, 2016. On December 21, 2012, in connection with the Notes offering, the Company voluntarily prepaid and terminated the 2011 Credit Facility, and repaid all outstanding amounts under the agreement. As a result of the prepayment and termination of the 2011 Credit Facility, the Company recognized a loss on extinguishment of debt of $3,953 in connection with the write-off of related unamortized deferred financing costs. As of December 31, 2011, the Company had $10,000 available for borrowing under the 2011 Credit Facility.

Proceeds from the 2011 Credit Facility—Term Loan and borrowings under the 2011 Credit Facility—Revolving Credit Facility were used to repay the principal and interest balance of certain outstanding secured promissory notes during 2011. As a result of the repayment of these obligations, the Company recognized a gain on extinguishment of debt of $6,954 during the year ended December 31, 2011.

F-24

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The aggregate amounts of long-term debt maturities subsequent to December 31, 2012 were as follows:

2013	$	3,935
2014		2,874
2015		2,882
2016		978
2017		51
2018 and thereafter		200,024
Total	$	210,744

16. DERIVATIVES

In February 2011, in order to manage the risk associated with changes in interest rates related to the 2011 Credit Facility—Term Loan, the Company entered into an interest rate swap agreement that effectively converted a portion of its floating-rate debt to a fixed-rate basis, thereby reducing the impact of interest rate changes on future cash interest payments beginning January 1, 2012. The swap was designated as a cash flow hedge of expected future interest payments and measured at fair value on a recurring basis. In connection with the prepayment and termination of the 2011 Credit Facility, the Company terminated the outstanding interest rate swap in December 2012. Accordingly, the Company reclassified $1,409, net of tax of zero, from accumulated other comprehensive income (loss) and recognized a loss on settlement of the swap, which was included as a component of other income (expense), net in the consolidated statement of operations for the year ended December 31, 2012.

The Company utilizes the best available information in measuring fair value. The interest rate swap was historically valued based on quoted data from the counterparty, corroborated with indirectly observable market data, which, combined, were deemed to be a Level 2 input in the fair value hierarchy. At December 31, 2011, the Company recorded a liability of $1,862, in other non-current liabilities on the consolidated balance sheet for the fair value of the swap. The effective portion of the related loss on the swap of $1,862, net of tax of zero, was deferred in accumulated other comprehensive income (loss). No ineffectiveness was recorded in the consolidated statement of operations during the years ended December 31, 2012 and 2011, respectively. In addition, during the years ended December 31, 2012 and 2011, $811 and zero, respectively, were reclassified from accumulated other comprehensive income (loss) to interest expense related to the effective portion of the interest rate swap.

17. LEASE OBLIGATIONS

The Company leases equipment and facilities directly under various non-cancelable lease agreements. Certain leases contain renewal or purchase terms in the contract. Rental expense under operating leases was $17,671, $16,243, and $10,683 for the years ended December 31, 2012, 2011, and 2010, respectively.

F-25

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Future minimum lease payments under non-cancelable operating leases (with initial or remaining lease terms in excess of one year) and future minimum capital lease payments as of December 31, 2012, are:

	Capital Leases		Operating Leases
Year ending December 31:
2013	$	4,753	$	18,438
2014		3,317		15,428
2015		1,864		10,291
2016		548		2,617
2017 and thereafter		124		528
Total minimum lease payments		10,606	$	47,302
Less: amount representing interest		889
Present value of net minimum capital lease payments		9,717
Less: current installments of obligations under capital leases		4,243
Obligations under capital leases, excluding current installments	$	5,474

The net amount of leased assets capitalized on the balance sheet is as follows:

	December 31,
	2012			2011
Asset cost	$	26,037		$	26,037
Accumulated depreciation		(13,827	)		(10,413	)
Net	$	12,210		$	15,624

18. ROYALTIES

Royalty expense, inclusive of royalties owed to a related party, for the years ended December 31, 2012, 2011, and 2010, were $9,446, $7,409, and $5,372, respectively. For the years ended December 31, 2012 and 2011, the Company recorded $223 and $853, respectively, of advance royalty payments. These payments are recoupable against royalties generated from future mining activity. As of December 31, 2012 and 2011, advance royalties totaled $7,684 and $13,760, respectively, which includes $1,149 related to a leased reserve acquired in 2010 whereby the lease requires the Company to provide the owner with a certain amount of coal tonnage until production commences on the leased reserve. The Company valued this coal tonnage using the prevailing average market pricing and the advance royalty is recoupable against production royalties generated by future mining activity. The value and term of future advanced royalties under this arrangement are dependent on the market value of the coal and the date that operations commence on the property. For disclosure purposes, the Company has included an anticipated annual minimum advance royalty based on estimated market prices for similar coal through 2016, at which time the lessor can terminate the agreement if mining has not commenced.

As of December 31, 2012, the Company has a remaining advance royalty to ARP of $5,683, which is recoupable against future production royalties earned on certain wholly-owned reserves of ARP (see Note 13).

F-26

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Based upon current production plans, the Company estimates the remaining amount will be recouped against royalties due to ARP during 2013.

Anticipated future minimum advance royalties as of December 31, 2012, are payable as follows:

2013	$	1,556
2014		955
2015		917
2016		70
2017 and thereafter		210
Total	$	3,708

In addition to the above advanced royalties, production royalties are payable based on the quantity of coal mined in future years.

Various royalties and commissions have been negotiated with certain key executives of management, a former minority unitholder, and sales brokers. See Note 13 for the terms of royalties to employees.

19. ASSET RETIREMENT OBLIGATIONS AND RECLAMATION

Asset retirement obligation and reclamation balances consist of the following as of December 31, 2012 and 2011:

	2012			2011
Balance at beginning of year	$	18,952		$	14,707
Accretion expense		1,673			1,471
Liabilities settled (net)		(820	)		(52	)
Revisions to estimates		(1,320	)		2,826
Balance at end of year		18,485			18,952
Less: current obligation		523			1,821
Total obligation, less current portion	$	17,962		$	17,131

The credit-adjusted, risk-free rates used to discount the estimated liability were 9.7% and 8.7% in 2012 and 2011, respectively.

20. INCOME TAXES

The income (loss) before income taxes and non-controlling interest was ($18,039), $4,328, and $8,169, for the years ended December 31, 2012, 2011 and 2010, respectively.

F-27

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The components of the income tax provision are as follows:

	December 31,
	2012		2011		2010
Current:
Federal	$	—	$	455	$	—
State		—		401		—
		—		856		—
Deferred:
Federal		—		—		—
State		—		—		—
		—		—		—
Total	$	—	$	856	$	—

The income tax rate differed from the U.S. federal statutory rate as follows:

	December 31,
	2012			2011			2010
Tax expense (benefit) at federal statutory rates	$	(6,313	)	$	1,515		$	2,859
State income taxes		(460	)		(495	)		577
Nontaxable entities		—			(1,360	)		798
Other permanent items		99			134			102
Other		1,048			(1,602	)		2,074
Change in valuation allowance		5,626			2,664			(6,410	)
Total	$	—		$	856		$	—

F-28

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consist of the following:

	December 31,
	2012			2011
Deferred tax assets:
Tax loss and credit carryforwards	$	54,391		$	47,623
Long-term obligation to related party		38,248			27,612
Deferred organization costs and other intangibles		790			607
Vacation accrual		577			486
Stock-based compensation		758			1,032
Charitable contributions		190			156
Interest rate swaps		—			724
Asset retirement obligation		4,478			3,541
Total gross deferred tax assets		99,432			81,781
Deferred tax liabilities:
Property, plant, and equipment		(84,348	)		(71,619	)
Investments		(266	)		(247	)
Total gross deferred tax liabilities		(84,614	)		(71,866	)
Valuation allowance		(14,818	)		(9,915	)
Net deferred tax assets	$	—		$	—

Changes to the valuation allowance during the years ended December 31, 2012 and 2011, were as follows:

Valuation allowance at December 31, 2010	$	6,527
Increase in valuation allowance		3,388
Valuation allowance at December 31, 2011		9,915
Increase in valuation allowance		4,903
Valuation allowance at December 31, 2012	$	14,818

The Company’s net deferred tax assets are offset by a valuation allowance of $14,818 and $9,915 at December 31, 2012 and 2011, respectively. The Company evaluated and assessed the expected near-term utilization of net operating loss carryforwards, book and taxable income trends, available tax strategies, and the overall deferred tax position and believes that it is more likely than not that the benefit related to the deferred tax assets will not be realized and has thus established the valuation allowance required as of December 31, 2012 and 2011.

The Company’s net deferred tax assets included federal and state net operating loss (NOL) carryforwards of $142,567 and $104,738, respectively, as of December 31, 2012 and $124,353 and $94,682, respectively, as of December 31, 2011. The NOLs begin to expire in 2026. The Company’s net deferred taxes also include $407 of AMT credits as of December 31, 2012 and 2011. These AMT credits have no expiration date.

The Company’s federal income tax returns for the tax years from 2006 (inception) forward remain subject to examination by the Internal Revenue Service. The Company’s state income tax returns for the same period remain subject to examination by the various state taxing authorities.

F-29

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In 2011, the Company paid federal income taxes of $387 and state and local income taxes of $643. During 2012 and 2010 the Company made an immaterial amount of federal, state, and local income tax payments.

There were no uncertain tax positions as of December 31, 2012 or 2011, and the Company has not currently accrued interest or penalties. If the accrual of interest or penalties becomes appropriate, the Company will record an accrual as part of its income tax provision.

21. EMPLOYEE BENEFIT PLANS

Defined Contribution Plan

The Company offers a 401(k) savings plan for all employees, whereby the Company matches voluntary contributions up to specified levels. The costs included in the consolidated statements of operations totaled $2,720, $1,933, and $1,434 for the years ended December 31, 2012, 2011, and 2010, respectively.

Postretirement Medical Cost Reimbursement Plan

Beginning January 1, 2013, the Company will begin providing certain health care benefits, including the reimbursement of a portion of out-of-pocket costs associated with insurance coverage, to qualifying salaried and hourly retirees and their dependents. Plan coverage for reimbursements will be provided to future hourly and salaried retirees in accordance with the plan document. As of the effective date, the Company will recognize a liability totaling $907 associated with the benefits earned by qualified employees prior to January 1, 2013. The Company’s funding policy with respect to the plan will be to fund the cost of all postretirement benefits as they are paid.

22. EQUITY AWARDS

Redemption of Non-Recourse Promissory Notes

In previous years, the Chief Executive Officer, the President, and a former board member have purchased common stock in the Company, which have been paid with cash and non-recourse promissory notes. On September 30, 2011, the non-recourse promissory notes outstanding from the Chief Executive Officer and the President were repaid in full through the sale of 148,652 shares of common stock back to the Company by the borrowers. The common stock was repurchased at $18.27 per share, which is a premium from the estimated fair value on the date of acquisition of $12.00 per share. Because the Company’s common stock is not publicly traded, the fair market value was estimated based on multiple valuation methodologies utilizing both quantitative and qualitative factors. A market approach using the comparable company method and an income approach using the discounted cash flow method were used to determine a fair value per common share. As a result of the premium paid on the redemption of the shares, a non-cash charge of $933 was recognized in the results of operations as a component of selling, general, and administrative expense for year ended December 31, 2011 for the difference between the purchase price and the fair value.

The outstanding principal and interest associated with the non-recourse promissory note from the former board member was settled in full on November 1, 2011 with the payment of cash to the Company of $1,083. As of December 31, 2012, no executives or directors of the Company have non-recourse promissory notes outstanding.

Restricted Stock Awards

The primary stock-based compensation tool used by the Company for its employee base is through awards of restricted stock. The majority of restricted stock awards generally cliff vest after two to three years of service.

F-30

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The fair value of restricted stock is equal to the fair market value of our common stock at the date of grant and is amortized to expense ratably over the vesting period, net of forfeitures.

Information regarding restricted shares activity and weighted-average grant-date fair value follows for the year ended December 31, 2012:

	Restricted Shares
	Shares		Weighted- Average  Grant- Date Fair Value
Outstanding at January 1		109,150	$	12.79
Granted		18,500		12.11
Vested		—		—
Canceled		—		—
Outstanding at December 31		127,650		12.69

Unearned compensation of $504 will be recognized related to the outstanding restricted shares that are expected to vest. The expense is expected to be recognized over a weighted average period of 1.2 years. The Company recognized expense of approximately $697, $450, and $79 related to restricted shares for the years ended December 31, 2012, 2011, and 2010, respectively.

23. PREFERRED STOCK

On January 13, 2012, the Company sold 300,000 shares of newly-created Series A Convertible preferred stock to certain investment funds managed by Yorktown pursuant to a certificate of designation for net cash consideration totaling $30,000. The proceeds of the sale were used to repay a portion of the outstanding borrowings under the 2011 Credit Facility and for general corporate purposes. The preferred stockholders are not entitled to dividends. In addition, the shares of preferred stock convert into common stock of the Company at the consummation of an initial public offering (IPO). Upon the completion of an IPO, the preferred stock converts into common stock equal to $30,000 divided by the IPO Price, as defined. In December 2012, the Company entered into a Share Conversion Agreement with Yorktown, whereby all of the outstanding shares of Series A Convertible preferred stock converted into an aggregate of 2,775,000 shares of common stock of the Company. The fair value of the Company’s common stock on the date of conversion, based on a third-party valuation, was $12.11 per share.

24. COMMITMENTS AND CONTINGENCIES

The Company is subject to various market, operational, financial, regulatory, and legislative risks. Numerous federal, state, and local governmental permits and approvals are required for mining operations. Federal and state regulations require regular monitoring of mines and other facilities to document compliance. Monetary penalties of $976, $955, and $602 related to Mine Safety and Health Administration (MSHA) fines were accrued in the results of operations for the years ended December 31, 2012, 2011, and 2010, respectively.

On October 28, 2011, a portion of the highwall at the Company’s Equality Boot mine collapsed, fatally injuring two employees of a local blasting company. Following the accident, pursuant to Section 103(k) of the Mine Act, MSHA issued an order prohibiting all activity at the Equality Boot mine until it was determined to be

F-31

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

safe to resume normal mining operations. MSHA approved resuming mining of the uppermost coal seam on November 2, 2011. An addendum to the ground control plan was submitted to MSHA and approved on November 8, 2011, which allowed for mining of the lower seams to resume.

On February 7, 2012, the Kentucky Office of Mine Safety and Licensing issued its Fatal Accident Report. The Commonwealth of Kentucky concluded that the failure of the highwall occurred where the rock strata transitioned from wide bands of shale to smaller bands on laminated rock, thus creating a slicken slide fault in the area where the rock fell. The Kentucky Office of Mine Safety and Licensing did not find any causes or circumstances which contributed to the accident other than the aforementioned naturally occurring geological condition.

Finally, on May 7, 2012, MSHA issued its final Investigation Report concerning the accident. Similar to the findings of the Kentucky Office of Mine Safety and Licensing, MSHA concluded that the accident occurred because of a geologic anomaly located in the portion of the highwall below the #14 coal seam and above the #13 coal seam where there were two intersecting or nearly intersecting discontinuities in the rock formation. Although MSHA concluded that personnel at the Equality Boot mine had failed to recognize the anomaly and issued five Section 104(a) citations in connection with the accident, MSHA did not issue any citations finding high negligence or reckless disregard on the part of the Company or its employees. The Company does not believe the impact of this accident will have a material adverse effect on its consolidated cash flows, results of operations or financial condition.

Periodically, there may be various claims and legal proceedings against the Company arising from the normal course of business. The Company is also involved in litigation matters arising in the ordinary course of business. In the opinion of management, the resolution of these matters will not have a material adverse effect on the Company’s consolidated cash flows, results of operations or financial condition.

Coal Sales Contracts

The Company is committed under multi-year supply agreements to sell coal that meets certain quality requirements at specified prices. These contracts typically have specific and possibly different volume and pricing arrangements for each year of the agreement, which allows customers to secure a supply for their future needs and provides the Company with greater predictability of sales volume and sales prices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or the Company. The remaining terms of the Company’s long-term contracts range from one to six years. The Company, via contractual agreements, has committed volumes of sales in 2013 and 2014 of 8.7 million tons and 6.5 million tons, respectively.

Coal Transportation Agreements

In December 2007, the Company entered into a lease services agreement with a third party commencing January 2008 and expiring December 2015. The third party will provide all barge switching, coal loading, tug, hauling, and similar services necessary for the Company’s operations. During the term of the agreement, the Company will pay a monthly amount based on the annual volume of tons of coal loaded at the dock facility. The Company commenced activity under the lease in January 2009 and incurred $3,474, $2,583, and $835 of expense during the years ended December 31, 2012, 2011 and 2010, respectively.

F-32

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indenture governing the Notes, certain wholly-owned subsidiaries of the Company have fully and unconditionally guaranteed the Notes, on a joint and several basis, subject to certain customary release provisions. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the Notes. The following historical financial statement information is provided for the Guarantor Subsidiaries. The non-guarantor subsidiaries are considered to be “minor” as the term is defined in Rule 3-10 of Regulation S-X promulgated by the Securities and Exchange Commission and the financial position, results of operations, and cash flows are, therefore, included in the condensed financial data of the guarantor subsidiaries.

Supplemental Condensed Consolidating Balance Sheets

	December 31, 2012
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	75		$	60,057		$	—		$	60,132
Accounts receivable		—			24,138			—			24,138
Inventories		—			9,461			—			9,461
Prepaid and other assets		288			3,434			—			3,722
Deferred income taxes		984			—			—			984
Total current assets		1,347			97,090			—			98,437
Property, plant, equipment, and mine development, net		14,848			416,377			—			431,225
Investments		—			3,323			—			3,323
Investments in subsidiaries		195,625			—			(195,625	)		—
Intercompany receivables		154,132			(154,132	)		—			—
Intangible assets, net		—			573			—			573
Other non-current assets		10,821			15,930			—			26,751
Total assets	$	376,773		$	379,161		$	(195,625	)	$	560,309
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	63		$	26,839		$	—		$	26,902
Accrued liabilities and other		1,274			13,210			—			14,484
Current portion of capital lease obligations		—			4,243			—			4,243
Current maturities of long-term debt		—			3,935			—			3,935
Total current liabilities		1,337			48,227			—			49,564
Long-term debt, less current maturities		193,152			6,809			—			199,961
Long-term obligation to related party		—			98,388			—			98,388
Related party payables, net		(1,343	)		6,229			—			4,886
Asset retirement obligations		—			17,962			—			17,962
Long-term portion of capital lease obligations		—			5,474			—			5,474
Deferred income taxes		984			—			—			984
Other non-current liabilities		—			428			—			428
Total liabilities		194,130			183,517			—			377,647
Stockholders’ equity:
Armstrong Energy, Inc.’s equity		182,643			195,625			(195,625	)		182,643
Non-controlling interest		—			19			—			19
Total stockholders’ equity		182,643			195,644			(195,625	)		182,662
Total liabilities and stockholders’ equity	$	376,773		$	379,161		$	(195,625	)	$	560,309

F-33

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	December 31, 2011
	Parent / Issuer			Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	299		$	19,281	$	—		$	19,580
Accounts receivable		—			22,506		—			22,506
Inventories		—			11,409		—			11,409
Prepaid and other assets		1,185			3,075		—			4,260
Deferred income taxes		—			—		—			—
Total current assets		1,484			56,271		—			57,755
Property, plant, equipment, and mine development, net		4,209			413,394		—			417,603
Investments		—			3,178		—			3,178
Investments in subsidiaries		200,688			—		(200,688	)		—
Intercompany receivables		(38,670	)		38,670		—			—
Intangible assets, net		—			1,305		—			1,305
Other non-current assets		4,886			23,181		—			28,067
Total assets	$	172,597		$	535,999	$	(200,688	)	$	507,908
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	163		$	35,279	$	—		$	35,442
Accrued liabilities and other		2,400			12,238		—			14,638
Current portion of capital lease obligations		—			4,347		—			4,347
Current maturities of long-term debt		—			33,957		—			33,957
Total current liabilities		2,563			85,821		—			88,384
Long-term debt, less current maturities		—			125,752		—			125,752
Long-term obligation to related party		—			71,047		—			71,047
Related party payables, net		—			25,700		—			25,700
Asset retirement obligations		—			17,131		—			17,131
Long-term portion of capital lease obligations		—			9,707		—			9,707
Deferred income taxes		—			—		—			—
Other non-current liabilities		1,911			138		—			2,049
Total liabilities		4,474			335,296		—			339,770
Stockholders’ equity:
Armstrong Energy, Inc.’s equity		168,123			200,688		(200,688	)		168,123
Non-controlling interest		—			15		—			15
Total stockholders’ equity		168,123			200,703		(200,688	)		168,138
Total liabilities and stockholders’ equity	$	172,597		$	535,999	$	(200,688	)	$	507,908

F-34

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplement Condensed Consolidated Statements of Operations

	Year Ended December 31, 2012
	Parent / Issuer			Guarantor Subsidiaries			Eliminations		Consolidated
Revenue	$	—		$	382,109		$	—	$	382,109
Costs and Expenses:
Operating costs and expenses		—			282,569			—		282,569
Production royalty to related party		—			5,695			—		5,695
Depreciation, depletion, and amortization		937			32,129			—		33,066
Asset retirement obligation expenses		—			3,977			—		3,977
Selling, general and administrative costs		3,936			46,218			—		50,154
Operating income (loss)		(4,873	)		11,521			—		6,648
Other income (expense):
Interest income		—			68			—		68
Interest expense		(1,512	)		(17,756	)		—		(19,268	)
Other, net		(6,590	)		1,103			—		(5,487	)
Loss from investments in subsidiaries		(5,064	)		—			5,064		—
Loss before income taxes		(18,039	)		(5,064	)		5,064		(18,039	)
Income tax provision		—			—			—		—
Net loss		(18,039	)		(5,064	)		5,064		(18,039	)
Income attributable to non-controlling interests		—			—			—		—
Net loss attributable to common stockholders	$	(18,039	)	$	(5,064	)	$	5,064	$	(18,039	)

	Year Ended December 31, 2011
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	299,270		$	—		$	299,270
Costs and Expenses:
Operating costs and expenses		—			221,597			—			221,597
Production royalty to related party		—			578			—			578
Depreciation, depletion, and amortization		12			27,649			—			27,661
Asset retirement obligation expenses		—			4,005			—			4,005
Selling, general and administrative costs		4,566			32,928			—			37,494
Operating income (loss)		(4,578	)		12,513			—			7,935
Other income (expense):
Interest income		—			145			—			145
Interest expense		(1,457	)		(9,382	)		—			(10,839	)
Other, net		502			6,585			—			7,087
Income from investments in subsidiaries		1,557			—			(1,557	)		—
(Loss) income before income taxes		(3,976	)		9,861			(1,557	)		4,328
Income tax provision		—			(856	)		—			(856	)
Net (loss) income		(3,976	)		9,005			(1,557	)		3,472
Income attributable to non-controlling interests		—			(7,448	)		—			(7,448	)
Net (loss) income attributable to common stockholders	$	(3,976	)	$	1,557		$	(1,557	)	$	(3,976	)

F-35

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Year Ended December 31, 2010
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	220,625		$	—		$	220,625
Costs and Expenses:
Operating costs and expenses		—			151,838			—			151,838
Depreciation, depletion, and amortization		23			18,869			—			18,892
Asset retirement obligation expenses		—			3,087			—			3,087
Selling, general and administrative costs		2,025			25,631			—			27,656
Operating (loss) income		(2,048	)		21,200			—			19,152
Other income (expense):
Interest income		—			198			—			198
Interest expense		(6	)		(11,064	)		—			(11,070	)
Other, net		686			(797	)		—			(111	)
Income from investments in subsidiaries		6,186			—			(6,186	)		—
Income before income taxes		4,818			9,537			(6,186	)		8,169
Income tax provision		—			—			—			—
Net income		4,818			9,537			(6,186	)		8,169
Income attributable to non-controlling interests		—			(3,351	)		—			(3,351	)
Net income attributable to common stockholders	$	4,818		$	6,186		$	(6,186	)	$	4,818

Supplement Condensed Consolidating Statements of Comprehensive Income (Loss)

	Year Ended December 31, 2012
	Parent / Issuer			Guarantor Subsidiaries			Eliminations		Consolidated
Net loss	$	(18,039	)	$	(5,064	)	$	5,064	$	(18,039	)
Other comprehensive income (loss):
Unrealized loss on derivatives arising during the period, net of tax of zero		—			—			—		—
Less: Reclassification adjustments for loss on derivatives included in net loss, net of tax of zero		(1,862	)		—			—		(1,862	)
Other comprehensive income		1,862			—			—		1,862
Comprehensive loss		(16,177	)		(5,064	)		5,064		(16,177	)
Less: Comprehensive income (loss) attributable to non-controlling interests		—			—			—		—
Comprehensive loss attributable to common stockholders	$	(16,177	)	$	(5,064	)	$	5,064	$	(16,177	)

F-36

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Year Ended December 31, 2011
	Parent / Issuer			Guarantor Subsidiaries		Eliminations			Consolidated
Net (loss) income	$	(3,976	)	$	9,005	$	(1,557	)	$	3,472
Other comprehensive income (loss):
Unrealized loss on derivatives arising during the period, net of tax of zero		(1,862	)		—		—			(1,862	)
Less: Reclassification adjustments for loss on derivatives included in net loss, net of tax of zero		—			—		—			—
Other comprehensive loss		(1,862	)		—		—			(1,862	)
Comprehensive (loss) income		(5,838	)		9,005		(1,557	)		1,610
Less: Comprehensive loss attributable to non-controlling interests		—			7,448		—			7,448
Comprehensive (loss) income attributable to common stockholders	$	(5,838	)	$	1,557	$	(1,557	)	$	(5,838	)

	Year Ended December 31, 2010
	Parent / Issuer		Guarantor Subsidiaries		Eliminations			Consolidated
Net income	$	4,818	$	9,537	$	(6,186	)	$	8,169
Other comprehensive income (loss):
Unrealized loss on derivatives arising during the period, net of tax of zero		—		—		—			—
Less: Reclassification adjustments for loss on derivatives included in net loss, net of tax of zero		—		—		—			—
Other comprehensive income (loss)		—		—		—			—
Comprehensive income		4,818		9,537		(6,186	)		8,169
Less: Comprehensive loss attributable to non-controlling interests		—		3,351		—			3,351
Comprehensive income attributable to common stockholders	$	4,818	$	6,186	$	(6,186	)	$	4,818

F-37

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplemental Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2012
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(7,863	)	$	38,632		$	30,769
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development		(11,578	)		(34,886	)		(46,464	)
Investment in affiliate		—			(130	)		(130	)
Proceeds from sale of fixed assets		—			70			70
Net cash used in investing activities		(11,578	)		(34,946	)		(46,524	)
Cash Flows from Financing Activities:
Payment on capital lease obligations		—			(4,338	)		(4,338	)
Payment of long-term debt		—			(169,872	)		(169,872	)
Payment of financing costs and fees		(11,117	)		—			(11,117	)
Borrowings under revolver financing		—			18,500			18,500
Proceeds from the issuance of Series A convertible preferred stock		30,000			—			30,000
Proceeds from bond offering		193,134			—			193,134
Transactions with affiliates, net		(192,800	)		192,800			—
Net cash provided by financing activities		19,217			37,090			56,307
Net change in cash and cash equivalents		(224	)		40,776			40,552
Cash, at the beginning of the period		299			19,281			19,580
Cash, at the end of the period	$	75		$	60,057		$	60,132

F-38

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Year Ended December 31, 2011
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(2,077	)	$	50,251		$	48,174
Cash Flows from Investing Activities:
Cash decrease due to deconsolidation		—			(155	)		(155	)
Investment in property, plant, equipment, and mine development		(4,137	)		(69,490	)		(73,627	)
Investment in affiliate		—			(2,470	)		(2,470	)
Proceeds from sale of fixed assets		—			425			425
Net cash used in investing activities		(4,137	)		(71,690	)		(75,827	)
Cash Flows from Financing Activities:
Payment on capital lease obligations		—			(4,115	)		(4,115	)
Payment of long-term debt		—			(118,170	)		(118,170	)
Payment of financing costs and fees		(4,798	)		—			(4,798	)
Proceeds from long term debt		—			140,000			140,000
Proceeds from financing obligation with related party		—			20,000			20,000
Transactions with affiliates, net		11,284			(11,284	)		—
Proceeds from repayment of non-recourse notes		—			1,083			1,083
Proceeds from acquisition of non-controlling interest		—			132			132
Contributions of noncontrolling interest		—			5,000			5,000
Net cash provided by financing activities		6,486			32,646			39,132
Net change in cash and cash equivalents		272			11,207			11,479
Cash, at the beginning of the period		27			8,074			8,101
Cash, at the end of the period	$	299		$	19,281		$	19,580

F-39

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Year Ended December 31, 2010
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(856	)	$	38,050		$	37,194
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development		—			(41,755	)		(41,755	)
Net cash used in investing activities		—			(41,755	)		(41,755	)
Cash Flows from Financing Activities:
Payment on capital lease obligations		—			(3,692	)		(3,692	)
Payment of long-term debt		—			(33,343	)		(33,343	)
Transactions with affiliates, net		(2,497	)		2,497			—
Contributions of noncontrolling interest		—			33,100			33,100
Net cash used in financing activities		(2,497	)		(1,438	)		(3,935	)
Net change in cash and cash equivalents		(3,353	)		(5,143	)		(8,496	)
Cash, at the beginning of the period		3,380			13,217			16,597
Cash, at the end of the period	$	27		$	8,074		$	8,101

26. SUMMARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

A summary of the unaudited quarterly results of operations for the years ended December 31, 2012 and 2011 is presented below.

	2012
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter(1)
Revenue	$	94,073		$	99,099		$	94,678		$	94,259
Gross profit		25,065			30,314			23,060			21,101
Operating income (loss)		2,842			6,591			(534	)		(2,251	)
Net income (loss)		(1,169	)		1,945			(5,320	)		(13,495	)
Net income (loss) attributable to common stockholders		(1,169	)		1,945			(5,320	)		(13,495	)
	2011
	First Quarter(2)			Second Quarter			Third Quarter			Fourth Quarter(3)
Revenue	$	71,476		$	68,350		$	90,154		$	69,290
Gross profit		18,231			12,519			28,932			17,991
Operating income (loss)		1,630			(3,891	)		8,690			1,506
Net income (loss)		5,602			(5,555	)		6,418			(2,993	)
Net income (loss) attributable to common stockholders		3,371			(7,689	)		3,334			(2,993	)

1 Included within the fourth quarter of 2012 is a loss on extinguishment of debt of $3,953, a loss on settlement of the interest rate swap of $1,409, and a loss on deferment of an equity offering of $1,130.

2 Included within the first quarter of 2011 is a gain on extinguishment of debt of $6,954.

3 The deconsolidation of ARP was effective October 1, 2011, resulting in the recognition of a gain on deconsolidation of $311.

F-40

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	June 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	44,706		$	60,132
Accounts receivable		26,152			24,138
Inventories		12,544			9,461
Prepaid and other assets		2,922			3,722
Short-term note receivable from related party		17,500			—
Deferred income taxes		1,718			984
Total current assets		105,542			98,437
Property, plant, equipment, and mine development, net		437,866			431,225
Investments		3,339			3,323
Intangible assets, net		213			573
Other non-current assets		24,162			26,751
Total assets	$	571,122		$	560,309
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	38,695		$	26,902
Accrued liabilities and other		19,454			14,484
Current portion of capital lease obligations		3,919			4,243
Current maturities of long-term debt		4,354			3,935
Total current liabilities		66,422			49,564
Long-term debt, less current maturities		199,012			199,961
Long-term obligation to related party		104,882			98,388
Related party payables, net		3,095			4,886
Asset retirement obligations		18,847			17,962
Long-term portion of capital lease obligations		3,753			5,474
Deferred income taxes		1,718			984
Other non-current liabilities		2,324			428
Total liabilities		400,053			377,647
Stockholders’ equity:
Common stock, $0.01 par value, 70,000,000 shares authorized, 21,944,765 and 21,870,765 shares issued and outstanding as of June 30, 2013 and December 31, 2012, respectively		219			219
Preferred stock, $0.01 par value, 1,000,000 shares authorized, zero shares issued and outstanding as of June 30, 2013 and December 31, 2012, respectively		—			—
Additional paid-in-capital		239,003			238,713
Accumulated deficit		(67,318	)		(56,289	)
Accumulated other comprehensive loss		(858	)		—
Armstrong Energy, Inc.’s equity		171,046			182,643
Non-controlling interest		23			19
Total stockholders’ equity		171,069			182,662
Total liabilities and stockholders’ equity	$	571,122		$	560,309

See accompanying notes to unaudited condensed consolidated financial statements.

F-41

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenue	$	101,244		$	99,100		$	202,466		$	193,173
Costs and Expenses:
Cost of coal sales		71,994			68,785			146,606			137,794
Production royalty to related party		1,967			1,405			4,017			2,363
Depreciation, depletion, and amortization		8,969			8,480			17,765			16,119
Asset retirement obligation expenses		592			1,036			1,165			2,140
Selling, general and administrative costs		13,730			12,803			26,975			25,324
Operating income		3,992			6,591			5,938			9,433
Other income (expense):
Interest income		15			14			30			34
Interest expense		(8,674	)		(4,866	)		(17,242	)		(9,050	)
Other, net		134			206			245			359
(Loss) Income before income taxes		(4,533	)		1,945			(11,029	)		776
Income tax provision		—			—			—			—
Net (loss) income		(4,533	)		1,945			(11,029	)		776
Income attributable to non-controlling interests		—			—			—			—
Net (loss) income attributable to common stockholders	$	(4,533	)	$	1,945		$	(11,029	)	$	776

See accompanying notes to unaudited condensed consolidated financial statements.

F-42

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Net (loss) income	$	(4,533	)	$	1,945		$	(11,029	)	$	776
Other comprehensive income (loss):
Postretirement benefit plan		24			—			(858	)		—
Unrealized loss on derivatives arising during the period, net of tax of zero		—			(129	)		—			(232	)
Less: Reclassification adjustments for loss on derivatives included in net loss, net of tax of zero		—			(215	)		—			(444	)
Other comprehensive income (loss)		24			86			(858	)		212
Comprehensive (loss) income		(4,509	)		2,031			(11,887	)		988
Less: Comprehensive income (loss) attributable to non-controlling interests		—			—			—			—
Comprehensive (loss) income attributable to common stockholders	$	(4,509	)	$	2,031		$	(11,887	)	$	988

See accompanying notes to unaudited condensed consolidated financial statements.

F-43

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

Six Months Ended June 30, 2013

(Amounts in thousands)

	Common Stock				Preferred Stock				Additional Paid- in-Capital					Accumulated Other Comprehensive Loss					Total Stockholders’ Equity
	Number of Shares		Amount		Number of Shares		Amount				Accumulated Deficit						Non-Controlling Interest
Balance at December 31, 2012		21,871	$	219		—	$	—	$	238,713	$	(56,289	)	$	—		$	19	$	182,662
Net loss		—				—		—		—		(11,029	)		—			—		(11,029	)
Stock based compensation		—		—		—		—		290		—			—			—		290
Postretirement benefit plan		—		—		—		—		—		—			858			—		858
Contribution of non-controlling interest		—		—		—		—		—		—			—			4		4
Shares issued under employee plan		74		—		—		—		—		—			—			—		—
Balance at June 30, 2013		21,945	$	219		—	$	—	$	239,003	$	(67,318	)	$	(858	)	$	23	$	171,069

See accompanying notes to unaudited condensed consolidated financial statements.

F-44

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	Six Months Ended June 30,
	2013			2012
Cash Flows from Operating Activities:
Net (loss) income	$	(11,029	)	$	776
Adjustments to reconcile net income to cash provided by operating activities:
Non-cash stock compensation expense		290			350
Income from equity affiliate		(16	)		(3	)
Gain on settlement of asset retirement obligation		(90	)		—
Gain on disposal of property, plant and equipment		(30	)		—
Amortization of original issue discount		322			558
Amortization of debt issuance costs		559			—
Depreciation, depletion and amortization		17,765			16,119
Asset retirement obligation expenses		1,165			2,140
Interest on long-term obligations		317			32
Change in operating assets and liabilities:
Increase in accounts receivable		(2,014	)		(3,770	)
Increase in inventories		(3,082	)		(139	)
Increase (decrease) in prepaid and other assets		800			(230	)
Decrease in other non-current assets		2,058			4,164
Increase (decrease) in accounts payable and accrued liabilities		16,511			(1,115	)
Increase in other non-current liabilities		5,764			1,842
Net cash provided by operating activities:		29,290			20,724
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development		(23,372	)		(29,778	)
Investment in affiliate		—			(130	)
Advance to related party		(17,500	)		—
Proceeds from disposal of fixed assets		255			—
Net cash used in investing activities		(40,617	)		(29,908	)
Cash Flows from Financing Activities:
Payment on capital lease obligations		(2,044	)		(2,161	)
Payment of long-term debt		(2,030	)		(34,765	)
Payment of financing costs and fees		(29	)		(743	)
Proceeds from the issuance of Series A convertible preferred stock		—			30,000
Contributions of non-controlling interest		4			—
Net cash used in financing activities		(4,099	)		(7,669	)
Net change in cash and cash equivalents		(15,426	)		(16,853	)
Cash, at the beginning of the period		60,132			19,580
Cash, at the end of the period	$	44,706		$	2,727
	Six Months Ended June 30,
	2013			2012
Supplemental cash flow information:
Non-Cash Transactions:
Investment in property, plant, equipment, and mine development acquired with debt	$	1,180		$	1,361

See accompanying notes to unaudited condensed consolidated financial statements.

F-45

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share amounts)

1. DESCRIPTION OF BUSINESS AND ENTITY STRUCTURE

The accompanying unaudited condensed consolidated financial statements include the accounts of Armstrong Energy, Inc. (formerly Armstrong Land Company, LLC) and its subsidiaries and controlled entities (collectively, the Company or AE). The Company’s primary business is the production of thermal coal from surface and underground mines located in western Kentucky, for sale to utility, industrial and export markets. Intercompany transactions and accounts have been eliminated in consolidation.

The Company’s wholly-owned subsidiary, Elk Creek GP, LLC (ECGP), has an approximate 0.4% ownership in Armstrong Resource Partners, L.P. (ARP). The various limited partners of ARP are related parties, as the entity is majority owned by investment funds managed by Yorktown Partners LLC (Yorktown), which has a majority ownership in the Company. The Company does not consolidate the financial results of ARP and accounts for its ownership in ARP under the equity method.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting and U.S. Securities and Exchange Commission regulations. In the opinion of management, all adjustments, consisting of normal, recurring accruals considered necessary for a fair presentation, have been included. Balance sheet information presented herein as of December 31, 2012 has been derived from the Company’s audited consolidated balance sheet at that date. Results of operations for the three and six months ended June 30, 2013 are not necessarily indicative of results to be expected for the year ending December 31, 2013. These financial statements should be read in conjunction with the audited financial statements and related notes as of and for the year ended December 31, 2012.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Benefit Plans

Effective January 1, 2013, the Company began providing certain health care benefits, including the reimbursement of a portion of out-of-pocket costs associated with insurance coverage, to qualifying salaried and hourly retirees and their dependents. The cost of providing these benefits is determined on an actuarial basis and accrued over the employee’s period of active service.

The Company recognizes the underfunded status of this plan, as determined on an actuarial basis, on the balance sheet and the changes in the funded status are recognized in other comprehensive (loss) income. See Note 12 for additional disclosures relating to these obligations.

Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation.

Newly Adopted Accounting Standards

In February 2013, the Financial Accounting Standards Board issued an amendment to the accounting guidance for the reporting of amounts reclassified out of accumulated other comprehensive income (AOCI). The amendment expands the existing disclosure by requiring entities to present information about significant items reclassified out of AOCI by component. In addition, an entity is required to provide information about the effects on net income (loss) of significant amounts reclassified out of each component of AOCI to net income (loss) either on the face of the statement where net income (loss) is presented or as a separate disclosure in the notes of

F-46

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

the financial statements. The amendment is effective prospectively for annual or interim reporting periods beginning after December 15, 2012. The adoption of this accounting pronouncement did not have a material impact on our financial statement disclosures. See Note 14 for additional information regarding AOCI.

3. INVENTORIES

Inventories consist of the following amounts:

	June 30, 2013		December 31, 2012
Materials and supplies	$	10,234	$	8,547
Coal—raw and saleable		2,310		914
Total	$	12,544	$	9,461

4. ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following amounts:

	June 30, 2013		December 31, 2012
Payroll and related benefits	$	8,355	$	6,494
Taxes other than income taxes		5,771		4,215
Interest		1,024		708
Asset retirement obligations		385		523
Royalties		1,506		1,171
Other		2,413		1,373
Total	$	19,454	$	14,484

5. INVESTMENTS

Survant Mining Company, LLC

On December 29, 2011, the Company formed a joint venture, Survant Mining Company, LLC (Survant), relating to coal reserves near its Parkway mine with a subsidiary of Peabody Energy, Inc. (Peabody). In connection with the joint venture, Peabody agreed to contribute an aggregate of approximately 25 million tons of recoverable coal reserves located in Muhlenberg County, Kentucky, and the Company agreed to contribute certain mining assets to the joint venture. The Company and Peabody also agreed to contribute 51% and 49%, respectively, of the cash sufficient to complete the development of the mine and sufficient for down payments on mining equipment. During 2012, Peabody and the Company each contributed $130 to Survant. The Company has applied the equity method to account for its investment in Survant, as it had the ability to exercise significant influence over the operating and financial policies of the joint venture. In July 2013, the Company and Peabody terminated the joint venture. Concurrent with the termination, the Company agreed to lease from Peabody the coal reserves that Peabody was to contribute to the joint venture.

Ram Terminals, LLC

On June 1, 2011, the Company entered into an agreement to acquire an equity interest in Ram Terminals, LLC (RAM) for $2,470. RAM, whose controlling unitholder is Yorktown, owns approximately 600 acres of

F-47

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Mississippi River front property south of New Orleans and intends to permit, design and construct a seaborne coal export terminal. The Company has the option to make additional contributions to RAM, but it is expected all future expenditures will be funded by Yorktown and its affiliates and therefore the Company’s equity interest will be significantly reduced in the future. As of June 30, 2013, the Company had an equity interest in RAM of approximately 5.0%. Effective January 1, 2012, the Company and RAM entered into a services agreement, whereby the Company will provide administrative and management services to RAM. In consideration for the services provided, RAM paid the Company an immaterial amount for the three and six months ended June 30, 2013 and 2012, respectively. Because of the Company’s limited influence over the investment and future dilution of ownership interest, the cost method is used to account for this investment. It is not practicable to estimate the fair value of this investment.

6. OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following amounts:

	June 30, 2013		December 31, 2012
Escrows and deposits	$	5,721	$	4,675
Restricted surety and cash bonds		4,571		4,306
Advanced royalties		4,314		7,684
Deferred financing costs, net		9,556		10,086
Total	$	24,162	$	26,751

7. RELATED-PARTY TRANSACTIONS

Sale of Coal Reserves

In February 2011, ARP exercised an option to acquire an undivided interest in certain of the land and mineral reserves of the Company in exchange for $5,000 and satisfaction of certain amounts owed to ARP by the Company. ARP acquired a 39.45% undivided interest as a joint tenant in common with the Company in certain of its land and mineral reserves for aggregate consideration totaling approximately $69,491. In addition, the Company entered into lease agreements with ARP pursuant to which ARP granted the Company leases to its 39.45% undivided interest in the mining properties described above, and licenses to mine and sell coal from those properties. The initial term of each such agreement is ten years, and will automatically extend for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or such agreement is terminated. Due to the Company’s continuing involvement in the land and mineral reserves transferred, this transaction has been accounted for as a financing arrangement. A long-term obligation has been established that is being amortized over the anticipated life of the mineral reserves, at an annual rate of 7% of the estimated gross revenue generated from the sale of the coal originating from the leased mineral reserves. Based on the mine plan in effect at the time, the effective interest rate of the obligation was 12.5%. In addition, the Company has agreed to indemnify ARP from and against any and all claims, damages, demands, expenses, fines, liabilities, taxes and any other losses related in any way to the Company’s mining operations on such premises, and to reclaim the surface lands on such premises in accordance with applicable federal, state and local laws.

In addition, the Company entered into a series of lease agreements with certain subsidiaries of ARP, pursuant to which ARP granted the Company a lease to its wholly-owned reserves (Elk Creek Reserves), and licenses to mine coal on that property. The initial term of the agreements is ten years, and they renew for

F-48

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. The Company must pay ARP a production royalty equal to 7% of the sales price of the coal it mines from the properties. The Company paid $12,000 of advance royalties under the lease of the Elk Creek Reserves, which are recoupable against production royalties. Mining of the Elk Creek Reserves began in 2011 and production royalties earned by ARP for the three months ended June 30, 2013 and 2012 were $1,967 and $1,405, respectively, and $4,017 and $2,363 for the six months ended June 30, 2013 and 2012, respectively. As of June 30, 2013 and December 31, 2012, the remaining balance of the advance royalties to be recouped against future production royalties was $1,666 and $5,683, respectively.

Effective February 9, 2011, the Company entered into a Royalty Deferment and Option Agreement with certain subsidiaries of ARP, pursuant to which ARP agreed to grant the Company the option to defer payment of their pro rata share of the 7% production royalty earned on the 39.45% undivided interest in mineral reserves acquired. In consideration for the granting of the option to defer these payments, the Company granted to ARP the option to acquire an additional undivided interest in certain of its coal reserves in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which the Company would satisfy payment of any deferred fees by selling part of its interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.

On December 29, 2011, the Company entered into a Membership Interest Purchase Agreement with ARP pursuant to which the Company agreed to sell to ARP, indirectly through contribution of a partial undivided interest in certain land and mineral reserves to a limited liability company and transfer of the Company’s membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by the Company. In exchange for the Company’s agreement to sell a partial undivided interest in those reserves, ARP paid the Company $20,000. In addition to the cash paid, certain amounts due ARP totaling $5,700 were forgiven, which resulted in aggregate consideration of $25,700. This transaction closed on March 30, 2012, whereby the Company transferred an 11.36% undivided interest in certain of its land and mineral reserves to ARP. The newly transferred mineral reserves were leased back to the Company under the agreement entered into in February 2011 at the same terms. In addition, production royalties earned by ARP from the newly transferred mineral reserves are being deferred under the Royalty Deferment and Option Agreement. Due to the Company’s continuing involvement in the mineral reserves, this transaction is accounted for as an additional financing arrangement and an additional long-term obligation to ARP of $25,700 was recognized on March 30, 2012, the date of closing the transaction. The effective interest of the obligation was adjusted to reflect the reserve transfer and the then current mine plan and reduced to 10.67%. The cash proceeds from ARP were used to acquire additional land and mineral reserves from a third party in December 2011, as well as for other working capital needs.

On March 21, 2013, the Company agreed to sell an additional 2.59% undivided interest in certain land and mineral reserves to ARP. The percentage interest in the land and mineral reserves sold was based on a fair value determined by a third-party specialist. In exchange for the undivided interest in the land and mineral reserves, ARP forgave amounts owed by the Company totaling $4,886. This transaction closed on April 1, 2013 whereby ARP’s undivided interest in certain of the Company’s land and mineral reserves in Muhlenberg and Ohio Counties increased to 53.4%. In addition, the transferred mineral reserves were leased back to the Company on terms similar to those applicable to the previous transfers. As the Company will have a continuing involvement in the reserves, the transaction is accounted for as a financing arrangement and an additional long-term obligation to ARP of $4,886 was recognized in the second quarter of 2013. As a result of the additional asset transfer, the effective interest rate on the long-term obligation to ARP was adjusted to 10.65%. As of June 30, 2013 and December 31, 2012, the outstanding long-term obligation to ARP totaled $104,882 and $98,388, respectively.

F-49

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Interest expense recognized for the three months ended June 30, 2013 and 2012 associated with the long-term obligation to ARP was $2,773 and $2,408, respectively, and for the six months ended June 30, 2013 and 2012 was $5,370 and $4,348, respectively.

Administrative Services Agreement

Effective as of January 1, 2011, the Company entered into an Administrative Services Agreement with ARP and its general partner, ECGP, pursuant to which the Company agreed to provide ARP 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 the Company’s employees and services, and for certain shared fixed costs, ARP paid the Company $193 and $188 for the three months ended June 30, 2013 and 2012, respectively, and $387 and $375 for the six months ended June 30, 2013 and 2012, respectively.

Credit Support Fee

ARP was a co-borrower under the Company’s previous senior secured term loan and guarantor on both the previous senior secured term loan and previous senior secured revolving credit facility (collectively, the Senior Secured Credit Facility), and substantially all of its assets were pledged as collateral. ARP received, as compensation for these restrictions, a fee of 1% of the weighted-average outstanding balance under the previous Senior Secured Credit Facility, which totaled $344 and $601 for the three and six months ended June 30, 2012, respectively. This arrangement ended in December 2012 upon the termination of the Senior Secured Credit Facility.

Short-term Note Receivable

On June 28, 2013, Thoroughbred Resources, LLC (Thoroughbred), an entity wholly-owned by investment funds managed by Yorktown, acquired approximately 65 million tons of fee-owned underground coal reserves and approximately 40 million tons of leased underground coal reserves from Peabody. The acquired coal reserves are located in Muhlenberg and McLean Counties of Kentucky, contiguous to the Company’s reserves. It is anticipated that these reserves will be leased to the Company in exchange for a production royalty.

In connection with Thoroughbred’s acquisition of these coal reserves, the Company loaned Thoroughbred $17,500, which was repaid in July 2013. The proceeds of the loan, which was evidenced by a promissory note, were used to make a portion of the down payment to Peabody for the purchase of the coal reserves.

Other

In 2006 and 2007, the Company entered into overriding royalty agreements with two key executive employees to compensate them $0.05/ton of coal mined and sold from properties owned by certain subsidiaries of the Company. The agreements remain in effect for the later of 20 years from the date of the agreement or until all salable coal has been extracted. Both royalty agreements transfer with the property regardless of ownership or lease status. The royalties are payable the month following the sale of coal mined from the specified properties. The Company accounts for these royalty arrangements as expense in the period in which the coal is sold. Expense recorded in the three months ended June 30, 2013 and 2012 was $238 and $224, respectively, and $464 and $435 in the six months ended June 30, 2013 and 2012, respectively.

F-50

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. LONG-TERM DEBT

The Company’s total indebtedness consisted of the following:

Type	June 30, 2013		December 31, 2012
11.75% Senior Secured Notes due 2019	$	193,473	$	193,152
2012 Credit Facility		—		—
Other		9,893		10,744
		203,366		203,896
Less: current maturities		4,354		3,935
Total long-term debt	$	199,012	$	199,961

Senior Secured Notes due 2019

On December 21, 2012, the Company completed a $200,000 offering of 11.75% Senior Secured Notes due 2019 (the Notes). The Notes were issued at an original issue discount (OID) of 96.567%. The OID was recorded on the Company’s balance sheet as a component of long-term debt, and is being amortized to interest expense over the life of the Notes. As of June 30, 2013 and December 31, 2012, the unamortized OID was $6,527 and $6,848, respectively. Interest on the Notes is due semiannually on June 15 and December 15 of each year, with the first payment being made on June 15, 2013. The Company used $123,698 of the proceeds from this issuance to prepay and terminate its previous Senior Secured Credit Facility, including accrued and unpaid interest. In addition, the Company used the proceeds to pay fees and expenses of $8,358 related to this transaction. A loss on extinguishment of debt of $3,953 was recorded in the fourth quarter of 2012 in connection with the write-off of unamortized deferred financing fees related to the previous Senior Secured Credit Facility.

2012 Credit Facility

Concurrently with the closing of the Notes offering on December 21, 2012, the Company entered into a new asset based revolving credit facility (the 2012 Credit Facility). The 2012 Credit Facility provides for a five-year $50,000 revolving credit facility that will expire on December 21, 2017. Borrowings under the 2012 Credit Facility may not exceed a borrowing base, as defined within the agreement. In addition, the 2012 Credit Facility includes a $10,000 letter of credit sub-facility and a $5,000 swingline loan sub-facility. As of June 30, 2013 and December 31, 2012, there were no borrowings outstanding under the 2012 Credit Facility and the Company had $19,653 available for borrowing under the facility. The Company incurred $1,198 of deferred financing fees related to the 2012 Credit Facility that have been capitalized and are being amortized to interest expense over the life of the facility.

9. FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures the fair value of assets and liabilities using a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: Level 1—observable inputs such as quoted prices in active markets; Level 2—inputs, other than quoted market prices in active markets, which are observable, either directly or indirectly; and Level 3—valuations derived from valuation techniques in which one or more significant inputs are unobservable. In addition, the Company may use various valuation techniques including the market approach, using comparable market prices; the income approach, using present value of future income or cash flow; and the cost approach, using the replacement cost of assets.

F-51

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company’s financial instruments consist of cash equivalents, accounts receivable, long-term debt, and other long-term obligations. For cash equivalents, accounts receivable and other long-term obligations, the carrying amounts approximate fair value due to the short maturity and financial nature of the balances. The estimated fair market values of the Company’s Notes, which was determined using level 2 inputs, and long-term obligation to related party, which was determined using level 3 inputs, are as follows:

	June 30, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
11.75% Senior Secured Notes due 20191	$	190,000	$	193,473	$	191,500	$	193,152
Long-term obligation to related party		107,692		104,882		103,506		98,388
Total	$	297,692	$	298,355	$	295,006	$	291,540

1 The carrying value of the Notes is net of the unamortized OID as of June 30, 2013 and December 31, 2012, respectively.

The fair value of the Notes is based on quoted market prices, while the fair value of the long-term obligation to related party was based on estimated cash flows discounted to their present value.

10. DERIVATIVES

In February 2011, in order to manage the risk associated with changes in interest rates related to the previous senior secured term loan, the Company entered into an interest rate swap agreement that effectively converted a portion of its floating-rate debt to a fixed-rate basis, thereby reducing the impact of interest rate changes on future cash interest payments beginning January 1, 2012. The swap was designated as a cash flow hedge of expected future interest payments and measured at fair value on a recurring basis. In connection with the prepayment and termination of the Senior Secured Credit Facility, the Company terminated the outstanding interest rate swap in December 2012. Accordingly, the Company reclassified $1,409, net of tax of zero, from accumulated other comprehensive income (loss) and recognized a loss on settlement of the interest rate swap in the fourth quarter of 2012. No ineffectiveness was recorded in the consolidated statement of operations during the three and six months ended June 30, 2012. In addition, during the three and six months ended June 30, 2012, $215 and $444, respectively, was reclassified from accumulated other comprehensive income (loss) to interest expense related to the effective portion of the interest rate swap.

11. INCOME TAXES

The Company has not recognized certain income tax benefits as it does not believe it is more likely than not it will be able to realize its net deferred tax assets. The Company has therefore established a valuation allowance against its net deferred tax assets as of June 30, 2013 and December 31, 2012.

12. EMPLOYEE BENEFIT PLANS

Effective January 1, 2013, the Company began providing certain health care benefits, including the reimbursement of a portion of out-of-pocket costs associated with insurance coverage, to qualifying salaried and hourly retirees and their dependents. Plan coverage for reimbursements will be provided to future hourly and salaried retirees in accordance with the plan document. As of the effective date, the Company recognized a

F-52

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

liability totaling $907 associated with the benefits earned by qualified employees prior to January 1, 2013. The Company’s funding policy with respect to the plan is to fund the cost of all postretirement benefits as they are paid.

Net periodic postretirement benefit cost included the following components:

	Three Months Ended June 30, 2013		Six Months Ended June 30, 2013
Service cost for benefits earned	$	282	$	564
Interest cost on accumulated postretirement benefit obligation		9		18
Amortization of prior service cost		24		49
Net periodic postretirement cost	$	315	$	631

13. PREFERRED STOCK

On January 13, 2012, the Company sold 300,000 shares of newly-created Series A Convertible preferred stock to certain investment funds managed by Yorktown pursuant to a certificate of designation for net cash consideration totaling $30,000. The proceeds of the sale were used to repay a portion of the outstanding borrowings under the Senior Secured Credit Facility and for general corporate purposes. In December 2012, the Company entered into a Share Conversion Agreement with Yorktown, whereby all of the outstanding shares of Series A Convertible preferred stock converted into an aggregate of 2,775,000 shares of common stock of the Company. The fair value of the Company’s common stock on the date of conversion, based on a third-party valuation, was $12.11 per share.

14. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive income (loss), net of tax, for the six months ended June 30, 2013 consisted of the following:

	Postretirement Benefit Plan
Balance as of December 31, 2012	$	—
Other comprehensive loss before reclassifications		(907	)
Amounts reclassified from accumulated other comprehensive income (loss)		49
Net current-period other comprehensive loss		(858	)
Balance as of June 30, 2013	$	(858	)

F-53

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following is a summary of reclassifications out of accumulated other comprehensive income for the three and six months ended June 30, 2013 and 2012:

Details about Accumulated Other Comprehensive Income (Loss) Components	Affected Line Item in  the Statement Where Net Income (Loss) Is Presented	Amounts Reclassified  from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30,
		2013			2012
Loss on cash flow hedge
—Interest rate swap	Interest expense	$	—		$	(215	)
Amortization of postretirement benefit plan items
—Prior service cost	(a)		(24	)		—
			(24	)		(215	)
Income taxes			—			—
Total reclassifications		$	(24	)	$	(215	)
Details about Accumulated Other Comprehensive Income (Loss) Components	Affected Line Item in  the Statement Where Net Income (Loss) Is Presented	Amounts Reclassified  from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30,
		2013			2012
Loss on cash flow hedge
—Interest rate swap	Interest expense	$	—		$	(444	)
Amortization of postretirement benefit plan items
—Prior service cost	(a)		(49	)		—
			(49	)		(444	)
Income taxes			—			—
Total reclassifications		$	(49	)	$	(444	)

(a) This component of accumulated other comprehensive income (loss) is included in the computation of net period postretirement cost. See Note 12.

15. COMMITMENTS AND CONTINGENCIES

The Company is subject to various market, operational, financial, regulatory, and legislative risks. Numerous federal, state, and local governmental permits and approvals are required for mining operations. Federal and state regulations require regular monitoring of mines and other facilities to document compliance. Monetary penalties of $1,246 and $976 related to Mine Safety and Health Administration (MSHA) fines were accrued as of June 30, 2013 and December 31, 2012, respectively.

Periodically, there may be various claims and legal proceedings against the Company arising from the normal course of business. The Company is also involved in litigation matters arising in the ordinary course of

F-54

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

business. In the opinion of management, the resolution of these matters will not have a material adverse effect on the Company’s consolidated cash flows, results of operations or financial condition.

Coal Sales Contracts

The Company is committed under multi-year supply agreements to sell coal that meets certain quality requirements at specified prices. These contracts typically have specific and possibly different volume and pricing arrangements for each year of the agreement, which allows customers to secure a supply for their future needs and provides the Company with greater predictability of sales volume and sales prices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or the Company. The remaining terms of the Company’s multi-year coal supply agreements range from one to six years.

16. Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the Notes, certain wholly-owned subsidiaries of the Company have fully and unconditionally guaranteed the Notes, on a joint and several basis, subject to certain customary release provisions. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the Notes. The following historical financial statement information is provided for the Guarantor Subsidiaries. The non-guarantor subsidiaries are considered to be “minor” as the term is defined in Rule 3-10 of Regulation S-X promulgated by the Securities and Exchange Commission and the financial position, results of operations, and cash flows are, therefore, included in the condensed financial data of the guarantor subsidiaries.

F-55

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplemental Condensed Consolidating Balance Sheets

	June 30, 2013
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	44,706		$	—		$	44,706
Accounts receivable		—			26,152			—			26,152
Inventories		—			12,544			—			12,544
Prepaid and other assets		156			2,766			—			2,922
Short-term note receivable from related party		—			17,500			—			17,500
Deferred income taxes		1,718			—			—			1,718
Total current assets		1,874			103,668			—			105,542
Property, plant, equipment, and mine development, net		15,386			422,480			—			437,866
Investments		—			3,339			—			3,339
Investments in subsidiaries		199,180			—			(199,180	)		—
Intercompany receivables		141,179			(141,179	)		—			—
Intangible assets, net		—			213			—			213
Other non-current assets		10,291			13,871			—			24,162
Total assets	$	367,910		$	402,392		$	(199,180	)	$	571,122
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	100		$	38,595		$	—		$	38,695
Accrued liabilities and other		3,321			16,133			—			19,454
Current portion of capital lease obligations		—			3,919			—			3,919
Current maturities of long-term debt		—			4,354			—			4,354
Total current liabilities		3,421			63,001			—			66,422
Long-term debt, less current maturities		193,473			5,539			—			199,012
Long-term obligation to related party		—			104,882			—			104,882
Related party payables, net		(1,748	)		4,843			—			3,095
Asset retirement obligations		—			18,847			—			18,847
Long-term portion of capital lease obligations		—			3,753			—			3,753
Deferred income taxes		1,718			—			—			1,718
Other non-current liabilities		—			2,324			—			2,324
Total liabilities		196,864			203,189			—			400,053
Stockholders’ equity:
Armstrong Energy, Inc.’s equity		171,046			199,180			(199,180	)		171,046
Non-controlling interest		—			23			—			23
Total stockholders’ equity		171,046			199,203			(199,180	)		171,069
Total liabilities and stockholders’ equity	$	367,910		$	402,392		$	(199,180	)	$	571,122

F-56

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	December 31, 2012
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	75		$	60,057		$	—		$	60,132
Accounts receivable		—			24,138			—			24,138
Inventories		—			9,461			—			9,461
Prepaid and other assets		288			3,434			—			3,722
Deferred income taxes		984			—			—			984
Total current assets		1,347			97,090			—			98,437
Property, plant, equipment, and mine development, net		14,848			416,377			—			431,225
Investments		—			3,323			—			3,323
Investments in subsidiaries		195,625			—			(195,625	)		—
Intercompany receivables		154,132			(154,132	)		—			—
Intangible assets, net		—			573			—			573
Other non-current assets		10,821			15,930			—			26,751
Total assets	$	376,773		$	379,161		$	(195,625	)	$	560,309
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	63		$	26,839		$	—		$	26,902
Accrued liabilities and other		1,274			13,210			—			14,484
Current portion of capital lease obligations		—			4,243			—			4,243
Current maturities of long-term debt		—			3,935			—			3,935
Total current liabilities		1,337			48,227			—			49,564
Long-term debt, less current maturities		193,152			6,809			—			199,961
Long-term obligation to related party		—			98,388			—			98,388
Related party payables, net		(1,343	)		6,229			—			4,886
Asset retirement obligations		—			17,962			—			17,962
Long-term portion of capital lease obligations		—			5,474			—			5,474
Deferred income taxes		984			—			—			984
Other non-current liabilities		—			428			—			428
Total liabilities		194,130			183,517			—			377,647
Stockholders’ equity:
Armstrong Energy, Inc.’s equity		182,643			195,625			(195,625	)		182,643
Non-controlling interest		—			19			—			19
Total stockholders’ equity		182,643			195,644			(195,625	)		182,662
Total liabilities and stockholders’ equity	$	376,773		$	379,161		$	(195,625	)	$	560,309

F-57

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplement Condensed Consolidated Statements of Operations

	Three Months Ended June 30, 2013
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	101,244		$	—		$	101,244
Costs and Expenses:
Operating costs and expenses		—			71,994			—			71,994
Production royalty to related party		—			1,967			—			1,967
Depreciation, depletion, and amortization		421			8,548			—			8,969
Asset retirement obligation expenses		—			592			—			592
Selling, general and administrative costs		1,262			12,468			—			13,730
Operating (loss) income		(1,683	)		5,675			—			3,992
Other income (expense):
Interest income		—			15			—			15
Interest expense		(5,635	)		(3,039	)		—			(8,674	)
Other, net		—			134			—			134
Income from investment in subsidiaries		2,785			—			(2,785	)		—
(Loss) income before income taxes		(4,533	)		2,785			(2,785	)		(4,533	)
Income tax provision		—			—			—			—
Net (loss) income		(4,533	)		2,785			(2,785	)		(4,533	)
Income attributable to non-controlling interests		—			—			—			—
Net (loss) income attributable to common stockholders	$	(4,533	)	$	2,785		$	(2,785	)	$	(4,533	)

	Three Months Ended June 30, 2012
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	99,100		$	—		$	99,100
Costs and Expenses:
Operating costs and expenses		—			68,785			—			68,785
Production royalty to related party		—			1,405			—			1,405
Depreciation, depletion, and amortization		230			8,250			—			8,480
Asset retirement obligation expenses		—			1,036			—			1,036
Selling, general and administrative costs		1,509			11,294			—			12,803
Operating (loss) income		(1,739	)		8,330			—			6,591
Other income (expense):
Interest income		—			14			—			14
Interest expense		(134	)		(4,732	)		—			(4,866	)
Other, net		25			181			—			206
Income from investment in subsidiaries		3,793			—			(3,793	)		—
(Loss) income before income taxes		1,945			3,793			(3,793	)		1,945
Income tax provision		—			—			—			—
Net (loss) income		1,945			3,793			(3,793	)		1,945
Income attributable to non-controlling interests		—			—			—			—
Net (loss) income attributable to common stockholders	$	1,945		$	3,793		$	(3,793	)	$	1,945

F-58

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Six Months Ended June 30, 2013
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	202,466		$	—		$	202,466
Costs and Expenses:
Operating costs and expenses		—			146,606			—			146,606
Production royalty to related party		—			4,017			—			4,017
Depreciation, depletion, and amortization		823			16,942			—			17,765
Asset retirement obligation expenses		—			1,165			—			1,165
Selling, general and administrative costs		2,457			24,518			—			26,975
Operating income		(3,280	)		9,218			—			5,938
Other income (expense):
Interest income		—			30			—			30
Interest expense		(11,302	)		(5,940	)		—			(17,242	)
Other, net		—			245			—			245
Income from investment in subsidiaries		3,553			—			(3,553	)		—
(Loss) Income before income taxes		(11,029	)		3,553			(3,553	)		(11,029	)
Income tax provision		—			—			—			—
Net (loss) income		(11,029	)		3,553			(3,553	)		(11,029	)
Income attributable to non-controlling interests		—			—			—			—
Net (loss) income attributable to common stockholders	$	(11,029	)	$	3,553		$	(3,553	)	$	(11,029	)

	Six Months Ended June 30, 2012
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	193,173		$	—		$	193,173
Costs and Expenses:
Operating costs and expenses		—			137,794			—			137,794
Production royalty to related party		—			2,363			—			2,363
Depreciation, depletion, and amortization		384			15,735			—			16,119
Asset retirement obligation expenses		—			2,140			—			2,140
Selling, general and administrative costs		2,543			22,781			—			25,324
Operating income		(2,927	)		12,360			—			9,433
Other income (expense):
Interest income		—			34			—			34
Interest expense		(253	)		(8,797	)		—			(9,050	)
Other, net		(41	)		400			—			359
Income from investment in subsidiaries		3,997			—			(3,997	)		—
(Loss) Income before income taxes		776			3,997			(3,997	)		776
Income tax provision		—			—			—			—
Net (loss) income		776			3,997			(3,997	)		776
Income attributable to non-controlling interests		—			—			—			—
Net (loss) income attributable to common stockholders	$	776		$	3,997		$	(3,997	)	$	776

F-59

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplement Condensed Consolidating Statements of Comprehensive Income (Loss)

	Three Months Ended June 30, 2013
	Parent / Issuer			Guarantor Subsidiaries		Eliminations			Consolidated
Net (loss) income	$	(4,553	)	$	2,785	$	(2,785	)	$	(4,533	)
Other comprehensive income (loss):
Postretirement benefit plan		—			24		—			24
Other comprehensive income (loss)		—			24		—			24
Comprehensive (loss) income		(4,553	)		2,809		(2,785	)		(4,509	)
Less: Comprehensive income (loss) attributable to non-controlling interests		—			—		—			—
Comprehensive (loss) income attributable to common stockholders	$	(4,553	)	$	2,809	$	(2,785	)	$	(4,509	)

	Three Months Ended June 30, 2012
	Parent / Issuer			Guarantor Subsidiaries		Eliminations			Consolidated
Net income	$	1,945		$	3,793	$	(3,793	)	$	1,945
Other comprehensive income (loss):
Unrealized loss on derivatives arising during the period, net of tax of zero		(129	)		—		—			(129	)
Less: Reclassification adjustments for loss on derivatives included in net loss, net of tax of zero		(215	)		—		—			(215	)
Other comprehensive income (loss)		86			—		—			86
Comprehensive income		2,031			3,793		(3,793	)		2,031
Less: Comprehensive income (loss) attributable to non-controlling interests		—			—		—			—
Comprehensive income attributable to common stockholders	$	2,031		$	3,793	$	(3,793	)	$	2,031

	Six Months Ended June 30, 2013
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Net (loss) income	$	(11,029	)	$	3,553		$	(3,553	)	$	11,029
Other comprehensive income (loss):
Postretirement benefit plan		—			(858	)		—			(858	)
Other comprehensive income (loss)		—			(858	)		—			(858	)
Comprehensive (loss) income		(11,029	)		2,695			(3,553	)		(11,887	)
Less: Comprehensive income (loss) attributable to non-controlling interests		—			—			—			—
Comprehensive (loss) income attributable to common stockholders	$	(11,029	)	$	2,695		$	(3,553	)	$	(11,887	)

F-60

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Six Months Ended June 30, 2012
	Parent / Issuer			Guarantor Subsidiaries		Eliminations			Consolidated
Net income	$	776		$	3,997	$	(3,997	)	$	776
Other comprehensive income (loss):
Unrealized loss on derivatives arising during the period, net of tax of zero		(232	)		—		—			(232	)
Less: Reclassification adjustments for loss on derivatives included in net loss, net of tax of zero		(444	)		—		—			(444	)
Other comprehensive income (loss)		212			—		—			212
Comprehensive income		988			3,997		(3,997	)		988
Less: Comprehensive income (loss) attributable to non-controlling interests		—			—		—			—
Comprehensive income attributable to common stockholders	$	988		$	3,997	$	(3,997	)	$	988

Supplemental Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2013
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(12,139	)	$	41,429		$	29,290
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development		—			(23,372	)		(23,372	)
Investment in affiliate		—			—			—
Advance to related party		—			(17,500	)		(17,500	)
Proceeds from disposal of fixed assets		—			255			255
Net cash used in investing activities		—			(40,617	)		(40,617	)
Cash Flows from Financing Activities:
Payment on capital lease obligations		—			(2,044	)		(2,044	)
Payment of long-term debt		—			(2,030	)		(2,030	)
Payment of financing costs and fees		(29	)		—			(29	)
Transactions with affiliates, net		12,093			(12,093	)		—
Contributions of noncontrolling interest		—			4			4
Net cash provided by (used in) financing activities		12,064			(16,163	)		(4,099	)
Net change in cash and cash equivalents		(75	)		(15,351	)		(15,426	)
Cash, at the beginning of the period		75			60,057			60,132
Cash, at the end of the period	$	—		$	44,706		$	44,706

F-61

Armstrong Energy, Inc. and Subsidiaries

(formerly Armstrong Land Company, LLC and Subsidiaries)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Six Months Ended June 30, 2012
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(3,071	)	$	23,795		$	20,724
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development		(10,709	)		(19,069	)		(29,778	)
Investment in affiliate		—			(130	)		(130	)
Net cash used in investing activities		(10,709	)		(19,199	)		(29,908	)
Cash Flows from Financing Activities:
Payment on capital lease obligations		—			(2,161	)		(2,161	)
Payment of long-term debt		—			(34,765	)		(34,765	)
Payment of financing costs and fees		(743	)		—			(743	)
Proceeds from the issuance of Series A convertible preferred stock		30,000			—			30,000
Transactions with affiliates, net		(15,521	)		15,521			—
Net cash provided by (used in) financing activities		13,736			(21,405	)		(7,669	)
Net change in cash and cash equivalents		(44	)		(16,809	)		(16,853	)
Cash, at the beginning of the period		299			19,281			19,580
Cash, at the end of the period	$	255		$	2,472		$	2,727

17. Subsequent Event

In August 2013, the Company entered into a settlement agreement with one of its customers regarding a governmental imposition claim associated with the additional mining costs incurred from constructing the MSHA mandated safety bench at the Equality Boot mine in November 2011. The terms of the settlement include a lump sum payment of approximately $2,500, due within 15 days of the execution of the settlement agreement, related to coal shipments from November 2011 thru June 2013, and a price adjustment of $0.87 per ton for tons shipped from the Equality Boot mine subsequent to June 2013 on certain contracts with the customer.

F-62

ARMSTRONG ENERGY, INC.

OFFER TO EXCHANGE

All Outstanding Unregistered 11.75% Senior Secured Notes due 2019

($200,000,000 Aggregate Principal Amount)

For

11.75% Senior Secured Notes due 2019 ($200,000,000 Aggregate Principal Amount)

that have been registered under the Securities Act of 1933

PROSPECTUS

October 15, 2013

When making an investment decision with respect to the Notes, you should rely only on the information contained in this prospectus. We have not authorized any person to provide you with any information or represent anything about us or this exchange offer that is not contained in this prospectus. If given or made, any such other information or representation should not be relied upon as having been authorized by us. We are not making an offer to sell these Notes in any jurisdiction where an offer or sale is not permitted.

Through and including November 9, 2013 (the 25^th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this exchange offer, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.