Armstrong Energy, Inc. - FORM 10-K

Armstrong Energy, Inc. - FORM 10-K - March 23, 2016

Attached files

Attached files

Armstrong Energy, Inc. Reports

file	filename
EX-32.1 - EXHIBIT 32.1 - Armstrong Energy, Inc.	arms12311510kexhibit321.htm
EX-21.1 - EXHIBIT 21.1 - Armstrong Energy, Inc.	arms12311510kexhibit211.htm
EX-31.1 - EXHIBIT 31.1 - Armstrong Energy, Inc.	arms12311510kexhibit311.htm
EX-31.2 - EXHIBIT 31.2 - Armstrong Energy, Inc.	arms12311510kexhibit312.htm
EX-95.1 - EXHIBIT 95.1 - Armstrong Energy, Inc.	arms-12311510kexhibit951.htm
EX-32.2 - EXHIBIT 32.2 - Armstrong Energy, Inc.	arms12311510kexhibit322.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K



ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 333-191182

Armstrong Energy, Inc.

(Exact name of registrant as specified in its charter)



Delaware		20-8015664
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

7733 Forsyth Boulevard, Suite 1625 St. Louis, Missouri		63105
(Address of principal executive offices)		(Zip code)

(314) 721 – 8202

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ Yes ý No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨ Yes ý No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes ý No

As of June 30, 2015, there was no established public market for the registrant’s voting and non-voting common stock and therefore the aggregate market value of the voting and non-voting common equity held by non-affiliates is not determinable.

As of March 23, 2016, there were 21,883,224 shares of Armstrong Energy, Inc.’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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		Page
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	33
Item 2.	Properties	33
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35
	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	54
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
Item 9A.	Controls and Procedures	55
Item 9B.	Other Information	56
	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	57
Item 11.	Executive Compensation	61
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	66
Item 13.	Certain Relationships and Related-Party Transactions, and Director Independence	67
Item 14.	Principal Accountant Fees and Services	68
	PART IV

Item 15.	Exhibits and Financial Statement Schedules	69

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Various statements contained in this annual report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). 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 annual report speak only as of the date of this annual report; 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 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;


•	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;


•	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;


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


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


•	liquidity constraints and our ability to service our outstanding indebtedness;


•	our ability to service our outstanding indebtedness;


•	our ability to comply with the restrictions imposed by our revolving credit facility, the indenture governing our notes and other financing arrangements;


•	our ability to obtain or renew surety bonds on acceptable terms;


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

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•	existing and future legislation and regulations affecting both our 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, or toxic gases, such as hydrogen chloride, particulate matter or greenhouse gases;


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


•	our ability to attract and retain key management personnel;


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


•	other factors, including those discussed in Item 1A – “Risk Factors” of this Annual Report on Form 10-K.

iii

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PART I

Item 1. Business

Overview

Our History

Armstrong Energy, Inc. (together with its subsidiaries, we, Armstrong Energy, or the Company) is 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 2015 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. Between 2006 and 2011, we completed six transactions, either directly or through our affiliate, Thoroughbred Resources, L.P. (Thoroughbred), to acquire mineral reserves and land from Peabody Energy, Inc. (Peabody). We commenced production in the second quarter of 2008 and currently operate six mines, including three surface and three underground. Since 2008, we have continued to acquire additional mineral reserves, which are strategic to our operating plans and currently control approximately 554 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 investment funds managed by Yorktown Partners LLC (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. Yorktown is represented on our board by Bryan H. Lawrence, founder and principal of Yorktown. 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.

We operate in one reporting segment. For information regarding our revenue, long-lived assets, and total assets, please see Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 – “Financial Statements and Supplementary Data.”

Our Reorganization

Armstrong Land Company, LLC, our prior holding company (Predecessor), was formed in 2006 as a Delaware limited liability company, and Armstrong Energy, Inc. was previously a wholly-owned subsidiary of our Predecessor. 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, our Predecessor 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 our Predecessor received 9.25 shares of Armstrong Energy, Inc. common stock for each unit held.

Our Relationship with Thoroughbred Resources, L.P.

Armstrong Resource Partners, L.P. (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. On February 1, 2014, Armstrong Resource Partners merged with and into Thoroughbred Resources, LLC, an entity wholly-owned by Yorktown also created to lease coal properties in exchange for royalties, with Armstrong Resource Partners as the surviving entity (the Merger). Effective with the Merger, Armstrong Resource Partners changed its name to Thoroughbred. As of December 31, 2015, Armstrong Energy holds a 0.2% equity interest in Thoroughbred through a wholly-owned subsidiary, Elk Creek GP, LLC (Elk Creek GP), which is the sole general partner of Thoroughbred. References to Thoroughbred in this Annual Report on Form 10-K refer to Armstrong Resource Partners prior to the Merger, unless otherwise noted.

In January 2014, our investment in Ram Terminals, LLC (RAM), an entity majority owned by Yorktown, was converted into an equal ownership percentage of Terminal Holdings, LLC, a holding company, which is the sole member of both RAM and MG Midstreaming, LLC. Subsequent to the Merger, but also on February 1, 2014, Terminal Holdings, LLC merged with

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and into a merger subsidiary of Thoroughbred created for the purpose of the transaction, with Terminal Holdings, LLC as the surviving entity. Terminal Holdings, LLC was owned by us and Yorktown in the same percentage as our prior interests in RAM, and, by virtue of the merger, Armstrong Energy’s equity interest in Terminal Holdings, LLC was converted into an equal number of common units representing limited partnership interests in Thoroughbred. The newly converted interest in Thoroughbred equates to an additional 0.9% equity interest in Thoroughbred, which increases Armstrong Energy’s total equity interest in Thoroughbred to 1.1%. Subsequent to the merger transactions, Yorktown owns 97.9% of its equity interests in Thoroughbred, all limited partnership interests.

Pursuant to the Amended and Restated Agreement of Limited Partnership of Thoroughbred Resources, L.P. (Thoroughbred LPA), Elk Creek GP has the exclusive authority to conduct, direct and manage all activities of Thoroughbred. Pursuant to the Thoroughbred LPA, effective October 1, 2011, Yorktown may unilaterally 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 Thoroughbred in the financial statements of Armstrong Energy.

Beginning in 2011, Thoroughbred acquired, through multiple transactions, an undivided interest in certain land and mineral reserves of Armstrong Energy in Muhlenberg and Ohio Counties, Kentucky. As of December 31, 2015, Thoroughbred owns a 61.38% undivided interest in approximately 174 million tons of our mineral reserves. In conjunction with the aforementioned acquisitions, Armstrong Energy entered into lease agreements with Thoroughbred pursuant to which Thoroughbred granted Armstrong Energy leases to its undivided interest in the mining properties acquired and licenses to mine coal on those properties in exchange for a production royalty.

In addition, we have also leased approximately 253 million tons of mineral reserves wholly-owned by Thoroughbred in exchange for a production royalty. See Item 13 – “Certain Relationships and Related-Party Transactions, and Director Independence” for further information regarding the Merger and related-party transactions.

Our Mining Operations

We currently operate six active mines, all of which are located in the Illinois Basin coal region in western Kentucky. Our active operations are comprised of three surface mines and three underground mines, and we have three preparation plants serving these operations. In 2015, approximately 50% of the coal that we produced came from our surface mining operations.

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. In general, we have developed our mines and preparation plants at strategic locations in close proximity to rail or barge shipping facilities.

We control approximately 554 million tons of coal available for production at our active and proposed mines in Ohio, Muhlenberg, McLean, Webster, and Union counties in Western Kentucky, of which we lease or sublease approximately 235 million tons from various unaffiliated landowners.

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

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. The Midway mine produced approximately 1.1 million tons of clean coal in 2015 and is 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 indicate the Midway mine has approximately 14.0 million tons of proven and probable reserves. Coal from the Midway mine was primarily transported less than one mile by truck to the Midway Preparation Plant for processing, where it is then shipped to customers via truck, rail or barge. On December 31, 2015, production at the Midway mine was temporarily idled as part of the Company's restructuring activities described in Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Parkway Underground Mine. The Parkway underground mine is located northeast of Central City, Kentucky in Muhlenberg County. The Parkway underground mine 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 underground mine. The Parkway underground mine has historically operated with two working super sections, and each section is equipped with two continuous miners that operate concurrently. On December 31, 2015, one of the super sections was shuttered as part of the Company's restructuring activities described in Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations." The Parkway underground mine produced approximately 1.1 million tons of clean coal in 2015. As of December 31, 2015, the Parkway underground mine had approximately 8.8 million tons of proven and probable reserves. The majority of the coal from the Parkway underground mine is primarily 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.

Equality Boot Mine. The Equality Boot mine is a surface mining operation located eight miles southwest of Centertown, Kentucky, which commenced operations in September 2010. The Equality Boot mine extracts thermal coal from the West Kentucky #14, #13, #12 and #11 seams and produced approximately 2.2 million tons of coal in 2015. 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. The Equality Boot mine had approximately 13.0 million tons of proven and probable reserves as of December 31, 2015. Coal from the Equality Boot mine is primarily transported less than one mile by truck to a 4,400 foot overland conveyor system, which 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.

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Lewis Creek Mine. The Lewis Creek mine is a surface mine located approximately five miles south of Centertown, Kentucky, and approximately 3.5 miles from the Midway Preparation Plant. Production commenced in June 2011 at the Lewis Creek mine, and thermal coal is being mined from the West Kentucky seams #13A and #13. Lewis Creek produced approximately 0.8 million tons of clean coal in 2015. 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, 2015, there were approximately 3.0 million tons of proven and probable reserves at the Lewis Creek surface mine. Coal mined at the Lewis Creek mine is primarily transported by truck to the Midway Preparation Plant for processing and subsequent delivery to our customers.

Kronos Underground Mine. The Kronos underground mine, which commenced operations in September 2011, is located approximately three miles southwest of Centertown, Kentucky. It extracts thermal coal from the West Kentucky #9 seam. The Kronos underground mine produced approximately 2.4 million clean tons of coal in 2015. The mine utilizes four continuous miner super sections, and there were approximately 31.2 million tons of proven and probable reserves at the Kronos underground mine as of December 31, 2015. Coal mined at the Kronos underground mine is transported by truck to the Midway Preparation Plant and by conveyor to the Armstrong Dock Preparation Plant for processing and delivery to our customers.

Survant Underground Mine. The Survant underground mine, which is located at our Parkway complex, came out of development in August 2015. The Survant underground mine extracts coal from the West Kentucky #8 seam and produced approximately 0.4 million clean tons of coal in 2015 through the operation of one continuous miner super section. As of December 31, 2015, there were approximately 59.3 million tons of proven and probably reserves at the Survant underground mine. Coal mined from the Survant underground mine is primarily processed at the Parkway Preparation Plant prior to shipment to the ultimate customer.

Future Mines.

We continue to evaluate our mine plans and expect to open additional mines in order to replace existing mines as the reserves are depleted.

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 process the coal we extract from our mines to ensure a consistent quality and to enhance its suitability for particular end-users. In 2015, 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, Lewis Creek, Kronos Underground	Parkway Underground, Survant Underground	Equality Boot, Kronos Underground
Current Capacity (Tons Per Hour):	1,200	400	1,200
Average Capacity Utilization:	78.3%	94.9%	81.0%
Loadout Tons Per Hour:	2,500 (Rail)	—	2,500 (Barge)
Transportation:	Rail, Truck	Truck	Barge

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 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

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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.

Customers

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, 2015, approximately 99% of our coal revenues related to sales to electric utilities. The majority of our electric utility customers purchase coal for terms of one to four years, but we also supply coal on a spot basis for some of our customers.

In 2015, we sold coal to nine domestic customers with operations located in numerous states. The majority of those customers operate power plants in the Midwestern and Southern regions of the United States. For the year ended December 31, 2015, we derived approximately 38% and 29% of our total coal revenues from sales to our two largest customers.

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 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 2015, we sold approximately 91% 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 December 31, 2015, we had multi-year coal supply agreements with remaining terms ranging from one to four 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 affect their operations.

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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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 51% of our coal shipped in 2015 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 2015, approximately 34% and 15% of our coal sales tonnage was shipped by truck and rail, respectively.

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., Peabody Energy, Inc., Foresight Energy L.P., and Murray Energy Corp., 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 data from the Mine Safety and Health Administration (MSHA), we were the fifth largest producer of Illinois Basin coal in fiscal 2015, producing approximately 7% of the total Illinois Basin coal. Outside of the Illinois Basin, we compete broadly with other United States based producers of thermal coal and internationally with numerous global coal producers.

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.

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 December 31, 2015, we employed approximately 751 employees, none of whom is represented for collective bargaining by a union. We believe that our relations with all employees are good, and, since our inception, we have had no history of work stoppages or union organizing campaigns.

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 affect our ability to mine and ship our coal and our customers’ ability to take delivery of coal.

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;

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•	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.

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 differing interpretations and more rigorous enforcement of existing laws, regulations or orders in the future, 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. 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 permits required for mining. None of the violations we have experienced to date or the monetary penalties assessed have had a material impact on our operations.

In addition, 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. 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, which may adversely affect our mining operations, cost structure or the demand for coal. 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.

Mine Safety and Health Laws

Stringent health and safety standards have been in effect since the enactment of the Federal Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (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. It requires regular inspections of surface and underground coal mines and the issuance of citations or orders for violations of mandatory health and safety standards. Serious violations of mandatory health and safety standards or circumstances deemed to constitute an imminent danger to health or safety 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 falsify records required to be kept under the Mine Act or 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. The State of Kentucky also has programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry provides one of the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. In the wake of several recent underground mine accidents, enforcement scrutiny has also increased, including increased number of inspections, more inspection hours at mine sites and increased number and severity of enforcement actions. Such regulation and enforcement has a significant effect on our operating costs.

In 2006, in response to an increase in fatal mine accidents, Congress enacted the Federal Mine Improvement and New Emergency Response Act of 2006 (the MINER Act). Among other things, the MINER Act: (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) notifying federal authorities of incidents that pose a reasonable risk of death; and (ii) increased penalties for violations of applicable federal laws and regulations.

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On January 23, 2013, MSHA published a revision to the pattern of violations (POV) regulation allowing, among other things, the use of non-final citations and orders in determining whether a pattern of violations exists at a coal mine. Under the new rule, citations and orders which an operator has challenged but that have not yet been adjudicated may nonetheless be used to determine that a pattern of violations exists at a mine. If a POV notice is issued to a mine operator, each subsequent significant and substantial violation results in a withdraw order until the violation is abated. The revised POV regulation also eliminated the “potential pattern of violations” (“PPOV”) designation along with the subsequent period during with a mine receiving PPOV notice could regain compliance before receiving a POV notice.

On April 23, 2014, MSHA published a final rule, which, among other things, reduces the overall respirable coal dust standard from 2.0 mg to 1.5 mg per cubic meter of air and cuts in half the standard from 1.0 to 0.5 for certain mine entries and miners with pneumoconiosis. The rule also increases sampling requirements, requires use of continuous personal dust monitors (CPDMs) to provide real-time information about dust levels and requires immediate corrective action when a single, full-shift sample finds an excessive concentration of dust. Legal challenges to the rule have been unsuccessful. MHSA is expected to require mine operators to implement all aspects of the final rule by the end of 2016.

On January 15, 2015, MSHA published a final rule requiring underground coal mine operators to equip continuous mining machines, except full-face continuous mining machines, with proximity detection systems. This final rule is intended to strengthen protections for miners by reducing the potential for pinning, crushing or striking accidents in underground coal mines. The new rule was effective March 16, 2015, but has staggered implementation deadlines through early 2018 depending upon the manufacturing date of the equipment and whether or not the equipment has been previously equipped with a proximity detection system.

On September 2, 2015, MSHA published a proposed rule requiring underground coal mine operators to equip all haulage equipment and scoops on non-longwall sections with proximity detection systems. The comment period closed, and a final rule is expected in 2016. Based upon the proposal, the rule will have a staggered implementation schedule from 8 to 36 months after the effective date of the final rule.

Subsequent to passage of the MINER Act, Kentucky and several other states enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties and increased inspections and oversight.

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 if they increase our costs, they will also increase the costs of our competitors. Some, but not all, of these additional costs may be passed on to our customers.

We provide income replacement and medical treatment for work-related traumatic injury claims as required under 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 eligible current and former employee claimants 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, 1973. The trust fund is funded by an excise tax on production of up to $1.10 per ton for coal mined via underground mining methods and up to $0.55 per ton for coal mined via surface mining methods, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. We recorded $6.3 million and $7.3 million of expense related to this excise tax in 2015 and 2014, respectively.

With the implementation of the Patient Protection and Affordable Care Act in 2010 and the amendment of federal black lung regulations, the number of claimants who are awarded federal black lung benefits has increased and will likely continue to increase, as will the amounts of those awards. Our payment obligations for federal black lung benefits are either secured by insurance coverage or paid from a tax exempt trust established for that purpose. Based on required funding levels, we may have to supplement the trust corpus to cover the anticipated liabilities going forward. In addition, we could be held liable under various state statutes for black lung claims.

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Mining Permits and Approval

Numerous governmental permits and approvals are required for our coal mining operations. When we apply for some of these permits, we are required to assess the effect or impact that any proposed production or processing of coal may have on 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 permitting 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 modify or revoke existing permits and to deny the issuance of additional permits.

In order to obtain the permits and approvals necessary for mining 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 permits for mining are becoming increasingly difficult to obtain in a timely manner, or at all, particularly those permits involving the federal Clean Water Act (CWA) and the U.S. Army Corps of Engineers (Corps). 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 affect bodies of water regulated by the Corps. The permit 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 the permits or other approvals necessary for mining 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 modification, revocation or suspension of mining permits and, in certain circumstances, criminal sanctions.

Surface Mining Control and Reclamation Act

The Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement within the Department of the Interior (OSM), establishes operational, reclamation and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. Mining operators must obtain SMCRA permits and permit renewals from 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 approved by OSM. Our mines are located in Kentucky, which has primacy to administer the SMCRA program. SMCRA stipulates compliance with many other major environmental statutes, including the federal Clean Air Act (CAA), the CWA, the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund).

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 it to take more than a year for a SMCRA mine permit to be issued.

The OSM’s “stream buffer zone rule” (SBZ Rule) prohibits 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 SBZ Rule; however, the U.S. District Court for the District of Columbia struck down the revised SBZ Rule in early 2014. As such, the 1983-era SBZ rule remains in place pending further action by OSM to proceed with new rulemaking.

On June 11, 2009, the Secretary of the Department of the Interior, the Administrator of the EPA, and the Acting Assistant Secretary of the Army for Civil Works entered into a memorandum of understanding (MOU) to reduce the environmental impacts of surface coal mining operations in certain Appalachian states, committing OSM to revising provisions of current SMCRA regulations, including the SBZ rule. On July 27, 2015, OSM published its proposed Stream Protection Rule (SPR). Comments were to be submitted on the proposed rule by October 26, 2015. The draft SPR proposes extensive revisions to the current regulation of coal mining, including but not limited to changes to bonding requirements, “approximate original contour” requirements, subsidence restrictions, and post-mining restoration requirements. The proposal includes newly defined terms and concepts such as “material damage to the hydrologic balance outside the permit area,” new monitoring and data

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collection requirements, stream restoration requirements and new procedures and requirements related to the protection of threatened or endangered species under the federal Endangered Species Act.

Finalization of the SPR is currently being challenged in U.S. Congress. In January 2016, the U.S. House of Representatives passed the Supporting Transparent Regulatory and Environmental Actions in Mining Act to block the implementation of the SPR. To date, the U.S. Senate has not voted on the matter.

The SPR, if adopted, is anticipated to be stricter than the SBZ Rule promulgated in December 2008, and 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 affect our future ability to conduct certain types of mining activities.

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 was 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 their 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 December 31, 2015, we had approximately $32.5 million in surety bonds outstanding to secure the performance of our reclamation obligations, which are collateralized by cash deposits of approximately $6.1 million.

In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund, which was created by SMCRA, imposes a fee on all coal produced in the United States. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. Currently and through 2021, the fee is $0.28 per ton for coal mined via surface mining methods and $0.12 per ton on coal via underground mining methods. In 2015, we recorded approximately $1.5 million of expense related to these reclamation fees.

In January 2011, OSM determined that the Kentucky regulatory program contained several reclamation bonding deficiencies. During May 2012, OSM required the implementation of program changes to address the deficiencies. Prominent among those changes was the promulgation of legislation that established the Kentucky Reclamation Guaranty Fund (RGF), the RGF Commission and the Office of the RGF, to support the commission and administer its affairs. The RGF is a revolving, interest-bearing account that will provide financial assistance in the event the permit-specific reclamation bond is insufficient to complete reclamation on a mine site. Participation in the RGF is mandatory, unless permittees elect to provide a full-cost bond in accordance with specific calculation methods. The RGF received initial capitalization from the assets of the former voluntary Kentucky Bond Pool, which was abolished by the new legislation. A start-up assessment and a one-time acreage fee provided additional initial capitalization. Beginning January 2014, additional revenue for the RGF is generated from tonnage and acreage fees paid annually, depending on the operational status of each permit.

Air Emissions

The CAA, the amendments thereto and state laws that regulate air emissions, affect coal mining operations, both directly and indirectly. Direct impacts on our coal mining and processing operations include CAA permitting requirements and control requirements for particulate matter, which includes fugitive dust from roadways, parking lots and equipment such as conveyors and storage piles. The CAA also indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide (SO₂), nitrogen oxide (NOx), carbon monoxide, ozone, mercury and other compounds emitted by coal-fired power plants, which are the largest end users of our coal. Costs to comply with current, new and emerging regulations applicable to coal-fired power plants could have an adverse effect on our customers, thereby reducing demand for coal. Moreover, these regulations may cause some users of coal to switch from coal to natural gas or renewable energy for electric power generation.

In addition to the greenhouse gas (GHG) issues discussed below, the air emissions programs that may directly or indirectly impact our operations include, but are not limited to, the following:

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The EPA’s Acid Rain Program under the CAA regulates emissions of SO_2,a by-product of coal combustion, from electric generating facilities. Affected facilities purchase or are otherwise allocated SO₂ emissions allowances, which must be surrendered annually in an amount equal to a facility’s SO₂ emissions in that year. Facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their SO₂ emissions. In addition to purchasing or trading for additional SO₂allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.

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The Clean Air Interstate Rule (CAIR) calls for power plants in 28 states and Washington, D.C. to reduce emission levels of SO₂ and NOx pursuant to a cap-and-trade program similar to the system in effect for acid rain. In June 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR), a replacement rule for CAIR, which requires 28 states in the Midwest and eastern seaboard to reduce power plant SO₂ and NOxemissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Though some issues with CSAPR remain subject to litigation, the EPA began implementation of CSAPR’s Phase 1 emission reduction requirements on January 1, 2015. Phase 2 will begin January 1, 2017. On November 16, 2015, the EPA proposed an update to CSAPR which would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S. The final impact of CSAPR are unknown at the present time due to the implementation of Mercury and Air Toxic Standards (MATS), discussed below, the recent updates to CSAPR and the significant number of coal retirements that have resulted and that potentially will result from MATS.

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In February 2012, the EPA adopted the MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants. In March 2013, the EPA finalized a reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies. Appeals were filed and oral arguments were heard by the D.C. Circuit Court of Appeals in December 2013. On April 15, 2014 the D.C. Circuit Court of Appeals upheld MATS. On June 29, 2015 the Supreme Court remanded the final rule back to the D.C. Circuit holding that the agency must consider cost before deciding whether regulation is necessary and appropriate. On December 1, 2015, the EPA issued, for comment, the proposed Supplemental Finding. The agency has indicated that the Supplemental Finding will be issued by April 15, 2016. Many electric generators have already announced retirements due to the MATS rule. If upheld by the D.C. Circuit Court of Appeals, MATS will force generators to make capital investments to retrofit power plants and could lead to additional retirements of older coal-fired generating units. The announced and possible additional retirements are likely to reduce the demand for coal. 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 been proposed. Regulation of mercury emissions may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.

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In January 2013, the EPA issued final Maximum Achievable Control Technology (MACT) standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters (Boiler MACT), which require owners of industrial, commercial, and institutional boilers to comply with standards for air pollutants, including mercury and other metals, fine particulates, and acid gases such as hydrogen chloride. Businesses and environmental groups have filed legal challenges to Boiler MACT and petitioned the EPA to reconsider the rule. On December 1, 2014, the EPA announced reconsideration of the standard and will accept public comment on five issues for its standards on area sources, will review three issues related to its major-source boiler standards, and four issues relating to commercial and solid waste incinerator units. Before reconsideration, the EPA estimated the rule will affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. While some owners would make capital expenditures to retrofit boilers and process heaters, a number of boilers and process heaters could be prematurely retired. Retirements are likely to reduce the demand for coal. The impact of the regulations will depend on the EPA’s reconsideration and the outcome of subsequent legal challenges.

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The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the national ambient air quality standards (NAAQS) should be revised. As a result of this process, the EPA has adopted more stringent NAAQS for fine particulate matter (PM), ozone, SO₂ and NOx. As a result, some states will be required to amend their existing individual state implementation plans (SIPs) to achieve and compliance with the new air quality standards. Other states will be required to develop new SIPs for areas that were previously in “attainment”, but do not meet the revised standards. In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. The final rule has been

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challenged in litigation by industry and state petitioners and several environmental groups, some aspects of which have been vacated and some of which have been remanded to the EPA for further consideration. The final rules and new standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers. Because coal mining operations and coal-fired electric generating facilities emit PM and SO₂, our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal.

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The EPA’s regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. Under the program, states are required to develop SIPs to improve visibility. Typically, these plans call for reductions in SO₂ and NOx emissions from coal-fueled electric plants. In recent cases, the EPA has decided to negate the SIPs and impose stringent requirements through federal implementation plans (FIPs). The regional haze program, including particularly the EPA’s FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.

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The EPA’s new source review (NSR) program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment. The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the NSR program. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for coal could be affected.

Greenhouse Gas Emissions

Carbon dioxide (CO₂) is a GHG, the man-made emission of which is of major concern under any regulatory framework intended to control what is sometimes referred to “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, is also classified as a GHG.

Future regulation of GHGs in the United States could occur pursuant to, for example, future U.S. treaty commitments; new domestic legislation that imposes a tax on GHG emissions, a GHG cap-and-trade program or other programs aimed at GHG reduction; or regulatory programs that may be established by the EPA under its existing authority. Internationally, the Kyoto Protocol set binding emission targets for developed countries that ratified it (the U.S. did not ratify, and Canada officially withdrew from its Kyoto commitment in 2012) to reduce their global GHG emissions. The Kyoto Protocol was nominally extended past its expiration date of December 2012, with a requirement for a new legal construct to be put into place by 2015. Most recently, the United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an international climate agreement. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. These commitments could further reduce demand and prices for our coal. Also, many states, regions and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted, which would have an adverse effect on our operations.

Even in the absence of new federal legislation, the EPA has already begun to regulate GHG emissions under the CAA. In 2009, the EPA issued a final rule, known as the Endangerment Finding, declaring that GHG emissions, including CO₂ and methane, endanger public health and welfare.

In May 2010, the EPA issued its final “tailoring rule” for GHG emissions, a policy aimed at shielding small emission sources from CAA permitting requirements. The EPA’s rule phases in various GHG-related permitting requirements beginning in January 2011. Beginning July 1, 2011, the EPA requires facilities that must already obtain NSR permits for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year. These permits require that the permittee adopt the Best Available Control Technology (BACT). In June 2012, the D.C. Circuit Court of Appeals upheld these permitting regulations. In June 2014, the U.S. Supreme Court invalidated the EPA’s position that power plants and other sources can be subject to permitting requirements based on their GHG emissions alone. For CO₂ BACT to apply, CAA permitting must be triggered by

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another regulated pollutant, such as SO₂. As a result of litigation filed by industry groups, the D.C. Circuit ordered the EPA regulations under review to be vacated, with certain limitations. On August 19, 2015, the EPA issued a final rule amending its regulations to remove portions of those regulations that were vacated by the D.C. Circuit. Currently the impacts are uncertain.

As a result of revisions to its preconstruction permitting rules that became fully effective in 2011, the EPA is now requiring new sources, including coal-fired power plants, to undergo control technology reviews for GHGs as a condition of permit issuance. These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for-and so discourage development of-coal-fired power plants.

In March 2012, the EPA proposed New Source Performance Standards (NSPS) for CO₂ emissions from new fossil fuel-fired power plants. The proposal requires new coal units to meet a CO₂ emissions standard of 1,000 lbs. CO2/MWh, which is equivalent to the CO₂emitted by a natural gas combined cycle unit. In January 2014, the EPA formally published its re-proposed NSPS for CO₂emissions from new power plants. The re-proposed rule requires an emissions standard of 1,100 lbs. CO2/MWh for new coal-fired power plants. To meet such a standard, new coal plants would be required to install carbon capture and storage (CCS) technology.

In June 2014, the EPA proposed CO₂emission “guidelines” for modified and existing fossil fuel-fired power plants, known as the Clean Power Plan (CPP). The CPP was finalized in August 2015 and established carbon pollution standards for power plants, called CO₂ emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO₂. The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA. Although each state can determine its own method of compliance, the requirements rely on decreased use of coal and increased use of natural gas and renewables for electricity generation, as well as reductions in the amount of electricity used by consumers. Judicial challenges have been filed. On February 9, 2016, the U.S. Supreme Court issued a stay, halting implementation of the regulations. The stay will be in place until the D.C. Circuit Court of Appeals rules on the merits of the legal challenges and, if following a ruling by the D.C. Circuit Court of Appeals, a writ of certiorari from the Supreme Court is sought and granted, the stay will remain in place until the Supreme Court issues its decision on the merits. If, despite the legal challenges, the rules are implemented in their current form, demand for coal will likely be further decreased, potentially significantly, and adversely impact our business.

In August 2015, the EPA released final rules requiring newly constructed coal-fired steam electric generating units (EGUs) to emit no more than 1,400 lbs. CO₂/MWh (gross) and be constructed with CCS to capture 16% of CO₂ produced by an electric generating unit burning bituminous coal. At the same time, the EPA finalized GHG emissions regulations for modified and existing power plants. The rule for modified sources required reducing GHG emissions from any modified or reconstructed source and could limit the ability of generators to upgrade coal-fired power plants, thereby reducing the demand for coal. The rule for existing sources proposes to establish different target emission rates (lbs. per megawatt hour) for each state and has an overall goal to achieve a 32% reduction of CO₂ emissions from 2005 levels by 2030. The compliance period begins in 2022, and in 2030, CO₂ emissions goals must be met. Collectively, these requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal. Congress has rejected legislation to restrict CO₂emissions from existing power plants and it is unclear whether the EPA has the legal authority to regulate CO₂ emissions for existing and modified power plants without additional Congressional authority. Challenges to the rule by a number of states and industry groups are pending before the D.C. Circuit Court of Appeals.

On June 28, 2010, the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule requiring all stationary sources that emit more than 25,000 tons of GHGs per year to collect and report annually to the EPA data regarding such emissions occurring after January 1, 2010. These GHG rules affect many of our customers, as well as additional source categories, including all underground mines subject to quarterly methane sampling by MSHA. Underground mines subject to these rules, including ours, were required to begin monitoring GHG emissions on January 1, 2011 and began reporting to the EPA in 2012.

In October 2013, the U.S. Supreme Court granted a number of petitions for certiorari seeking review of the EPA’s approach to GHG regulation. The Supreme Court heard oral arguments in February 2014. On June 23, 2014, the Supreme Court issued an opinion affirming the D.C. Circuit decision in part and reversing the decision in part. The Court struck down the EPA’s tailoring rule, making permanent a temporary exclusion that the EPA had provided for small sources. However, the Court’s holding affirmed the EPA’s authority to regulate GHG emissions from the vast majority of sources subject to the CAA’s

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permitting provisions, and did not affect the EPA’s ability to regulate GHG emissions from new and existing sources. Future legislation or new regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the coal we produce.

There have been numerous protests of and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to GHG emissions. For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of CO₂. In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, over 30 states have currently adopted “renewable energy standards” or “renewable portfolio standards,” which encourage or 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. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for our coal. Finally, 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 a second federal appeals court dismissed a similar case on procedural grounds. The U.S. Supreme Court overturned that decision in June 2011, holding that federal common law provides no basis for public nuisance claims against utilities due to their CO₂ emissions. The Supreme Court did not, however, decide whether similar claims can be brought under state common law. As a result, despite this favorable ruling, tort-type liabilities remain a concern.

In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act (NEPA). These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In December 2014, the Council on Environmental Quality released updated draft guidance discussing how federal agencies should consider the effects of GHG emissions and climate change in their NEPA evaluations. The guidance encourages agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably foreseeable emissions and effects. This guidance could create additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our future operations, including due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts.

Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement (RGGI), calling for implementation of a cap-and-trade program aimed at reducing CO₂ emissions from power plants in the participating states. The members of RGGI have established a CO₂trading program. Auctions for CO₂ allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional Northeastern states and Canadian provinces have joined as participants or observers.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.

It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with coal production and consumption, such as costs to install additional controls to reduce CO₂ emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, which could have a material adverse effect on our business, financial condition and results of operations.

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Water Discharge

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 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 jurisdictional waters. Failures to comply with the CWA or the NPDES permits can lead to the suspension or revocation of permits, the imposition of penalties, compliance costs and delays in coal production. The CWA and corresponding state laws also protect waters that states have designated as impaired (i.e., as not meeting present water quality standards) through Total Maximum Daily Load (TMDL) regulations and “high quality/exceptional use” waters through state anti-degradation regulations, which restrict or prohibit discharges which result in degradation. As part of NPDES permitting, both TMDL and anti-degradation reviews can result in our NPDES permit terms and conditions, including effluent limitations, becoming more stringent, thereby potentially increasing our treatment costs and making it more difficult to obtain new surface mining permits. Permits may also include limitations or other conditions related to pollutants not traditionally included in coal mining NPDES permits, such as chlorides, sulfates, selenium, conductivity, and dissolved solids, thus requiring additional treatment and monitoring of discharges to waters, and may include additional requirements intended to protect the physical, chemical, and biological integrity of waters. 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 any such mining activities that involve discharges of “fill” or dredged materials into 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. Effective March 2012, the Corps reissued 49 NWPs, including NWP 21, authorizing mining activities in streams and wetlands 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. Other NWPs issued in 2012 for coal mining activities include NWPs 44, 49, and 50. In addition, other NWPs can be used for certain impacts to waters associated with coal mining. Where an activity does not qualify for a NWP, the applicant must obtain an individual CWA Section 404 permit, which involves a longer and more costly application and review process.

•

Clean Water Rule (CWR). On June 29, 2015, both the EPA and the Corps jointly proposed a rule defining the scope of waters of the United States to be protected pursuant to the CWA. The CWR was proposed in response to earlier United States Supreme Court rulings interpreting the regulatory scope of the CWA, creating uncertainty as to what waters were regulated pursuant to the CWA and what waters were not. The final rule was to become effective on August 28, 2015, and revises and expands regulations that have been in place for decades, and is anticipated to expand areas subject to CWA permitting. Multiple lawsuits were filed promptly challenging the CWR. The CWR is not currently being enforced because of a federal court ruling that blocked its implementation while it is being litigated. Adding to uncertainty surrounding the rule, in December 2015 the Governmental Accountability Office concluded in a report that the EPA had improperly lobbied for the CWR.

Since 2009, the EPA has taken a more active role in its review of NPDES permit applications for coal mining

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operations in Appalachia. In September 2009, for example, the EPA delayed the issuance of 74 Section 404 permits in central Appalachia. In April 2010, the EPA issued an interim guidance document on water quality requirements for coal mines in Appalachia, coinciding with its new practice of actively commenting on and objecting to the issuance of many NPDES permits for coal mining projects, particularly in West Virginia. 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 EPA efforts have extended the time required for operations affected by them to obtain permits for coal mining, and increased the costs associated with obtaining and complying with those permits. Additionally, any future regulatory or policy changes could further restrict our ability to obtain other new permits or to maintain existing permits. Any future use of the EPA’s Section 404 “veto” power could create uncertainly with regard to our continued use of current permits.

Resource Conservation and Recovery Act

Enacted in 1976, the Resource Conservation and recovery Act (RCRA) along with corresponding state laws establish standards for the management of solid and hazardous wastes generated at facilities. RCRA affects both current waste management and disposal practices and some past waste treatment, storage and disposal practices. RCRA generally exempts certain coal mining wastes, such as overburden and coal cleaning wastes from regulation as hazardous wastes. A change in this exemption would have a significant impact on our mining operations.

Although RCRA has the potential to apply to wastes from the combustion of coal, the EPA has determined that most 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. On December 19, 2014, the EPA issued a final rule establishing that coal ash would be regulated as non-hazardous waste under RCRA subtitle D, with national minimum criteria for disposal. The rule requires closure of sites that fail to meet prescribed engineering standards, requires regular inspection of impoundments, establishes limits on the location of new sites, and requires immediate remediation and closure of unlined ponds that are polluting ground water. The rule does provide flexibility for states to implement and enforce the rule. The EPA did not address the use of coal combustion wastes as minefill, but indicated that it would separately work with OSM in order to develop effective federal regulations ensuring that such placement is adequately controlled. The regulation of coal ash under RCRA subtitle D could 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, could lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Comprehensive Environmental Response, Compensation and Liability Act

Although typically not applied to the coal mining sector, CERCLA, which was enacted in 1980, and similar state laws may affect coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA and similar state laws, joint and several liabilities may be imposed on waste generators, site owners, operators, lessees and others, regardless of fault or the legality of the original disposal activity. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our mine sites.

Endangered Species Act

The federal Endangered Species Act of 1973 and counterpart state legislation (collectively, ESA) protects species threatened with possible extinction. A number of species indigenous to the areas in which we operate are protected under the ESA, and compliance with ESA requirements could increase our costs of operations or have the effect of prohibiting or

delaying us from obtaining mining permits. Changes in species listings or requirements under the ESA could result in increased operating costs, heightened difficulty in obtaining future mining permits or the need to implement additional mitigation measures. In addition, in the event the OSM’s proposed SPR is adopted, SMCRA permitting is anticipated to require additional review or coordination with the United States Fish & Wildlife Service pursuant to the ESA as part of the SMCRA permitting process.

Other Environmental Laws

Our business is subject to numerous environmental laws. In addition to those discussed above, our operations can also be subject to the Safe Drinking Water Act, the Toxic Substances Control Act, the National Environmental Policy Act, the Emergency Planning & Community Right-to-Know Act of 1986, and other related federal laws and regulations and state and

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local counterparts, as well as individual state environmental laws and regulations. Our compliance with all of these laws may be expensive and time-consuming and cause delays or limitations in our operations.

Use of Explosives

We do not directly engage in blasting services at our surface mining locations but instead use third-party contractors to perform such services. These third party contractors are subject to numerous regulations, and, in supporting the third-party contractors in performing their blasting activities, 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.

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.

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 have opted out of any extended transition period, and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

We could 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 Exchange Act.

Available Information

We file annual, quarterly and current reports, and amendments to those reports, and other information with the Securities and Exchange Commission (SEC). You may access and read our filings without charge through the SEC’s website, at sec.gov. We also make the documents listed above available without charge through our website, www.armstrongenergyinc.com, as soon as practicable after we file or furnish them with the SEC. You may also request copies of the documents, at no cost, by telephone at (314) 721-8202 or by mail at Armstrong Energy, Inc., 7733 Forsyth Blvd., Suite 1625, St. Louis, Missouri, 63105 Attention: Vice President and Chief Financial Officer. The information on our website is not part of this Annual Report on Form 10-K.

Item 1A. Risk Factors

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;

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•	competition for production of electricity from non-coal sources, which are a function of the price and availability of alternative fuels, such as natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power, and the location, availability, quality and price of those alternative fuel sources;


•	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 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 11.75% Senior Secured Notes due 2019 (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;

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•	unexpected or accidental surface subsidence from underground mining; and


•	accidental mine water discharges, fires, explosions or similar mining accidents.

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.

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. If foreign demand for U.S. coal were to further decline, this could cause increased 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 affect U.S. prices for coal.

Our business is closely linked to domestic demand for electricity, and any changes in coal consumption by U.S. electric power generators would likely affect our business over the long term. In 2015, 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 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.

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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 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 2015, 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. While the U.S. Energy Information Administration (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 increase slightly to approximately 34% of total generation by 2040, compared with 33% during 2015. According to the EIA, total coal consumption in the U.S. in 2015 decreased by approximately 108 million tons, or 11.8%, from 2014 levels.

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 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;

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•	geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;


•	the percentage of coal ultimately recoverable;


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


•	assumptions concerning the timing for the development of the reserves; and


•	assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs, including the cost of reclamation bonds.

As a result, estimates of the quantities and qualities of economically recoverable coal 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. 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.

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.

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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, see Item 1 – “Business — Customers — 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;


•	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;


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

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•	the decision by one or more of our key customers to close certain of its facilities.

For more information regarding our major customers and multi-year coal supply agreements, see Item 1 – “Business — Customers.”

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

For the year ended December 31, 2015, we derived approximately 67% of our total coal revenues from sales to our two largest customers. We have several multi-year coal supply agreements with each of these customers, with various expiration dates extending through 2019. However, several of our multi-year coal supply agreements 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 provides that the customer has the unilateral right to terminate the agreement upon 60 days’ written notice, in which case the customer 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 these two customers are terminated early pursuant to the reopener provisions, or we fail to extend or renew our multi-year coal supply agreements with these two customers, 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 these two customers, 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.

Negotiations to extend existing agreements or enter into new multi-year coal supply agreements with our largest customers, as well as other existing customers, may not be successful, and those customers may not continue to purchase coal from us under multi-year coal supply agreements or may significantly reduce their purchases of coal from us. In addition, interruption in the purchases by or operations of our principal customers could significantly affect our results of operations and cash flows from operations, if we are unable to timely replace such demand.

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

At December 31, 2015, our total long-term debt was approximately $218.4 million, which is comprised of the following: $195.4 million in borrowings under the Notes and $23.0 million in other long-term debt. As of December 31, 2015, we had a long-term obligation owed to our affiliate, Thoroughbred, associated with the financing transactions in connection with the transfers of undivided interests in certain land and mineral reserves to Thoroughbred totaling $128.8 million. We also have significant lease and royalty obligations, including, but not limited to, our capital lease obligations that totaled approximately $2.5 million as of December 31, 2015, and our obligations under non-cancelable operating leases that totaled approximately $10.5 million. Future minimum advance royalties totaled approximately $4.6 million as of December 31, 2015. 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;

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


•	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 Notes and our asset based revolving credit facility entered into in December 2012 (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 Notes will not prevent us from incurring obligations that do not constitute indebtedness under the indenture.

The indenture governing the 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 Notes.

The indenture governing the 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 Notes, could accelerate their debt. If their debt is accelerated, we may not be able to repay all of their debt, in which case the Notes may not be fully repaid, if they are repaid at all.

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 Notes.

The Revolving Credit Facility includes customary covenants that restrict our ability and the ability of our subsidiaries to, among other things:

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•	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 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 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 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 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 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.

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 could reduce our revenues and thus adversely affect our results of operations. The domestic markets have historically experienced disruptions, 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, high unemployment rates and increasing interest rates. Furthermore, if these developments continue or worsen it may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. 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.

We may not recover our investments in our mining and other related assets, which may require us to recognize non-cash impairment charges related to those assets.

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The value of our assets may be adversely affected by numerous uncertain factors, some of which are beyond our control, including:


•	unfavorable changes in the economic environments in which we operate;


•	lower-than-expected demand and coal pricing;


•	unfavorable regulatory or legal developments impacting our industry;


•	technical and geological operating difficulties;


•	an inability to economically extract our coal reserves; and


•	unanticipated increases in operating costs.

These may cause us to fail to recover all or a portion of our investments in those assets and may trigger the recognition of non-cash impairment charges in the future, which could have a substantial adverse impact on our results of operations.

As described in Note 3, "Asset Impairment and Restructuring Charges" to our audited consolidated financial statements, included in Item 8 - "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K, we recognized an asset impairment charge of $137.7 million in 2015. Because of the volatile nature of U.S. coal markets, it is reasonably possible that our current estimates of projected future cash flows from our mining assets may change in the near term, which may result in the need for further adjustments to the carrying value of mineral rights and other mining assets.

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 Thoroughbred may be removed or control of Thoroughbred may be otherwise transferred to a third party without our consent.

Thoroughbred is majority-owned by Yorktown. Pursuant to the Thoroughbred LPA, Yorktown may remove our subsidiary, Elk Creek GP, as general partner of Thoroughbred or otherwise cause a change of control of Thoroughbred without our consent. If such a change in control of Thoroughbred were to occur, our ability to enter into, or obtain renewals of, coal lease or mining license agreements with Thoroughbred 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 Thoroughbred 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 Thoroughbred. 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 Thoroughbred. These officers may also be conflicted when negotiating the terms of contracts between Armstrong Energy and Thoroughbred.

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

As the general partner of Thoroughbred, our subsidiary Elk Creek GP has a legal duty to manage Thoroughbred in a manner beneficial to the limited partners of Thoroughbred. 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 Thoroughbred in a manner beneficial to Armstrong Energy. The managers of Elk Creek GP, some of whom are also directors and executive

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officers of Armstrong Energy, may resolve any conflict between the interests of Armstrong Energy on the one hand, and Thoroughbred, 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 Thoroughbred with respect to matters such as the allocation of opportunities to acquire coal reserves in the future, and the terms and amount of any related royalty payments. In addition, we may determine to permit Thoroughbred 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.

Our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes Oxley Act of 2002 (Section 404) for so long as we are an emerging growth company.

We are required to disclose changes made in our internal control over financial reporting on a quarterly basis, and we are required to assess the effectiveness of our internal controls annually. However, for as long as we are an “emerging growth company,” our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404. 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 Exchange Act. Even if we conclude that our internal control over financial reporting is effective, our independent registered public accounting firm may still decline to attest to our assessment or may issue a report that is qualified if it is not satisfied with our internal controls or the level at which our internal controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us.

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 of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.

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.

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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 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 affect 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 on terms that could increase the risk of payment default.

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

As described in Note 13, “Related-Party Transactions,” to our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K, we have sold certain of our coal reserves to Thoroughbred. Under U.S. generally accepted accounting principles (GAAP), these transfers are treated as financing transactions, with one consequence thereof being that the entire 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 Thoroughbred. 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 December 31, 2015, approximately 21% of the net book value of our “property, plant, equipment, and mine development, net” reflected assets for which legal title has been transferred to Thoroughbred.

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 CO₂. CO₂is a “greenhouse gas,” the man-made emission of which is of major concern under any regulatory framework intended to control what is sometimes referred to “climate change.” 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. Such measures have also been introduced and passed at the state level. Passage of such comprehensive climate change or energy legislation could affect the demand for coal. Even in the absence of new federal legislation, the EPA has already begun to regulate greenhouse gas emissions under the CAA. The EPA has promulgated regulations requiring pre-construction and operating permits for greenhouse gas emissions from certain large stationary sources, including coal-fired

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power plants. In addition, the EPA also requires the monitoring and report of greenhouse gas emissions from certain sources, including underground coal mines.

Moreover, the EPA has proposed several regulations directly affecting coal-fired power plants, which in turn could have an adverse impact on the demand for coal and reduce our revenues. For example, the EPA recently proposed new regulations related to CO₂ emissions from existing, new and modified fossil fuel-fired electric utility generating power plants. Generally, the proposed rule for new or modified power plants establishes a performance standard based on 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. The proposal for existing coal-fired power plants focuses on establishing state-wide CO₂ emission rates rather than at the facility level. The EPA’s proposal allows states to choose a range of options for meeting the rule’s requirements. At this time, we cannot predict how states may choose to implement the EPA’s proposed rule, assuming it is adopted as proposed. If adopted, any of these proposed rules could negatively affect the demand for coal.

In addition, the permitting of new coal-fired power plants has also recently been contested by state regulators and environmental advocacy organizations due to concerns related to greenhouse gas emissions. 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. Any of the developments described above could have a material adverse effect on revenues. See Item 1 – “Business—Regulation and Laws—Climate Change.”

Extensive environmental laws and regulations 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.

Coal contains sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. The operations of coal consumers are subject to extensive environmental requirements, particularly with respect to air emissions. For example, the CAA and similar state and local laws extensively regulate the amount of SO₂, particulate matter, NOx, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, SO₂, NOx, toxic gases, and other air pollutants have been proposed or could become effective in coming years. In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices to decline and reduce the demand for our coal, thereby reducing our revenues.

Considerable uncertainty is associated with these air emissions initiatives, with many of these new initiatives being subject to review by federal or state agencies or the courts. Further, additional requirements are in the process of being developed. 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 plants, or reduced construction of new plants could have a material adverse effect on demand 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. For example, on December 19, 2014, the EPA issued a final rule concerning management of coal combustion residuals. This rule could 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 and prices received for our coal.

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 . Moreover, 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, which could negatively affect production and reduce revenues. Such changes could have a material adverse effect on our financial condition and results of operations. See “Business — Regulation and Laws” for more information about the various governmental regulations affecting us.

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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, recently, new regulations have been implemented, affirmed or proposed that have resulted in the retirement of coal-fired generators and have the potential to result in additional premature retirements. See Item 1 - “Business-Regulation and Laws.” These regulations and any similar future regulatory developments could result in significantly less expansion of scrubbed coal-fired electricity generating capacity than we anticipate. This in turn could mean that the strong increase in demand for relatively high-sulfur Illinois Basin coal we believe will occur in the future may not materialize or may not materialize as soon as it otherwise would. This could adversely affect the demand and prices received for our coal.

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 our 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 affect the permitting process, including court intervention. The slowing pace at which necessary permits are issued or renewed for new and existing mines has materially affected coal production, especially in Central Appalachia. Permitting by the Corps, the EPA and the Department of the Interior has become subject to “enhanced review” in recent years under both SMCRA and the CWA, and may become subject to new and expanded CWA, SMCRA and state counterpart regulation in the near future.

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 timeframes 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 or become difficult to obtain in the future if the EPA continues its enhanced review of CWA permit applications, if the CWR becomes effective and is implemented, if OSM’s SPR is enacted as a final rule, or other federal or state rule or policy changes, such as changes to water quality standards occur. 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 “Item 1 - Business-Regulation and Laws.”

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, including MSHA, 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 to reopen the mine. In the event that these agencies order the closing of our mines, certain of our coal sales contracts 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 obligations, incur capital expenditures to reopen the mines and/or negotiate settlements with the customers, which may result in price reductions, the reduction of commitments or the extension of time for delivery under the contracts or terminate the customers’ contracts at issue. 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:

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• limitations on land use;

• mine permitting and licensing requirements;

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

• management and disposal of materials generated by mining operations;

• storage, treatment and disposal of wastes;

• remediation of contaminated soil and water, including wetlands and groundwater;

• air quality standards;

• water pollution, including numeric and narrative water quality standards;

• protection of human health,


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

• protection of wetlands;

• discharge of materials into the environment;

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

• 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 in respect of these matters, we could be materially and adversely affected.

New legislation or administrative regulations or new interpretations or enforcement of existing laws and regulations 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 Item 1 - “Business-Regulation and Laws.”

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 consider the estimated current costs of reclamation and mine closure and apply inflation rates and third-party profit, as required. The third-party profit is an estimate of the approximate markup that would be charged by contractors for reclamation 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.

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Our operations may affect 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 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 amount.

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” (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 may affect our results or increase our costs or liabilities. Such legal and regulatory changes may include changes in:

• the processes for obtaining or renewing permits;

• the standards upon which permit terms and conditions are established;


•	regulations for the protection of water, air or land, including but not limited to enactment of the SPR, new water quality standards, implementation of the CWR, revisions to the MATS and CASPR rules, or new MACT, NESHAPS or NAAQS under the CAA;

• costs associated with providing health care benefits to employees;

• health and safety standards;

• accounting standards;

• taxation requirements; and

• competition laws.

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 Item 1 - “Business-Regulation and Laws.”

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

See Item 1 – “Business—Our Mining Operations” for specific information about our mining operations and see Item 13 – “Certain Relationships and Related-Party Transactions, and Director Independence” for specific information about our leases with related parties.

Coal Reserves

As of December 31, 2015, we controlled approximately 554 million tons of proven and probable coal reserves. Our coal reserve estimates were prepared from geological data assembled and analyzed by our staff of geologists and engineers. Our coal reserve estimates are based on data obtained from our drilling activities and other available geologic data and are updated to reflect past coal production and acquisitions of coal properties.

Our coal reserve estimates include reserves that can be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this economical and legal standard, we take into account, among other things, our potential ability or inability to obtain a mining permit, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices.

All of our proven and probable reserves are classified as thermal coal.

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The following tables provide a summary of information regarding our coal reserves as of December 31, 2015, unless otherwise noted.



		Clean Recoverable Coal(Proven and Probable Reserves)(1)				Production			Quality Specifications (As Received)(2)
						Year Ended December 31,
Mines (Commenced Operations)	Mining Method (3)	Proven Reserves	Probable Reserves	Total		2015	2014	2013	Heat Value (Btu/ Lb)	SO2 Content (Lbs/ MMBtu)
			(Tons in thousands)
Active mines
Midway (July 2008)(5)	S	12,962	1,002	13,964	(4)	1,063	1,293	1,310	11,423	4.9
Parkway Underground (April 2009)	U	6,011	2,822	8,833	(4)	1,107	1,125	1,347	11,760	4.8
East Fork (June 2009)(6)	S	2,583	543	3,126	(4)	21	—	—	11,078	7.8
Equality Boot (September 2010)	S	12,530	505	13,035	(4)	2,169	2,803	2,705	11,409	5.1
Lewis Creek (June 2011)	S	2,935	45	2,980	(4)	817	971	900	11,145	4.0
Kronos Underground (September 2011)	U	27,171	4,073	31,244	(7)	2,440	2,515	2,591	11,586	4.7
Lewis Creek Underground (March 2013)(8)	U	1,775	14	1,789	(4)	99	638	462	11,863	4.5
Survant Underground	U	38,888	20,420	59,308	(4)	358	—	—	11,944	4.4
Total active mines		104,855	29,424	134,279		8,074	9,345	9,315
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
Thoroughbred	S/U	146,873	51,250	198,123		—	—	—	11,754	4.7
Other	S/U	60,512	13,044	73,556	(9)	—	—	—	11,656	5.2
Total additional reserves		271,832	148,335	420,167		—	—
Total		376,687	177,759	554,446		8,074	9,345	9,315

(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)	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, 61.4% of the interests controlled by Armstrong Energy were leased from Thoroughbred as of December 31, 2015.


(5)	The Midway mine was temporarily idled in December 2015.


(6)	Warden and Kronos pits. Production at the Kronos pit ceased in August 2011 and at the Warden pit in December 2015.


(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 Thoroughbred and leased to Armstrong Energy (the Elk Creek Reserves).


(8)	Production at the Lewis Creek underground mine ceased in March 2015.

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(9)	Of these reserves, excluding an estimated 23.9 million tons of Elk Creek Reserves, 61.4% of the interests controlled by Armstrong Energy were leased from Thoroughbred as of December 31, 2015.



	Clean Recoverable Tons (Proven and Probable Reserves)(1)
	Owned	Leased	Total			Primary Transportation Method
	(In thousands)
Active Mines (Commenced Operations)
Midway (July 2008)(3)	13,964	—	13,964	(2	)	Rail, barge & truck
Parkway Underground (April 2009)	740	8,093	8,833	(2	)	Truck
East Fork (June 2009)(4)	2,648	478	3,126	(2	)	Rail, barge & truck
Equality Boot (September 2010)	13,035	—	13,035	(2	)	Barge
Lewis Creek (surface) (June 2011)	2,980	—	2,980	(2	)	Rail, barge & truck
Kronos Underground (September 2011)	29,157	2,087	31,244	(5	)	Rail, barge & truck
Lewis Creek Underground (March 2013)(6)	1,789	—	1,789	(2	)	Rail, barge & truck
Survant Underground (August 2015)	—	59,308	59,308	(2	)	Barge & truck
Total active mines	64,313	69,966	134,279

(1)


(2)	Of these reserves, 61.4% of the interests controlled by Armstrong Energy are leased from Thoroughbred as of December 31, 2015.


(3)	The Midway mine was temporarily idled in December 2015.


(4)	Warden and Kronos pits. Production at the Kronos pit ceased in August 2011 and at the Warden pit in December 2015.


(5)	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 Thoroughbred and leased to Armstrong Energy (the Elk Creek Reserves).


(6)	Production at the Lewis Creek underground mine ceased in March 2015.

Item 3. Legal Proceedings

We are involved from time to time in various lawsuits and claims arising in the ordinary course of business. Although the outcomes of these lawsuits and claims are uncertain, we do not believe any of them will have a material adverse effect on our business, financial condition or results of operations.

Item 4. Mine Safety Disclosures

Information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report on Form 10-K.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

There is no established public trading market for our common stock. The majority of the issued and outstanding common stock of Armstrong Energy, Inc. is held by members of management or Yorktown. See Item 12 — “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” As of March 1, 2016, there were approximately 22 beneficial holders of the common stock.

We have not issued a dividend to any of our equity holders since our inception. The indentures governing our Notes and our Revolving Credit Facility contain covenants that limit our ability to pay dividends. See Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Item 6. Selected Financial Data

The following table presents our selected historical consolidated financial and operating data for the periods indicated for Armstrong Energy, Inc. and its subsidiaries. The selected historical financial data for the years ended December 31, 2015, 2014, 2013, 2012, and 2011, and the balance sheet data as of December 31, 2015, 2014, 2013, 2012, and 2011, are derived from the audited consolidated financial statements of Armstrong Energy, Inc.

Historical results are not necessarily indicative of results we expect in future periods. The following selected financial data should be read in conjunction with Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K.



													Predecessor
	Year Ended December 31,
	2015⁽¹⁾			2014			2013			2012			2011
Results of Operations Data
Total revenues	$	360,900		$	441,833		$	415,282		$	382,109		$	299,270
Costs and expenses	494,499			438,289			405,370			375,461			291,335
Operating (loss) income	(133,599		)	3,544			9,912			6,648			7,935
Interest expense, net	(34,685		)	(33,134		)	(35,563		)	(19,200		)	(10,694		)
Other income (expense), net	5,486			758			579			(1,534		)	133
(Loss) gain on extinguishment of debt	—			—			—			(3,953		)	6,954
(Loss) income before income taxes	(162,798		)	(28,832		)	(25,072		)	(18,039		)	4,328
Income taxes	657			—			—			—			(856		)
Net (loss) income	(162,141		)	(28,832		)	(25,072		)	(18,039		)	3,472
Less: income (loss) attributable to non-controlling interest	—			—			—			—			7,448
Net loss attributable to common stockholders	$	(162,141	)	$	(28,832	)	$	(25,072	)	$	(18,039	)	$	(3,976	)

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													Predecessor
	Year Ended December 31,
	2015⁽¹⁾			2014			2013			2012			2011
Balance Sheet Data (at period end)
Total assets	$	387,240		$	532,447		$	543,553		$	560,309		$	507,908
Working capital (deficiency)	52,456			43,501			42,042			48,873			(30,629		)
Total long-term debt(2)	218,439			203,889			202,684			203,896			159,709
Total stockholders’ equity/(deficit)	(35,281		)	124,857			156,943			182,662			168,138
Other Data
Tons sold (unaudited)	7,791			9,419			9,266			8,521			7,030
Tons produced (unaudited)	8,074			9,345			9,315			8,663			6,642
Sales price per ton (unaudited)	$	46.32		$	46.91		$	44.82		$	44.84		$	42.57
Net cash provided by (used in):
Operating activities	$	36,243		$	41,145		$	32,944		$	30,769		$	48,174
Investing activities	(18,925		)	(24,437		)	(32,581		)	(46,524		)	(75,827		)
Financing activities	(9,219		)	(8,822		)	(8,863		)	56,307			39,132
Adjusted EBITDA(3) (unaudited)	68,483			61,760			58,156			50,854			41,601
Adjusted EBITDA is calculated as follows (unaudited):
Net (loss) income	$	(162,141	)	$	(28,832	)	$	(25,072	)	$	(18,039	)	$	3,472
Income taxes	(657		)	—			—			—			856
Depreciation, depletion and amortization	45,948			46,037			38,219			33,066			27,661
Asset retirement obligation expenses	3,277			2,099			2,267			3,743			4,005
Non-cash production royalty to related party	7,879			8,269			6,761			5,695			578
Interest expense, net	34,685			33,134			35,563			19,200			10,694
Asset impairment and restructuring charges	138,679			—			—			—			—
Non-cash stock compensation expense (income)	145			(74		)	418			697			1,383
Non-cash employee benefit expense	668			1,127			—			—			—
Loss on settlement of interest rate swap	—			—			—			1,409			—
Loss on deferment of equity offering	—			—			—			1,130			—
Loss (gain) on extinguishment of debt	—			—			—			3,953			(6,954		)
Non-cash charge related to non-recourse notes	—			—			—			—			217
Gain on deconsolidation	—			—			—			—			(311		)
	$	68,483		$	61,760		$	58,156		$	50,854		$	41,601


(1)	Due to the challenging market conditions, our 2015 results were negatively impacted. As a result, we recognized asset impairment and restructuring charges of $138.7 million. See Note 3, "Asset Impairment and Restructuring Charges," to our audited consolidated financial statements, included in Item 8 - "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K.


(2)	Amount does not include $128.8 million, $110.7 million, $106.3 million, $98.4 million and $71.0 million of certain long-term obligations to Thoroughbred as of December 31, 2015, 2014, 2013, 2012 and 2011, respectively, which are characterized as financing transactions due to our continuing involvement in the lease of the related land and mineral reserves.


(3)	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.

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

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.

Item 7. 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 Item 6 – “Selected Financial Data” and our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. This discussion and analysis contains forward-looking statements that involve 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 Item 1A – “Risk Factors.” We assume no obligation to update any of these forward-looking statements.

Overview

Armstrong Energy, Inc. (together with its subsidiaries, we or the Company) is a 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 2015 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 six mines, including three surface and three underground. We control approximately 554 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 coal blending and handling, and provide our customers with rail, barge and truck transportation options.

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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 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 December 31, 2015, we had multi-year coal supply agreements with remaining terms ranging from one to four years, and we are contractually committed to sell 5.6 million tons of coal in 2016.

For each of 2015 and 2014, we produced 8.1 million and 9.3 million tons of coal, respectively, and, during the same periods, we sold 7.8 million and 9.4 million tons of coal, respectively. For the year ended December 31, 2015, our revenue from coal sales was $360.9 million, and we generated an operating loss of $133.6 million, net loss of $162.1 million, and Adjusted EBITDA of $68.5 million. Our revenue, operating income, net loss and Adjusted EBITDA for the year ended December 31, 2014 were $441.8 million, $3.5 million, $28.8 million, and $61.8 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 state and federal severance 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 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 coal blending and handling and provide our customers with rail, barge and truck transportation options.

Business Developments

On October 28, 2015, Worker Adjustment and Retraining Notification (WARN) Act notices were delivered to employees of two mining operations, along with the two preparation plants that directly support those mining operations. The decision to rationalize production was made in response to persistent weakness in thermal coal demand, depressed price levels and increased government regulations. Following an evaluation of cost structures, including wages and benefits, as well as an assessment of forecasts for customer commitments and anticipated pricing, effective December 31, 2015, we temporarily idled the Midway surface mine, reduced operations to one section at the Parkway underground mine, and reduced the workforce at the related preparation plants. These mines shipped approximately 2.1 million tons of coal during 2015. We will continue to evaluate our operations and cost structure, and we will continue to take actions to respond quickly to changing and challenging market conditions, including a reduction of general and administrative (G&A) expenses and overhead costs throughout the Company.

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.

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

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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.

We define our coal sales price per ton, or average sales price, as total coal sales divided by tons sold. We evaluate the price we receive for our coal on an average sales price per ton basis to evaluate marketing efforts and for market demand and trend analysis. 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,
	2015		2014		2013
	(In thousands, except per ton amounts)
Tons of Coal Produced	8,074		9,345		9,315
Tons of Coal Sold	7,791		9,419		9,266
Average Sales Price Per Ton	$	46.32	$	46.91	$	44.82

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, selling and related expenses, 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 expenses, such as G&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,
	2015		2014		2013
	(In thousands, except per ton amounts)
Tons of Coal Sold	7,791		9,419		9,266
Average Sales Price Per Ton	$	46.32	$	46.91	$	44.82
Cost of Coal Sales Per Ton	$	36.31	$	38.46	$	36.25

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, asset retirement obligation expenses, non-cash production royalty to related party, asset impairment and restructuring charges, loss on settlement of interest rate swap, loss on deferment of equity offering, non-cash stock compensation expense (income), non-cash employee benefit expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt. Although Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, it 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 Item 6 – “Selected Financial 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 Affect Our Business

For the past three years, more than 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

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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, certain of our contracts 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 contain provisions that permit us to 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.

Certain of our multi-year coal supply agreements contain option provisions that give the customer the right to elect to purchase 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 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 provisions may affect our average sales price per ton of coal in any given month or similarly narrow window.

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 Item 1A – “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. According to the EIA, total coal consumption in the United States in 2015 decreased by approximately 108 million tons, or 11.8%, from 2014 levels. The decrease in U.S. domestic coal consumption during 2015 was primarily a function of decreased consumption in the electric power sector due to lower natural gas prices and an increase in retirements of coal fired power plants. However, according to the EIA, coal is expected to remain a major source for electric power generation for the foreseeable future.

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Results of Operations

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 Item 6 – “Selected Financial Data.”



	Year Ended December 31,
	2015			2014			2013
	(In thousands, except per share and per ton amounts)
Results of Operations Data
Total revenues	$	360,900		$	441,833		$	415,282
Costs and expenses:
Costs of coal sales	282,903			362,294			335,904
Production royalties to related party	7,879			8,269			7,811
Depreciation, depletion and amortization	45,948			46,037			38,219
Asset retirement obligation expenses	3,277			2,099			2,267
Asset impairment and restructuring charges	138,679			—			—
General and administrative expenses	15,813			19,590			21,169
Total costs and expenses	494,499			438,289			405,370
Operating (loss) income	(133,599		)	3,544			9,912
Interest expense, net	(34,685		)	(33,134		)	(35,563		)
Other income (expense), net	5,486			758			579
Loss before income taxes	(162,798		)	(28,832		)	(25,072		)
Income taxes	657			—			—
Net loss	(162,141		)	(28,832		)	(25,072		)
Less: income attributable to non-controlling interest	—			—			—
Net loss attributable to common stockholders	$	(162,141	)	$	(28,832	)	$	(25,072	)
Other Data (1)
Adjusted EBITDA (unaudited)	$	68,483		$	61,760		$	58,156
Adjusted EBITDA per ton sold (unaudited)	8.79			6.56			6.28

(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, asset retirement obligation expenses, non-cash production royalty to related party, asset impairment and restructuring charges, loss on settlement of interest rate swap, loss on deferment of equity offering, non-cash stock compensation expense (income), non-cash employee benefit 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 Item 6 – “Selected Financial Data” for a reconciliation of Adjusted EBITDA to net income (loss).

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Overview

We reported revenue of $360.9 million for the year ended December 31, 2015, compared to $441.8 million for the year ended December 31, 2014. Coal sales decreased 17.3% to 7.8 million tons in 2015, compared to 9.4 million tons in the prior year. Our average sales price per ton in the year ended December 31, 2015 totaled $46.32 per ton, as compared to $46.91 per ton for the prior year. Our net loss and Adjusted EBITDA for 2015 totaled $162.1 million and $68.5 million, respectively, as compared to net loss and Adjusted EBITDA for 2014 of $28.8 million and $61.8 million, respectively.

Coal Production, Sales Volume, and Sales Price per Ton

Our coal production in 2015 of approximately 8.1 million tons decreased from production levels in 2014 of 9.3 million tons. For the years ended December 31, 2015 and 2014, we sold 7.8 million tons and 9.4 million tons, respectively. The decrease in overall production and corresponding decline in sales volumes is directly related to the deteriorating market demand driven by strict governmental regulations, increased competition from natural gas, mild weather in the second half of 2015, and

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oversupply in the domestic coal market. Partially offsetting the production decreases was the addition of the Survant Underground mine in August 2015, which produced 0.4 million tons during the year.

Our average sales price per ton decreased to $46.32 for the year ended December 31, 2015, from $46.91 for 2014. The per ton decrease in 2015 is primarily due to unfavorable transportation adjustments included as a component of the price in certain of our long-term coal supply agreements as a result of declining diesel prices, partially offset by annual price increases on certain of our multi-year coal supply agreements.

Revenue

Our coal sales revenue for the year ended December 31, 2015 decreased by $80.9 million, or 18.3%, to $360.9 million, as compared to $441.8 million for the year ended December 31, 2014. This decrease is primarily attributable to an unfavorable volume variance of approximately $76.3 million year-over-year due to production and delivery issues during the first quarter of 2015 resulting from the inclement weather experienced in western Kentucky and a decline in customer demand resulting in the delay of shipments during the second half of the year. In addition, we experienced an unfavorable price variance of approximately $4.6 million driven primarily by unfavorable transportation adjustments.

Cost of Coal Sales

Cost of coal sales decreased 21.9% to $282.9 million in the year ended December 31, 2015, from $362.3 million in 2014. The decline is primarily attributable to selling 1.6 million tons less coal during the year ended December 31, 2015, as compared to 2014. On a per ton basis, our cost of coal sales decreased during the year ended December 31, 2015, as compared to 2014, from $38.46 per ton to $36.31 per ton. This decrease in the per ton amounts is due to favorable repair and maintenance costs experienced at our underground mines, lower blasting costs incurred by our surface mines, lower fuel costs and better mining conditions experienced during the year ended December 31, 2015, partially offset by the impacts of adverse weather conditions that occurred in the first quarter of 2015.

Production Royalty to Related Party

Production royalty to related party was $7.9 million and $8.3 million, respectively, for the years ended December 31, 2015 and 2014, respectively. This amount relates to production royalties earned by our affiliate, Thoroughbred, from sales originating from our Kronos underground mine (where the mineral reserves are leased directly from Thoroughbred). Sales volume declines experienced at our Kronos underground mine during the year ended December 31, 2015, along with slightly lower average prices in the current year, resulted in the decline in the production royalty earned by Thoroughbred in the year ended December 31, 2015, as compared to 2014.

Depreciation, Depletion and Amortization

DD&A expense decreased by $0.1 million, or 0.2%, to $45.9 million during the year ended December 31, 2015, as compared to 2014. The slight decrease is primarily due to lower depletion expense associated with reduced mine output in 2015 and lower DD&A in the fourth quarter of 2015 from the reduced depreciable base subsequent to the impairment charge recognized in the third quarter of 2015, mostly offset by the accelerated depreciation of the capitalized mine development costs associated with the Lewis Creek underground mine resulting from the closure of the mine in the first quarter of 2015 and the impact of the revision during the first quarter of 2015 to the useful lives of a portion of the machinery and equipment associated with certain of our surface mines.

Asset Retirement Obligation Expenses

Asset retirement obligation expenses increased by $1.2 million, or 56.1%, to $3.3 million during the year ended December 31, 2015, as compared to 2014. The increase is primarily attributable to changes in asset retirement cost estimates based on revisions to discount rates, reserve valuations and projected mine lives.

Asset Impairment and Restructuring Charges

Asset impairment and restructuring charges were $138.7 million for the year ended December 31, 2015 and consisted of long-lived asset impairments of $137.7 million related to mineral rights and other property, plant, and equipment and employee termination benefits of $1.0 million. Refer to Note 3, “Asset Impairment and Restructuring Charges,” to our audited consolidated financial statements, included in Item 8 - “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K for further information regarding the nature and composition of those chargessoud.

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General and Administrative Expenses

G&A expenses were $15.8 million for the year ended December 31, 2015, which was $3.8 million, or 19.3%, lower than the year ended December 31, 2014. The decrease in the year ended December 31, 2015, as compared to 2014, is due primarily to lower labor and benefits expense and non-income related taxes.

Interest Expense, Net

Interest expense, net is derived from the following components:



	Year Ended December 31,
	2015			2014
	(In thousands)
11.75% Senior Secured Notes due 2019	$	23,500		$	23,500
Senior Secured Credit Facility	—			—
Long-term obligation to related party	10,049			7,993
Other, net	3,123			2,614
Capitalized interest	(1,987		)	(973		)
Total	$	34,685		$	33,134

Interest expense, net was $34.7 million for the year ended December 31, 2015, as compared to $33.1 million for the year ended December 31, 2014. The increase is principally attributable to an increase in the effective interest rate on the long-term obligation to related party due to revisions in the mine plan at December 31, 2015 and the increase in the principal balance of the long-term obligation to related party from the completion of the reserve transfers to Thoroughbred in October 2014 and May 2015, which increased the principal balance on the obligation by $6.1 million and $18.2 million, respectively. The year-over-year increase in interest expense was partially offset by a higher amount of capitalized interest during the year ended December 31, 2015, as compared to 2014.

Other, Net

Other, net for the year ended December 31, 2015 and 2014 was $5.5 million and $0.8 million, respectively. The increase is due to a $4.5 million refund during the second quarter of 2015 for a portion of Kentucky sales and use taxes paid on the purchase of certain energy and energy producing fuels for the period of 2008 through 2013.

Net Loss

Net loss for the year ended December 31, 2015 was $162.1 million, as compared to $28.8 million for the same period of 2014. The increase in net loss is largely due to the asset impairment and restructuring charges of $138.7 million, lower gross margin of $1.5 million, and higher interest expense of $1.6 million, partially offset by the refund of certain previously paid Kentucky sales and use taxes during the second quarter of 2015 and lower G&A expenses of $4.5 million and $3.8 million, respectively.

Adjusted EBITDA

Our Adjusted EBITDA for the year ended December 31, 2015 was $68.5 million, as compared to $61.8 million for the year ended December 31, 2014. The increase in Adjusted EBITDA resulted primarily from the $4.5 million Kentucky sales and use tax refund during the second quarter of 2015 and lower G&A costs during the year, exclusive of stock compensation expense.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Overview

We reported revenue of $441.8 million for the year ended December 31, 2014, compared to $415.3 million for the year ended December 31, 2013. Coal sales increased 1.7% to 9.4 million tons in 2014, compared to 9.3 million tons in the prior year. Our average sales price per ton in the year ended December 31, 2014 totaled $46.91 per ton, as compared to $44.82 per ton for the prior year. Our net loss and Adjusted EBITDA for 2014 totaled $28.8 million and $61.8 million, respectively, as compared to net loss and Adjusted EBITDA for 2013 of $25.1 million and $58.2 million, respectively.

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Coal Production, Sales Volume, and Sales Price per Ton

Our coal production in 2014 remained consistent with that of 2013 at approximately 9.3 million tons. We completed development of the Lewis Creek underground mine in mid-2013 and experienced a modest increase in tons produced year over year. Subsequent to completion, the mine has experienced significant operating difficulties, which has kept the mine from reaching full capacity and ultimately led to our abandonment of the mine plan. Production increases also occurred at the Midway and Equality Boot mines from improved stripping ratios experienced in 2014. Offsetting the production increases were declines at the Parkway and Kronos underground mines due to poor geological conditions.

For the years ended December 31, 2014 and 2013, we sold 9.4 million tons and 9.3 million tons, respectively. The increase is due to increased spot sales year over year.

Our average sales price per ton increased to $46.91 for the year ended December 31, 2014, from $44.82 for 2013. The per ton increase is due to favorable customer mix and annual price increases on our multi-year coal supply agreements.

Revenue

Our coal sales revenue for the year ended December 31, 2014 increased by $26.6 million, or 6.4%, to $441.8 million, as compared to 2013. This increase is primarily attributable to a favorable price variance of approximately $19.7 million due to a favorable customer mix and higher year-over-year contract prices. We also experienced a favorable volume variance of approximately $6.9 million due to the sale of 0.2 million additional tons from increased spot sales in 2014.

Cost of Coal Sales

Cost of coal sales increased 7.9% to $362.3 million in the year ended December 31, 2014, from $335.9 million in 2013. On a per ton basis, our cost of coal sales increased during the year ended December 31, 2014, compared to 2013, from $36.25 per ton to $38.46 per ton. This increase is due to lower productivity at the Parkway and Kronos underground mines driven by poor geological conditions and production inefficiencies encountered at the Lewis Creek underground mine subsequent to the completion of development of the mine, partially offset by favorable mining conditions at our Midway and Equality Boot surface mines in 2014.

Production Royalties to Related Party

Production royalties to related party increased $0.5 million, or 5.9%, to $8.3 million for the year ended December 31, 2014, as compared to $7.8 million in 2013. The increase in production royalties earned by Thoroughbred is due to an increase in sales originating from our Kronos underground mine (where the mineral reserves are leased directly from Thoroughbred) during 2014, as compared to 2013.

Depreciation, Depletion and Amortization

DD&A expenses increased by $7.8 million, or 20.5%, during the year ended December 31, 2014 to $46.0 million, as compared to $38.2 million in 2013. The increase is primarily due to the accelerated depreciation of the capitalized mine development costs associated with the Lewis Creek underground mine resulting from the planned closure of the mine in the first quarter of 2015. In addition, depletion and amortization expenses were slightly higher as a result of the higher production in 2014.

Asset Retirement Obligation Expense

Asset retirement obligation expense decreased by $0.2 million, or 7.4%, to $2.1 million in the year ended December 31, 2014, as compared to 2013. The decrease is primarily attributable to changes in asset retirement cost estimates based on revisions to discount rates, reserve valuations and projected mine lives.

General and Administrative Expenses

G&A expenses were $19.6 million for the year ended December 31, 2014, which was $1.6 million, or 7.5%, lower than the year ended December 31, 2013. The decrease is primarily due to lower expenses for legal and other professional services ($0.9 million), compensation and benefits ($0.2 million), and share-based compensation ($0.5 million) from the decline in unvested shares and the forfeiture of certain grants and the reversal of the associated expense during 2014.

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Interest Expense, Net

Interest expense, net is derived from the following components:



	Year Ended December 31,
	2014			2013
11.75% Senior Secured Notes due 2019	$	23,500		$	23,500
Senior Secured Credit Facility	—			—
Long-term obligation to related party	7,993			11,029
Other, net	2,614			2,675
Capitalized interest	(973		)	(1,641		)
Total	$	33,134		$	35,563

Interest expense, net decreased $2.4 million, or 6.8%, to $33.1 million for the year ended December 31, 2014, as compared to $35.6 million for the year ended December 31, 2013. The decrease is principally attributable to a decrease in the effective interest rate on the long-term obligation to related party due to revisions in the mine plan at December 31, 2013. The decline was partially offset by the increase in the principal balance of the long-term obligation to related party from the closing of the reserve transfers to Thoroughbred in April 2013 and October 2014, which increased the principal balance on the obligation by $4.9 million and $6.1 million, respectively, and a lesser amount of capitalized interest in the current year due to a decline in capital expenditures year over year.

Other, Net

Other, net totaled income of $0.8 million for the year ended December 31, 2014, as compared to income of $0.6 million for the year ended December 31, 2013. The amount relates primarily to ancillary income from timber, scrap, and crop sales recognized in each of the respective years.

Net Loss

Net loss for the year ended December 31, 2014 was $28.8 million, as compared to $25.1 million for 2013. The increase in the loss is largely due to lower operating income driven from the accelerated depreciation of the capitalized mine development costs associated with the planned closure of the Lewis Creek underground mine, partially offset by higher gross margin and reduced G&A expenses. In addition, the decline in interest expense in 2014 from a lower effective interest rate favorably affected our overall results.

Adjusted EBITDA

Our Adjusted EBITDA for the year ended December 31, 2014 was $61.8 million, or $6.56 per ton, as compared to $58.2 million, or $6.28 per ton, for the year ended December 31, 2013. The increase resulted primarily from higher gross margin as a result of favorable price and volume variances in 2014, as well as reduced overall G&A expenses, as compared to 2013.

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, reclamation obligations, and to service our debt. Historically, our primary sources of liquidity to meet these needs have been cash generated by our operations, and to a lesser extent, borrowings under our credit facilities and contributions from our equity holders.

The principal indicators of our liquidity are our cash on hand and availability under our Revolving Credit Facility. As of December 31, 2015, our available liquidity was $84.3 million, comprised of cash on hand of $67.6 million and $16.7 million available under our Revolving Credit Facility. We had no borrowings outstanding under the Revolving Credit Facility as of December 31, 2015 and have not been required to use it as a source of liquidity since its inception.

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As a result of the weak market conditions and depressed coal prices, we have undertaken steps to adequately preserve our liquidity and manage operating costs, including efficiently controlling capital expenditures. During 2015, we undertook steps to enhance our financial flexibility and reduce cash outflows in the near term, including a streamlining of our cost structure and anticipated reductions in production volumes and capital expenditures. We believe that existing cash balances, cash generated from operations and borrowing capacity available under our Revolving Credit Facility will be sufficient to meet working capital requirements, anticipated capital expenditures and debt service requirements in 2016. If market conditions do not improve, we expect to continue to experience operating losses, which would adversely affect our liquidity in the future. As a result, we could be forced to take further action, including additional restructurings and rationalization of production volumes and capital expenditures.

In addition to the above, our ability to access the capital markets on acceptable economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, prevailing commodity prices and other macroeconomic factors outside of our control. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to significantly reduce our spending and to alter our business plan. We may also be required to consider other options, which, depending on the urgency of our liquidity constraints, may be required to be pursued at an inopportune time.

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, fund planned capital expenditures, and 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.

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



	December 31,
Type	2015		2014
11.75% Senior Secured Notes due 2019	$	195,419	$	194,570
Other	23,020		9,319
	218,439		203,889
Less: current maturities	8,402		4,929
Total long-term debt	$	210,037	$	198,960

Senior Secured Notes due 2019

On December 21, 2012, we completed the $200.0 million Notes offering. The Notes were issued at an original issuance discount (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 December 31, 2015 and 2014, the unamortized OID was $4.6 million and $5.4 million, respectively. We incurred $8.4 million of deferred financing fees related to the Notes, which have been capitalized and are being 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, the Notes were redeemable 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.

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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). 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 (i) incur additional indebtedness or issue preferred equity; (ii) pay dividends or distributions on or purchase our stock or our restricted subsidiaries’ stock; (iii) make certain investments; (iv) use assets as security in other transactions; (v) create guarantees of indebtedness by restricted subsidiaries; (vi) enter into agreements that restrict dividends, distributions, or other payment by restricted subsidiaries; (vii) sell certain assets or merge with or into other companies; and (viii) enter into transactions with affiliates.

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, 2015 and 2014, there were no borrowings outstanding under the Revolving Credit Facility, and we had $16.7 million and $15.9 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 12 months then ended, greater than 1.0 to 1.0. The fixed charge coverage ratio is defined as the ratio of consolidated EBITDA to fixed charges, which includes the sum of unfinanced capital expenditures, scheduled principal payments on indebtedness, cash interest payments, dividends, and cash taxes.

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.

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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.

Cash Flows

The following table reflects cash flows for the applicable periods:



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Net cash provided by (used in):
Operating Activities	$	36,243		$	41,145		$	32,944
Investing Activities	$	(18,925	)	$	(24,437	)	$	(32,581	)
Financing Activities	$	(9,219	)	$	(8,822	)	$	(8,863	)

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Net cash provided by operating activities was $36.2 million for the year ended December 31, 2015, a decrease of $4.9 million from net cash provided by operating activities of $41.1 million for the same period of 2014. Operating results were negatively impacted during the year due to a decline in gross margin resulting primarily from lower shipments during this year, as compared to 2014. Substantially offsetting this decline is a reduction in G&A expenses from lower labor and benefits expense. In addition, operating results were favorably impacted from the receipt of a Kentucky sales and use tax refund totaling approximately $4.5 million during the second quarter of 2015, which is included as a component of Other, net in the audited consolidated statement of operations. Positively impacting cash flows from operations for the year ended December 31, 2015 was an increase in the net related party liabilities of $16.3 million due to the deferment of amounts owed to our affiliate, Thoroughbred, including interest and royalties earned on leased reserves. Negatively impacting operating cash flows was an increase in inventory due to the timing of shipments and a decrease in accounts payable and accrued and other liabilities due to the timing of payments. Cash flows from operations for the year ended December 31, 2014 were positively impacted by a decrease in accounts receivable and inventory resulting from reduced production and shipments during the fourth quarter of 2014, as well as an increase in net related party liabilities of $14.8 million due to the deferment of amounts owed to Thoroughbred. Negatively impacting operating cash flows was an increase in other non-current assets during the year ended December 31, 2014 due to an increase in collateral posted against outstanding surety bonds, which are used to secure the performance of our reclamation obligations.

Net cash used in investing activities decreased $5.5 million to $18.9 million for the year ended December 31, 2015, compared to $24.4 million for 2014. The current year investment is primarily attributable to capital expenditures for equipment and mine development associated with the opening of the Survant underground mine at our Parkway complex, whereas the prior year investment is attributable to capital expenditures to maintain our existing fixed assets and initial spending on the development of the Survant underground mine.

Net cash used in financing activities was $9.2 million for the year ended December 31, 2015, as compared to net cash used in financing activities of $8.8 million for the year ended December 31, 2014. The current year and prior year activity relates primarily to scheduled capital lease and other long-term debt payments.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Net cash provided by operating activities was $41.1 million for the year ended December 31, 2014, an increase of $8.2 million from net cash provided by operating activities of $32.9 million for 2013. We experienced a decrease in operating income in 2014 largely driven by the increase in DD&A expense from the accelerated depreciation of the capitalized mine development costs associated with the planned closure of the Lewis Creek underground mine, which increased DD&A expense by $6.3 million in 2014, as compared to 2013. Partially offsetting the increase in DD&A expense was an increase in gross margin driven by the increase in sales volume and pricing, as well as the decline in G&A and interest expense. Positively impacting cash flows from operations for the year ended December 31, 2014 was a decrease in accounts receivable and inventory resulting from reduced production and shipments during the fourth quarter of 2014, as well as an increase in net related party liabilities of $14.8 million due to the deferment of amounts owed to our affiliate, Thoroughbred, including interest and royalties earned on leased reserves. Negatively impacting operating cash flows was an increase in other non-current assets during 2014 due to an increase in collateral posted against outstanding surety bonds, which are used to secure the performance

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of our reclamation obligations. Positively impacting cash flows from operations for the year ended December 31, 2013 was an increase in accounts payable and accrued liabilities of $3.3 million and an increase in amounts due to related party resulting primarily from an increase in royalties earned by Thoroughbred. Negatively impacting operating cash flows was an increase in inventory experienced during 2013 due to an increase in coal inventory and materials and supplies on hand resulting from the development of the Lewis Creek underground mine.

Net cash used in investing activities decreased $8.2 million to $24.4 million for the year ended December 31, 2014, compared to $32.6 million for 2013. The 2014 investment was largely attributable to capital expenditures associated with maintaining our existing fixed assets and for the development of the Survant underground mine at our Parkway mine complex, whereas the 2013 investment relates primarily to capital expenditures for the completion of the Lewis Creek underground mine.

Net cash used in financing activities was $8.8 million for the year ended December 31, 2014, as compared to net cash used in financing activities of $8.9 million for the year ended December 31, 2013. The 2014 and 2013 activity relates primarily to scheduled capital lease and other long-term debt payments.

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, 2015:



	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)	$	318,945	$	32,906	$	59,876	$	226,163	$	—
Long-term obligation to related party(1)	485,589		6,878		12,894		11,989		453,828
Operating lease obligations	10,464		5,595		4,774		95		—
Capitalized lease obligations (principal and interest)	2,601		2,033		568		—		—
Purchase obligations	303		303		—		—		—
Total	$	817,902	$	47,715	$	78,112	$	238,247	$	453,828

(1)

Long-term obligation to related party is an obligation associated with a financing arrangement with Thoroughbred. 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 2016, we are deferring the payment of any production royalty amounts due to Thoroughbred. In consideration for granting the option to defer these payments, we granted to Thoroughbred 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 and safety regulations. Our anticipated total capital expenditures for 2016 are estimated to be within a range of $8.0 million to $12.0 million. Management anticipates funding 2016 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 our financial condition and results of operations, as well as prevailing market conditions and several other factors over which we have limited control.

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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.

During the third quarter of 2015, we completed development of the Survant underground mine at our Parkway complex to extract coal from the West Kentucky #8 seam. Annual production capacity at the mine is eventually expected to be expanded to approximately 2.4 million tons. Capitalized development costs for the new mine totaled approximately $25.2 million.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements, which are not reflected in our consolidated balance sheets. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as surety bonds and performance bonds. In our past, no claims have been made against these financial instruments. 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 December 31, 2015, we had approximately $32.5 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $6.1 million of cash posted as collateral.

Related-Party Transactions

For information regarding our related-party transaction, see Note 13, “Related-Party Transactions,” to our audited consolidated financial statements, included in Item 8 — “Financial Statements and Supplementary Data” of this Annual Report of Form 10-K.

Critical Accounting Policies and Estimates

Our consolidated financial statements are prepared in accordance with GAAP. In connection with the preparation of our consolidated financial statements, we are required to make assumptions and estimates about future events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expenses and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time our consolidated financial statements are prepared. On a regular basis, we review the accounting policies, assumptions, estimates and judgments to ensure that our consolidated financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ from our assumptions and estimates, and such differences could be material.

Our significant accounting policies are discussed in Note 2, “Summary of Significant Accounting Policies,” to our audited consolidated financial statements, included in Item 8 – “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K. We believe the following accounting estimates are the most critical to aid in fully understanding and evaluating our reported financial results, and they require our most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.

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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. Our reserve estimates are based on engineering, economic and geological data assembled by our staff of geologists and engineers. 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 affected. Coal reserve values are reviewed annually, at a minimum, for consideration in our consolidated financial statements.

Impairment of Long-Lived Assets

We evaluate our long-lived assets used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition.

If there is an indication the carrying amount of an asset may not be recovered, the asset is evaluated by management where changes to significant assumptions are reviewed. Individual assets are grouped for impairment review purposes based on the lowest level for which there is identifiable cash flows that are largely independent of the cash flows of other groups of assets. When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, we must determine the fair value for the assets in question in accordance with the applicable fair value accounting guidance. Once the fair value is determined, the appropriate impairment loss is recorded based on the difference between the carrying amount of the assets and their respective fair values.

Due to the prolonged weakness in the U.S. coal markets, in the third quarter of 2015, we performed a comprehensive review of our current mining operations as well as potential future development projects to ascertain any potential impairment losses. We recorded an asset impairment charge of $137.7 million for the year ended December 31, 2015. Refer to Note 3, “Asset Impairment and Restructuring Charges,” to our audited consolidated financial statements, included in Item 8 - “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K. No impairment charges were recorded in 2014 and 2013.

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, 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

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currently estimated. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled. We expect our actual cost to reclaim our properties will be less than the expected cash flows used to determine the asset retirement obligation. However, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the years ended December 31, 2015, 2014, and 2013 was $3.3 million, $2.1 million, and $2.3 million, respectively. At December 31, 2015 and 2014, our balance sheets reflected asset retirement obligation liabilities of $14.1 million and $17.7 million, respectively, including amounts classified as a current liability. See Note 16 to our audited consolidated financial statements for additional details regarding our asset retirement obligations, included in Item 8 – “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K.

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. See Note 17 to our audited consolidated financial statements for additional details regarding our accounting for income taxes, included in Item 8 – “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K.

Based on our cumulative loss position and after evaluating other available evidence, including the scheduled reversals of our deferred tax assets and deferred tax liabilities, we have concluded a valuation allowance is necessary for the excess of deferred tax assets over deferred tax liabilities.

We anticipate that until we re-establish a pattern of continuing profitability, we will not recognize any material income tax expense or benefit in our statement of operations for future periods, as pretax profits or losses generally will generate tax effects that will be offset by decreases or increases in the valuation allowance with no net effect on the statement of operations. If a pattern of continuing profitability is re-established and we conclude that it is more likely than not that deferred income tax assets are realizable, we will reverse any remaining valuation allowance which will result in the recognition of an income tax benefit in the period that it occurs.

Long-Term Obligation to Related Party

We have entered into certain transactions with our affiliate, Thoroughbred, whereby we have sold an undivided interest in certain of our land and mineral reserves and subsequently entered into a lease agreement to mine the acquired mineral reserves in exchange for a production royalty. Due to our continuing involvement in the land and mineral reserves transferred, these transactions have been accounted for as financing arrangements and a long-term obligation has been established that is being amortized at an annual rate of 7% of the estimated gross revenue generated from the sale of the coal originating from the leased mineral reserves. The effective interest rate of the obligation is based on various estimates in future pricing and production quantities within our mine plans and is adjusted prospectively, as significant changes in our mine plans occur. As of December 31, 2015, the effective interest on the long-term obligation to related party was 5.0%. See Note 13 to our audited consolidated financial statements for additional details regarding our related party obligations, included in Item 8 – “Financial Statements and Supplementary Data,” of this Annual Report on Form 10-K.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

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 have chosen 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.

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In February 2016, the Financial Accounting Standards Board (FASB) issued updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are currently evaluating the effect of this update on our consolidated financial statements.

In November 2015, the FASB issued guidance that eliminates the requirement to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent. The new guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted. We adopted this standard as of December 31, 2015. While the adoption of this guidance impacted our balance sheet disclosure, it did not affect our results of operations or cash flows.

In April 2015, the FASB issued guidance requiring an entity to present debt issuance costs on the balance sheet as a direct deduction from the related debt liability as opposed to an asset. Amortization of the costs will continue to be reported as interest expense. The update is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued, and the new guidance would be applied retrospectively to all prior periods presented. The adoption of this standard update is not expected to have a material impact on our consolidated financial statements.

In August 2014, the FASB issued guidance on management’s responsibility in evaluating, at each annual and interim reporting period, whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early adoption permitted.

In May 2014, the FASB issued a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The standard requires revenue to be recognized when promised goods or services are transferred to a customer in an amount that reflects the consideration expected in exchange for those goods or services. The standard permits the use of either the full retrospective or modified retrospective transition method. This guidance is effective for annual and interim reporting periods beginning after December 15, 2017, with early adoption permitted to the original effective date of December 15, 2016. We are currently evaluating the impact of this new pronouncement on our financial statements.

Item 7A. 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.

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 negatively impacted our results of operations by $0.7 million for the year ended December 31, 2015. A hypothetical increase of 10% in steel prices would have negatively impacted our results of operations by $1.7 million for the year ended December 31, 2015. A hypothetical increase of 10% in explosives prices would have negatively impacted our results of operations by $1.2 million for the year ended December 31, 2015.

Credit Risk

Most of our coal sales are 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

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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.

Seasonality

Item 8. Financial Statements and Supplementary Data

The report of independent registered public accounting firm and the consolidated financial statements required by this Item are set forth on pages F-1 through F-34 of this report and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountant on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Our management, including our Chief Executive Officer and Chief Financial Officer, reviewed and evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2015. Based upon such review and evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the date of such evaluation to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with GAAP. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework). Based on our evaluation under this framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2015.

Changes in Internal Control over Financial Reporting

During the fourth quarter of 2015, there has been no change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

Set forth below are the names, ages and positions of our executive officers and directors as of March 1, 2016. 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	74	Executive Chairman (Class II)
Martin D. Wilson	54	President, Chief Executive Officer, and Director (Class I)
Kenneth E. Allen	69	Executive Vice President, Chief Operating Officer, and Director (Class I)
Jeffrey F. Winnick	41	Vice President and Chief Financial Officer
Anson M. Beard, Jr.	79	Director (Class I)
James C. Crain	67	Director (Class III)
Richard F. Ford	79	Director (Class III)
Bryan H. Lawrence	73	Director (Class III)
Greg A. Walker	60	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 2018, the term of our Class II directors expires in 2016, and the term of our Class III directors expires in 2017.

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. From 2011 through May 2015, Mr. Armstrong served as our Chairman and Chief Executive Officer. In May 2015, Mr. Armstrong became Executive Chairman of the Board. Previously, Mr. Armstrong worked for the Morgan Guaranty Trust Company and was elected Assistant Treasurer in 1967. He subsequently spent ten 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 (Arch Mineral), 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, Inc. (D&K). Mr. Armstrong served as D&K’s Chief Executive Officer from 1987 to 2005. D&K became a public company in 1992 and was acquired by McKesson Corporation in 2005. Mr. Armstrong served for nine 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. From 2011 to July 2014, Mr. Wilson was our President. From July 2014 to May 2015, he served as our President and Chief Commercial Officer. In May 2015, Mr. Wilson was appointed President and Chief Executive Officer. From 1988 until 2005, Mr. Wilson served as President, Chief Operating Officer, and Director of D&K. From 1985 to 1988, Mr. Wilson was employed by KPMG Peat Marwick. Mr. Wilson served for nine years as a member of the Board of Trustees of the St. Louis College of Pharmacy, as well as previously served as a Director of Healthcare Distribution Management Association. The board selected Mr. Wilson to serve as a director because of his experience in finance, operations, commercial transactions and public company management.

Kenneth E. Allen—Mr. Allen served as our Predecessor’s Vice President of Operations from 2007 until 2011. From 2011 to July 2014, Mr. Allen was our Executive Vice President of Operations. Since that time, he has served as our Executive Vice President and Chief Operating Officer. In December 2013, Mr. Allen was also named Chief Operating Officer of Armstrong Coal Company, a wholly-owned subsidiary of Armstrong Energy. Mr. Allen was elected to our board in May 2015. He started his career with Peabody Coal Company in 1967 and has more than 40 years of experience in the coal industry. In 1971, he

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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 Corporation. Mr. Allen is Chairman of the Upper Pond River Conservancy District, Vice Chairman of the Kentucky Reclamation Guaranty Fund Commission, a member of the Kentucky Workforce Investment Board of Directors and the Madisonville-Hopkins County Economic Development 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 past Chairman and member of the Executive Board of the Western Kentucky Coal Association. The board selected Mr. Allen to serve as a director because of his vast knowledge of the coal industry and experience in operations.

Jeffrey F. Winnick - Mr. Winnick served as our Vice President and Controller from 2011 to September 2015, at which time he was appointed Vice President and Chief Financial Officer. Prior to joining the Company, Mr. Winnick was employed by Ernst & Young, LLP, an international public accounting firm, for over 13 years. Mr. Winnick is a Certified Public Accountant.

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. 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 more than 35 years, both as an attorney and as an executive officer. In July 2013, Mr. Crain retired as President of Marsh Operating Company (Marsh), an investments management company, a position he held since 1989. Mr. Crain currently serves as an adviser to Marsh and is a private investor. Before joining Marsh in 1984, Mr. Crain was a partner in the law firm of Jenkens & Gilchrist. Mr. Crain is a director of Enlink Midstream, LLC, a midstream natural gas company, and Approach Resources, Inc., an independent oil and natural gas company. Mr. Crain was also formerly a director of Crosstex Energy, Inc. and Crosstex Energy, GP, LLC, midstream natural gas companies, GeoMet, Inc., a natural gas exploration and production 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 committee of Barry-Wehmiller Company. Mr. Ford is also currently a management consultant to Centene Corp. Until 2012, Mr. Ford served as a director of Stifel Financial Corp. 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. Mr. Lawrence 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. (Dillon Read) 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 Hallador Energy Company, Carbon Natural Gas Company, Star Gas Partners, L.P., and Approach Resources, Inc. (each a U.S. publicly traded company) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence was a director of Crosstex Energy, Inc. and Crosstex Energy GP, LLC until their combination with substantially all of Devon Energy Corporation’s midstream assets to form EnLink Midstream, LLC and EnLink Midstream Partners, LP in March 2014. During the past five years, Mr. Lawrence has also been a director of Winstar Resources Ltd. and Compass Petroleum, Ltd., Canadian oil and gas companies. Mr. Lawrence serves on our board of directors because of his significant knowledge of all aspects of the energy industry.

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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. Mr. Walker 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 were 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. From 2007 through 2010, he served as an appointee from the United States to the Coal Industry Advisory Board, an international advisory panel to the International Energy Administration with respect to matters regarding the production, use and demand for coal on a global basis. The board selected Mr. Walker to serve as a director because of his specialized knowledge of the coal and energy industry and applicable regulations, as well as his experience in public company management.

Board of Directors and Board Committees

Our board currently consists of eight 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.

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.

Audit Committee Report

The responsibilities of the audit committee are provided in its charter, which has been approved by the board of directors of the Company.

In fulfilling its oversight responsibilities with respect to the December 31, 2015 financial statements, the audit committee, among other things, has:


•	reviewed and discussed with management the Company’s audited financial statements as of and for the fiscal year ended December 31, 2015, including a discussion of the quality and acceptability of our financial reporting and internal controls;

•

discussed with the Company’s independent registered public accounting firm, who is responsible for expressing an opinion on the conformity of those audited financial statements with accounting principles generally accepted in the United States of America, its judgment as to the quality, not just the acceptability, of the accounting principles utilized, the reasonableness of significant accounting judgments and estimates and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards, including Statement on Auditing Standards No. 61, Communication with Audit Committees, as amended, by the Public Company Accounting Oversight Board in Rule 3200T;

•

discussed with the Company’s independent registered public accounting firm its independence from management and the Company, received and reviewed the written disclosures in the letter from the Company’s independent registered public accounting firm as required by the Public Company Accounting Oversight Board, and considered the compatibility of non-audit services with the Company’s independent registered public accounting firm’s independence; and

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•	discussed with the Company’s independent registered public accounting firm the overall scope and plans for its audit.

Based on the reviews and discussions referred to above, the audit committee has recommended to the board of directors that the audited financial statements referred to above be included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

Members of the Audit Committee:

Richard F. Ford, Chair of the Audit Committee

James C. Crain

Greg A. Walker

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


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


•	Evaluation of the executive officers’ performance;


•	Determination and approval of executive officer compensation;


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


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


•	Management of risk relating to incentive compensation.

Nominating and Corporate Governance Committee

Messrs. Beard, Crain and Ford, each an independent director, serve on our nominating and corporate governance 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 members and chairpersons for each committee to the board, (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 and (v) monitoring and evaluating corporate governance issues and trends.

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

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are a party, (iii) advising the board on actions to be taken by the committee upon the board’s request and (iv) carrying out any other duties delegated to the conflicts committee by the board of directors.

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 at www.armstrongenergyinc.com. Any amendments to, or waivers from, provisions of the code related to certain matters will be disclosed on our website.

Procedures for Nominating Directors

There have been no material changes to the procedures by which security holders may recommend nominees to the Company’s Board of Directors during the fiscal quarter ended December 31, 2015.

Item 11. Executive Compensation

2015 Summary Compensation Table

The following table sets forth all compensation paid to our named executive officers for the years ending December 31, 2015 and 2014.



Name and Principal Position	Year	Salary		Bonus		All Other Compensation			Total
J. Hord Armstrong, III,	2015	$	400,425	$	100,000	$	56,698	(1)	$	557,123
Executive Chairman	2014	$	400,000	$	385,046	$	88,132		$	873,178
Martin D. Wilson,	2015	$	437,426	$	110,000	$	36,576	(2)	$	584,002
President and Chief Executive Officer	2014	$	400,000	$	385,046	$	37,170		$	822,216
Kenneth E. Allen	2015	$	314,246	$	72,000	$	345,138	(3)	$	731,384
Executive Vice President and Chief Operating Officer	2014	$	350,000	$	215,274	$	435,320		$	1,000,594

(1)

Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Armstrong ($13,000), an allowance for personal automobile usage ($12,000), the incremental cost to the Company of Mr. Armstrong’s personal use of our corporate aircraft ($20,278), and an allowance for club membership dues ($11,420). 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.


(2)	Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Wilson ($13,000), an allowance for personal automobile usage ($12,000), and an allowance for club membership dues ($11,576).

(3)

Represents overriding royalties paid to Mr. Allen ($316,063) (see “—Overriding Royalty Agreement” for a description of Mr. Allen’s agreement with us regarding the payment of overriding royalties), our matching contributions paid to our 401(k) plan on behalf of Mr. Allen ($13,000), an allowance for personal automobile usage ($12,000) and the incremental cost to the Company of Mr. Allen's personal use of our corporate aircraft ($4,075). Mr. Allen’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.

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Elements of Compensation

Compensation Program

We believe that our compensation program provides a competitive compensation package to our executives and links pay to performance by making a significant portion of total executive compensation variable or “at risk.” A substantial portion of each executive officer’s total compensation is performance-based, varying from a low of approximately 33% and a high of approximately 60% for our Executive Chairman and President and Chief Executive Officer, respectively, to a low of approximately 27% to a high of approximately 53% for the other named executive officer.

Our compensation committee continues to consider informally the executive compensation data of certain publicly traded coal companies. The compensation committee uses peer group data as a point of reference for comparative purposes, but it is not the determinative factor for our named executive officers’ compensation. The compensation committee exercises discretion in determining the nature and extent of the use of comparative pay data. We did not utilize a compensation consultant in 2015. The compensation committee considered internal pay equity when making compensation decisions for executive officers, excluding any overriding royalties that may be due to executive officers. See “—Overriding Royalty Agreement.” However, the compensation committee does not use a fixed ratio or formula when comparing compensation among executive officers.

The compensation program consists primarily of base salary and annual bonus. 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 compensation committee. See “—Employment Agreements.” The base salary is intended to provide a degree of financial certainty and stability, to recognize competitive market conditions and to reward individual performance through periodic increases. Base salary levels are based on the executive officer’s role and responsibilities, the position’s complexity and its importance to us in relation to other executive positions and the officer’s experience, tenure, unique skills, past performance and future potential with the Company. Base salary increases are made at the compensation committee’s discretion after a review of the executive officer’s performance and the relevant market data. While the compensation committee uses market data as a point of reference for comparative purposes, it will determine the nature and amount of executive officer compensation in its sole discretion.

Executive officers’ target bonus percentage amounts are based on a multiple of each executive’s base salary. The annual bonus target percentage is recommended by the President and Chief Executive Officer and approved by the compensation committee, typically in January of each year. Although the individual performance component is discretionary at the sole determination of the compensation committee, with respect to the executive officers other than himself, our President and Chief Executive Officer provides his recommendations for these amounts to the compensation committee for its consideration.

Annual bonuses are intended to: (i) motivate executive officers to achieve key annual goals and position the Company for long-term success, (ii) provide compensation for performance based on the executive’s achievement of strategic goals and objectives, on both an individual and a Company-wide level and (iii) retain and attract executive talent. In setting the target bonus for each executive officer, consideration is given to the target bonus set forth in the respective officer’s employment agreement, if any, subject to adjustment by the compensation committee. Bonuses are typically based on financial performance goals related to our achievement of a pre-determined Adjusted EBITDA level, personal performance goals, and for Mr. Allen, the achievement of certain safety goals. However, the compensation committee has the discretion to consider other factors when the market warrants.

The compensation committee also has the authority to grant discretionary-based awards or adjust the bonus set forth above downward for one or a group of employees based on criteria set at the compensation committee’s discretion.

As a result of the declining market conditions, our overall performance during 2015, and the actions that management took to allow us to sustain our financial strength, the compensation committee unanimously voted to use its discretion as allowed under our compensation program and awarded certain of our key employees, including all the named executive officers, solely a discretionary bonus for 2015. The compensation committee determined that such discretionary bonus was to be made on an individual basis based on the recommendation made by the President and Chief Executive Officer.

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;

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•	Life insurance and supplemental life insurance;


•	Short-term and long-term disability; and


•	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. The Company aircraft may occasionally be used by executive officers for personal travel.

Employment Agreements

Allen Employment Agreement

Effective June 1, 2007, we entered into an employment agreement (the Allen Agreement) with Mr. Allen. The term of the Allen Agreement was three years, but the Allen Agreement shall be automatically renewed for additional one-year terms until such time, if any, as we or the executive 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. Effective January 1, 2015, Mr. Allen’s annual base salary was increased to $363,000. Effective September 1, 2015, Mr. Allen's annual base salary was decreased to $200,000.

The Allen Agreement contains non-competition and non-solicitation provisions that endure for a period of 12 months following the executive’s termination of employment with us.

In addition, pursuant to the Allen Agreement and the related overriding royalty agreement, as amended, between Mr. Allen and us, Mr. Allen receives an overriding royalty equal to $0.05 per ton sold by us from certain reserves described in that agreement. See “—Overriding Royalty Agreement.”

Pursuant to the Allen Agreement, we may terminate the 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, (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, (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, (vi) the executive’s death, (vii) any breach by the executive of certain obligations under the agreement or (viii) resignation by the executive under circumstances where a termination for “cause” was impending or could have reasonably been foreseen.

We also may terminate the Allen Agreement without cause. 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 and (ii) health insurance premiums for 12 months. In addition, the overriding royalty will run with the land per the provisions of the overriding royalty agreement. See “—Overriding Royalty Agreement.”

Under the Allen Agreement, the executive may resign for good reason, which is defined as a material demotion or reduction 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 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 agreement. See “—Overriding Royalty Agreement.”

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, plus any accrued and unpaid overriding royalty.

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Armstrong and Wilson Employment Agreements

Effective October 1, 2011, we entered into an employment agreement with each of Messrs. Armstrong and Wilson (together, the “Armstrong and Wilson Agreements”). The term of each of the Armstrong and Wilson Agreements was 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. Effective January 1, 2015, each of Messrs. Armstrong’s and Wilson’s annual base salaries was increased to $415,000. On May, 12, 2015, the board of directors appointed Mr. Wilson as President and Chief Executive officer of the Company, adjusting his salary to $450,000 effective May 16, 2015. Mr. Armstrong remained in the position of Executive Chairman of the Board and his salary was adjusted to $380,000 effective May 16, 2015. Effective January 1, 2016, Mr. Armstrong's annual base salary was decreased to $300,000. The remaining terms of the their employment agreements remain unchanged.

Pursuant to the Armstrong and Wilson Agreements, we may terminate Mr. Armstrong and Mr. Wilson at any time without cause (as defined below), and each 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 (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 (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 (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); (ii) willful misconduct by the executive in the performance of his duties that is demonstrably and materially injurious to our company or any affiliated company; (iii) the executive’s conviction of (or plea of nolo contendere to) a financial-related felony or other similarly material crime; or (iv) any material violation of the respective agreement by the executive.

For this purpose, good reason means the occurrence of any of the following: (i) the authority, duties or responsibilities of the executive are significantly and materially reduced; (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.

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; (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, 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); 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.

The Armstrong and Wilson Agreements contain non-competition provisions that continue for 18 months following the executive’s termination and non-solicitation provisions that endure for a period of 24 months following the executive’s termination.

Overriding Royalty Agreement

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 $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.

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Outstanding Equity Awards at 2015 Fiscal Year-End

There were no outstanding option and stock awards held by the named executive officers as of December 31, 2015.

Amended and Restated 2011 Long-Term Incentive Plan

Our board of directors adopted the 2011 Long-Term Incentive Plan during October 2011 and the Amended and Restated 2011 Long-Term Incentive Plan on February 10, 2015 (collectively, the LTIP). The LTIP will terminate upon the earlier of the adoption of a board resolution terminating the LTIP or ten years from its effective date. The 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 employees and directors who contribute significantly to our strategic and long-term performance objectives and growth. 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 to the named executive officers or directors under the LTIP in 2015. Each of the independent directors – Messrs. Beard, Crain, Ford and Walker – were awarded 10,000 shares of restricted stock under the LTIP on February 10, 2015, in recognition of their services and performance and to encourage retention of their services. See “—Compensation of Directors.”

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 compensation committee may also generally amend the terms and conditions of awards, subject to certain restrictions. Except with respect to restricted stock awards and unless otherwise determined by the compensation 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 following is a brief summary of the types of awards available for issuance under the LTIP:

Stock Options

The compensation 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. Subject to the committee’s discretion, recipients of such awards shall have voting, dividend and other stockholder rights with respect to the awards from the date of grant.

Performance Grants

Performance grants shall consist of a right that is (i) denominated in cash, common stock or any other form of award issuable under the LTIP, (ii) valued in accordance with the achievement of certain performance goals applicable to performance periods as the compensation committee may establish and (iii) payable at such time and in such form as the compensation committee shall determine. The compensation 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.

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Compensation of Directors

Each of our independent directors receives (i) an annual cash retainer of $50,000, and (ii) $1,500 per meeting of the board of directors attended by such director ($500 in the case of telephonic participation). Our compensation 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. Our non-employee directors also participate in the LTIP. To date, each of Messrs. Beard, Crain, Ford and Walker have been granted 10,000 shares of restricted stock of the Company under the LTIP. These shares were granted to each of the non-employee directors on February 10, 2015, and vested on February 9, 2016. Prior to the vesting date of the restricted stock grants, Mr. Beard voluntarily forfeited his grant.

The following table discloses compensation paid for the fiscal year ended December 31, 2015 to our independent directors for serving as members of the Board.

2015 Director Compensation Table



Name	Fees Earned or Paid in Cash		Stock Awards (1)		Total
Anson M. Beard, Jr. (2)	$	56,000	$	56,500	$	112,500
James C. Crain	$	56,000	$	56,500	$	112,500
Richard F. Ford	$	53,000	$	56,500	$	109,500
Greg A. Walker	$	55,000	$	56,500	$	111,500


(1)	Amounts in the Stock Awards column represents the grant-date fair value of restricted stock awards granted in 2015, as computed in accordance with FASB Accounting Standards Codification Topic 718, Compensation - Stock Compensation. As our common stock is not publicly traded, the fair value was estimated based on multiple valuation methods through the use of a third-party specialist.


(2)	Mr. Beard voluntarily forfeited his restricted stock grant prior to its vesting in February 2016.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table shows the amount of our common stock beneficially owned as of March 1, 2016 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 21,883,224 shares of common stock outstanding as of March 1, 2016.

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 directors and 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.

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	Shares Beneficially Owned(1)
	Number	Percent
J. Hord Armstrong, III (2)	148,201	*
Martin D. Wilson (3)	124,743	*
Kenneth E. Allen	12,000	*
Jeffrey F. Winnick	5,434	*
Anson M. Beard, Jr.	—	—
James C. Crain	10,000	*
Richard F. Ford	10,000	*
Bryan H. Lawrence	—	—
Greg A. Walker	10,000	*
All directors and executive officers as a group (nine persons)	320,378	1.46	%
Yorktown VII Associates LLC(4)(5)	11,562,500	52.84	%
Yorktown VIII Associates LLC(4)(6)	6,012,500	27.48	%
Yorktown IX Associates LLC(4)(7)	2,775,000	12.68	%



*	Less than 1%.


(1)	Does not reflect any fractional shares beneficially owned.


(2)	Includes 148,201 shares of common stock held of record by the John Hord Armstrong, III Trust dated June 13, 1994, for which Mr. Armstrong, as trustee, maintains sole voting and investment authority.


(3)	Includes 124,743 shares of common stock held of record by the Martin D. & Carole J. Wilson Living Trust dated September 7, 2013, for which Mr. and Mrs. Wilson, as co-trustees, share voting and investment authority.


(4)	The address of this beneficial owner is 410 Park Avenue, 19th Floor, New York, New York 10022.

(5)

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.

(6)

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.

(7)

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 partner of Yorktown IX Company LP. As a result, Yorktown IX Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the 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.

Item 13. Certain Relationships and Related-Party Transactions, and Director Independence

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.

For further information regarding our related-party transactions, see Note 13, “Related-Party Transactions,” to our audited consolidated financial statements included in Item 8 — “Financial Statements and Supplementary Data.”

Table of Contents

Director Independence

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 are independent. The board has determined that each of Messrs. Beard, Crain, Ford and Walker is an independent director pursuant to the requirements of NASDAQ. In addition, each of our audit and compensation committee members satisfies NASDAQ’s additional conditions for independence for audit and compensation committee members.

Item 14. Principal Accountant Fees and Services

The following table sets forth the amount of audit fees, tax fees, audit-related fees and all other fees billed or expected to be billed by Ernst & Young LLP, our independent registered public accounting firm for the years ended December 31, 2015 and 2014 (in thousands):



	2015		2014
Audit fees (1)	$	345	$	337
Tax fees (2)	113		111
Audit related fees	—		—
All other fees (3)	—		2
Total fees	$	458	$	450


(1)	Includes fees associated with the annual audit of our consolidated financial statements, including quarterly review procedures, and the issuance of their consent to include their audit opinion in registration statements filed with the SEC.


(2)	Includes fees associated with federal and state tax compliance and consulting services.


(3)	Includes fees for access to on-line accounting research tool.

Pre-Approval Policies and Procedures

The audit committee has adopted a policy that requires advance approval of all audit, audit-related, tax and other services performed by the Company’s independent registered public accounting firm. All of the fees listed above were pre-approved in accordance with this policy. The policy provides for pre-approval by the audit committee of specifically defined audit and permitted non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the Company’s independent registered public accounting firm is engaged to perform it. The audit committee has delegated to its Chair the authority to approve permitted services, provided that he reports any decisions to the audit committee at its next scheduled meeting. The audit committee, after review and discussion with Ernst & Young LLP of the Company’s pre-approval policies and procedures, determined that the provision of these services in accordance with such policies and procedures was compatible with maintaining the firm’s independence.

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PART IV

Item 15. Exhibits and Financial Statement Schedules


(a)	The following documents are filed as part of this Annual Report.


1.	Financial Statements

The consolidated financial statements of Armstrong Energy, Inc. and subsidiaries (formerly Armstrong Land Company, LLC and subsidiaries), together with the report thereon of our independent registered public accounting firm, are included on pages F-1 through F-34 of this Annual Report on Form 10-K.


2.	Financial Statement Schedules

All schedules have been omitted because they are not required, not applicable, not present in amounts sufficient to require submission of the schedule, or the required information is otherwise included.


3.	Exhibits

The exhibits required to be filed as part of this annual report on Form 10-K are listed in the attached Index to Exhibits.


(b)	The exhibits filed with this annual report on Form 10-K are listed in the attached Index to Exhibits.


(c)	None.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 23, 2016.



ARMSTRONG ENERGY, INC.

By:	/s/ Martin D. Wilson
	Martin D. Wilson
	President and Chief Executive Officer (Principal Executive Officer)

By:	/s/ Jeffrey F. Winnick
	Jeffrey F. Winnick
	Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 23, 2016.



Signature		Title

/s/ J. Hord Armstrong, III		Executive Chairman
J. Hord Armstrong, III

/s/ Martin D. Wilson		President, Chief Executive Officer and Director
Martin D. Wilson		(Principal Executive Officer)

/s/ Jeffrey F. Winnick		Vice President and Chief Financial Officer
Jeffrey F. Winnick		(Principal Financial and Accounting Officer)

/s/ Kenneth E. Allen		Executive Vice President, Chief Operating Officers
Kenneth E. Allen		and Director

/s/ Anson M. Beard, Jr.		Director
Anson M. Beard, Jr.

/s/ James C. Crain		Director
James C. Crain

/s/ Richard F. Ford		Director
Richard F. Ford

/s/ Bryan H. Lawrence		Director
Bryan H. Lawrence

/s/ Greg A. Walker		Director
Greg A. Walker

Table of Contents

INDEX TO EXHIBITS



		Incorporated by Reference
Exhibit Number	Description	Form	File Number	Exhibit	Filing Date	Filed or Furnished Herewith
3.1	Certificate of Conversion of Armstrong Land Company, LLC to Armstrong Land Company, Inc., effective as of October 1, 2011.	S-4	333-191182	3.1	09/16/13

3.2	Certificate of Incorporation of Armstrong Land Company, Inc., effective as of October 1, 2011.	S-4	333-191182	3.2	09/16/13

3.3	Certificate of Amendment to Certificate of Incorporation of Armstrong Land Company, Inc., effective as of October 5, 2011.	S-4	333-191182	3.3	09/16/13

3.4	Amended and Restated Certificate of Designations of Series A Convertible Preferred Stock of Armstrong Energy, Inc., effective as of March 6, 2012.	S-4	333-191182	3.4	09/16/13

3.5	Bylaws of Armstrong Energy, Inc., effective as of October 3, 2011.	S-4	333-191182	3.5	09/16/13

4.1	Registration Rights Agreement dated April 11, 2012 by and among Armstrong Energy, Inc. and J. Hord Armstrong, III, Martin D. Wilson, Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., Yorktown Energy Partners VIII, L.P., Yorktown Energy Partners IX, L.P., LucyB Trust (February 26, 2007), Lorenzo Weisman/Danielle Weisman Joint Ownership with Right of Survivorship, James H. Brandi, Brim Family 2004 Trust, Franklin W. Hobbs IV, Hutchinson Brothers, LLC and John H. Stites, III.	S-4	333-191182	4.6	09/16/13

4.2	Indenture dated as of December 21, 2012 among Armstrong Energy Inc. and Armstrong Air, LLC, Armstrong Coal Company, Inc., Armstrong Energy Holdings, Inc., Western Diamond LLC and Western Land Company, LLC, as Guarantors, and Wells Fargo Bank, National Association, as Trustee and as Collateral Agent.	S-4	333-191182	4.7	09/16/13

4.3	First Supplemental Indenture, dated as of September 19, 2013, among Armstrong Logistics Services, LLC, Armstrong Energy, Inc., and Wells Fargo Bank, National Association, as Trustee under the Indenture.	S-4	333-191182	4.8	09/23/13

4.4	Registration Rights Agreement dated December 21, 2012 among Armstrong Energy, Inc. and Armstrong Air, LLC, Armstrong Coal Company, Inc., Armstrong Energy Holdings, Inc., Western Diamond LLC and Western Land Company, LLC, as Guarantors, and Stifel, Nicolaus & Company, Incorporated, as representative of the several initial purchasers.	S-4	333-191182	4.8	09/16/13

4.5	Intercreditor Agreement dated as of December 21, 2012 by and between PNC Bank, National Association, as Agent, and Wells Fargo Bank, National Association, as Trustee, and acknowledged by Armstrong Energy, Inc., Armstrong Air LLC, Armstrong Coal Company, Inc., Armstrong Energy Holdings, Inc., Western Diamond LLC and Western Land Company LLC.	S-4	333-191182	4.9	09/16/13

4.6	Security Agreement dated as of December 21, 2012 by and among Armstrong Air, LLC, Armstrong Coal Company, Inc., Armstrong Energy, Inc., Armstrong Energy Holdings, Inc., Western Diamond LLC and Western Land Company, LLC, as Grantors, and Wells Fargo Bank, National Association, as Collateral Agent.	S-4	333-191182	4.10	09/16/13

Table of Contents



		Incorporated by Reference
Exhibit Number	Description	Form	File Number	Exhibit	Filing Date	Filed or Furnished Herewith
4.7	Joinder No. 1, dated as of September 19, 2013, to the Security Agreement, dated as of December 21, 2012, by and among Each of the Parties Listed on the Signature Pages thereto and Those Additional Entities that Thereafter Become Parties thereto and Wells Fargo Bank, National Association, as Trustee and as Collateral Agent.	S-4	333-191182	4.12	09/23/13

4.8	Security Agreement dated as of December 21, 2012 by and among Armstrong Energy, Inc., Armstrong Coal Company, Inc., Armstrong Energy Holdings, Inc., Armstrong Air, LLC, Western Land Company, LLC and Western Diamond LLC, as Debtors, and PNC Bank, National Association, as Administrative Agent.	S-4	333-191182	4.11	09/16/13

4.9	Second Supplemental Indenture, dated as of July 24, 2014, among Thoroughfare Mining, LLC, Armstrong Energy, Inc., and Wells Fargo Bank, National Association, as Trustee under the Indenture.	10-Q	333-191182	4.15	08/14/14

4.10	Joinder No. 2, dated as of July 24, 2014, to the Security Agreement, dated as of December 21, 2012 (as amended, restated, supplemented, or otherwise modified from time to time), by and among Each of the Parties Listed on the Signature Pages thereto and Those Additional Entities that Thereafter Become Parties thereto and Wells Fargo Bank, National Association, as Trustee and as Collateral Agent.	10-Q	333-191182	4.16	08/14/14

4.11	Third Supplemental Indenture, dated as of August 14, 2014, among Armstrong Energy, Inc. and Wells Fargo Bank, National Association, as Trustee under the Indenture.	10-Q	333-191182	4.17	08/14/14

4.12	Fourth Supplemental Indenture, dated as of January 29, 2015, among Armstrong Coal Sales, LLC, Armstrong Energy, Inc., and Wells Fargo Bank, National Association, as Trustee under the Indenture.	10-K	333-191182	4.12	03/26/15

4.13	Joinder No. 3, dated as of January 29, 2015, to the Security Agreement, dated as of December 21, 2012 (as amended, restated, supplemented, or otherwise modified from time to time), by and among Each of the Parties Listed on the Signature Pages thereto and Those Additional Entities that Thereafter Become Parties thereto and Wells Fargo Bank, National Association, as Trustee and as Collateral Agent.	10-K	333-191182	4.13	03/26/15

10.1	Credit Agreement dated as of December 21, 2012 by and among Armstrong Energy, Inc., as Borrower, Armstrong Coal Company, Inc., Armstrong Energy Holdings, Inc., Armstrong Air, LLC, Western Land Company, LLC and Western Diamond LLC, as Guarantors, the Lenders, Stifel Bank & Trust, as Agent, and PNC Bank, National Association, as Administrative Agent.	S-4	333-191182	10.1	09/16/13

10.2	Contract for Purchase and Sale of Coal by and between Tennessee Valley Authority and Armstrong Coal Company, Inc., dated as of August 30, 2012.	S-4	333-191182	10.8	09/16/13

10.3	Tennessee Valley Coal Supply & Origination Contract Supplement No. 1, dated as of October 4, 2012.	S-4	333-191182	10.9	09/16/13

10.4	Tennessee Valley Coal Supply & Origination Contract Supplement No. 2, dated as of October 29, 2012.	S-4	333-191182	10.10	09/16/13

Table of Contents



		Incorporated by Reference
Exhibit Number	Description	Form	File Number	Exhibit	Filing Date	Filed or Furnished Herewith
10.5	Tennessee Valley Coal Supply & Origination Contract Supplement No. 3, dated as of December 14, 2012.	S-4	333-191182	10.11	09/16/13

10.6	Tennessee Valley Coal Supply & Origination Contract Supplement No. 4, dated as of December 28, 2012.	S-4	333-191182	10.12	09/16/13

10.7	Tennessee Valley Coal Supply & Origination Contract Supplement No. 5, dated as of January 9, 2013.	S-4	333-191182	10.13	09/16/13

10.8	Tennessee Valley Coal Supply & Origination Contract Supplement No. 6, dated as of March 21, 2013.	S-4	333-191182	10.14	09/16/13

10.9	Tennessee Valley Coal Supply & Origination Contract Supplement No. 7, dated as of March 29, 2013.	S-4	333-191182	10.15	09/16/13

10.10	Tennessee Valley Coal Supply & Origination Contract Supplement No. 8, dated as of March 29, 2013.	S-4	333-191182	10.16	09/16/13

10.11	Tennessee Valley Coal Supply & Origination Contract Supplement No. 9, dated as of June 12, 2013.	S-4	333-191182	10.17	09/16/13

10.12	Tennessee Valley Coal Supply & Origination Contract Supplement No. 10, dated as of June 26, 2013.	S-4	333-191182	10.18	09/16/13

10.13	Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of January 1, 2008.	S-4	333-191182	10.20	09/16/13

10.14	Amendment No. 1 to Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of July 1, 2008.	S-4	333-191182	10.21	09/16/13

10.15	Letter Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated December 8, 2008.	S-4	333-191182	10.22	09/16/13

10.16	Letter Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated April 1, 2009.	S-4	333-191182	10.23	09/16/13

10.17	Amendment No. 2 to Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, effective as of December 22, 2009.	S-4	333-191182	10.24	09/16/13

10.18	Settlement Agreement and Release by and between Louisville Gas and Electric Company and Kentucky Utilities Company and Armstrong Coal Company, Inc., dated as of December 22, 2009.	S-4	333-191182	10.25	09/16/13

10.19	Coal Supply Agreement by and between Louisville Gas and Electric Company and Kentucky Utilities Company, as Buyer, and Armstrong Coal Company, Inc., as Seller, dated January 1, 2013.	S-4	333-191182	10.30	09/16/13

10.20†	Employment Agreement by and between Armstrong Energy, Inc. and Jeffrey F. Winnick, dated as of September 1, 2015.	10-Q	333-191182	10.1	11/12/15

Table of Contents

Incorporated by Reference

Exhibit

Number

Description

Form

File Number

Exhibit

Filing

Date

Filed or

Furnished

Herewith

10.21†

Employment Agreement by and between Armstrong Energy, Inc. and J. Richard Gist, dated as of October 1, 2011.

S-4

333-191182

10.31

09/16/13

10.22†

Employment Agreement by and between Armstrong Energy, Inc. and J. Hord Armstrong, III, dated as of October 1, 2011.

S-4

333-191182

10.32

09/16/13

10.23†

Employment Agreement by and between Armstrong Energy, Inc. and Martin D. Wilson, dated as of October 1, 2011.

S-4

333-191182

10.33

09/16/13

10.24†

Employment Agreement by and between Armstrong Coal Co. and Kenneth E. Allen, dated as of June 1, 2007.

S-4

333-191182

10.34

09/16/13

10.25†

Form of Director Indemnification Agreement.

S-4

333-191182

10.37

09/16/13

10.26†

Amended and Restated Armstrong Energy, Inc. 2011 Long-Term Incentive Plan

10-K

333-191182

10.30

03/26/15

10.27

Amended Overriding Royalty Agreement by and among Western Land Company, LLC, Western Diamond, LLC, Ceralvo Holdings, LLC, Armstrong Mining, Inc., Armstrong Coal Company, Inc., Armstrong Land Company, LLC and Kenneth E. Allen, dated as of December 3, 2008.

S-4

333-191182

10.39

09/16/13

10.28

Administrative Services Agreement by and between Armstrong Energy, Inc., Armstrong Resource Partners, L.P. and Elk Creek GP, LLC, effective as of January 1, 2011.

S-4

333-191182

10.41

09/16/13

10.29

Coal Mining Lease and Sublease Agreement between Armstrong Coal Company, Inc. and Ceralvo Holdings, LLC, dated February 9, 2011 (Elk Creek).

S-4

333-191182

10.42

09/16/13

10.30

Coal Mining Lease between Alcoa Fuels, Inc. and Armstrong Coal Company, Inc., dated as of October 27, 2010.

S-4

333-191182

10.46

09/16/13

10.31

Asset Purchase Agreement, dated as of December 29, 2011, by and between Cyprus Creek Land Resources, LLC and Armstrong Coal Company, Inc.

S-4

333-191182

10.47

09/16/13

10.32

Contract to Sell and Lease Real Estate between Midwest Coal Reserves of Kentucky, LLC and Armstrong Coal Company, Inc. dated December 25, 2011.

S-4

333-191182

10.49

09/16/13

10.33

Share Exchange Agreement dated as of December 12, 2012 by and between Armstrong Energy, Inc. and Yorktown Energy Partners IX, L.P.

S-4

333-191182

10.52

09/16/13

10.34

Guarantor Joinder and Assumption Agreement made as of September 19, 2013 by Armstrong Logistics Services, LLC.

S-4

333-191182

4.14

09/23/13

10.35

First Amended and Restated Royalty Deferment and Option Agreement by and between Armstrong Coal Company, Inc., Thoroughfare Mining, LLC, Western Diamond LLC, Western Land Company, LLC and Thoroughbred Resources, L.P., Western Mineral Development, LLC, and Ceralvo Holdings, LLC, effective August 14, 2014.

10-Q

333-191182

10.54

08/14/14

Table of Contents



		Incorporated by Reference
Exhibit Number	Description	Form	File Number	Exhibit	Filing Date	Filed or Furnished Herewith
10.36	First Amendment to Credit Agreement dated as of August 14, 2014 by and among Armstrong Energy, Inc., as Borrower, Armstrong Coal Company, Inc., Armstrong Energy Holdings, Inc., Armstrong Air, LLC, Western Land Company, LLC, Western Diamond LLC, Armstrong Logistics Services, LLC, and Thoroughfare Mining, LLC, as Guarantors, the Lenders, Stifil Bank & Trust, as Syndication Agent, PNC Bank, National Association, as Administrative Agent, and US Bank, National Association.	10-Q	333-191182	10.55	08/14/14

10.37	Guarantor Joinder and Assumption Agreement made as of July 24, 2014 by Thoroughfare Mining, LLC.	10-Q	333-191182	10.56	08/14/14

10.38	Guarantor Joinder and Assumption Agreement made as of January 29, 2015 by Armstrong Coal Sales, LLC.	10-K	333-191182	10.42	03/26/15

21.1	List of Subsidiaries.					X

31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X

31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					X

32.1#	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					X

32.2#	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					X

95.1	Federal Mine Safety and Health Act Information.					X

99.1	Audit Committee Charter.	S-4	333-191182	99.1	09/16/13

99.2	Compensation Committee Charter.	S-4	333-191182	99.2	09/16/13

99.3	Nominating, Corporate Governance and Risk Management Committee Charter.	S-4	333-191182	99.3	09/16/13

101.INS	XBRL Instance Document					X

101.SCH	XBRL Taxonomy Extension Scheme Document					X

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					X

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					X

101.LAB	XBRL Taxonomy Extension Label Linkbase Document					X

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					X

†	Indicates a management contract or compensatory plan or arrangement.
#	This certification is deemed not “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act), or otherwise subject to the liability of that section, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.

Table of Contents

INDEX TO FINANCIAL STATEMENTS



	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2015 and 2014		F-3
Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013		F-4
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013		F-5
Consolidated Statements of Stockholders’ Equity/(Deficit) for the years ended December 31, 2015, 2014 and 2013		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013		F-7
Notes to Audited Consolidated Financial Statements		F-8

F-1

Table of Contents

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Armstrong Energy, Inc. and Subsidiaries

We have audited the accompanying consolidated balance sheets of Armstrong Energy, Inc. and Subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2015. 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, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.



	/s/ Ernst & Young LLP
St. Louis, Missouri
March 23, 2016

F-2

Table of Contents

Armstrong Energy, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share amounts)



	December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	67,617		$	59,518
Accounts receivable	14,270			21,799
Inventories	14,562			10,552
Prepaid and other assets	1,952			2,962
Total current assets	98,401			94,831
Property, plant, equipment, and mine development, net	261,398			408,740
Investments	3,525			3,372
Other non-current assets	23,916			24,769
Total assets	$	387,240		$	531,712
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)
Current liabilities:
Accounts payable	$	22,555		$	27,593
Accrued and other liabilities	13,045			17,117
Current portion of capital lease obligations	1,943			2,426
Current maturities of long-term debt	8,402			4,929
Total current liabilities	45,945			52,065
Long-term debt, less current maturities	210,037			198,960
Long-term obligation to related party	128,809			110,713
Related-party payables, net	16,413			18,172
Asset retirement obligations	13,990			17,379
Long-term portion of capital lease obligations	555			1,358
Other non-current liabilities	6,772			8,208
Total liabilities	422,521			406,855
Stockholders’ equity/(deficit):
Common stock, $0.01 par value, 70,000,000 shares authorized, 21,853,224 shares and 21,936,844 shares issued and outstanding as of December 31, 2015 and 2014, respectively	218			219
Preferred stock, $0.01 par value, 1,000,000 shares authorized, zero shares issued and outstanding as of December 31, 2015 and 2014, respectively	—			—
Additional paid-in-capital	238,695			238,549
Accumulated deficit	(272,334		)	(110,193		)
Accumulated other comprehensive loss	(1,883		)	(3,741		)
Armstrong Energy, Inc.’s equity/(deficit)	(35,304		)	124,834
Non-controlling interest	23			23
Total stockholders’ equity/(deficit)	(35,281		)	124,857
Total liabilities and stockholders’ equity/(deficit)	$	387,240		$	531,712

See accompanying notes to consolidated financial statements.

F-3

Table of Contents

Armstrong Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands)



	Year Ended December 31,
	2015			2014			2013
Revenue	$	360,900		$	441,833		$	415,282
Costs and expenses:
Cost of coal sales, exclusive of items shown separately below	282,903			362,294			335,904
Production royalty to related party	7,879			8,269			7,811
Depreciation, depletion, and amortization	45,948			46,037			38,219
Asset retirement obligation expenses	3,277			2,099			2,267
Asset impairment and restructuring charges	138,679			—			—
General and administrative expenses	15,813			19,590			21,169
Operating (loss) income	(133,599		)	3,544			9,912
Other income (expense):
Interest expense, net	(34,685		)	(33,134		)	(35,563		)
Other, net	5,486			758			579
Loss before income taxes	(162,798		)	(28,832		)	(25,072		)
Income taxes	657			—			—
Net loss	(162,141		)	(28,832		)	(25,072		)
Less: income attributable to non-controlling interest	—			—			—
Net loss attributable to common stockholders	$	(162,141	)	$	(28,832	)	$	(25,072	)

See accompanying notes to consolidated financial statements.

F-4

Table of Contents

Armstrong Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)



	Year Ended December 31,
	2015			2014			2013
Net loss	$	(162,141	)	$	(28,832	)	$	(25,072	)
Postretirement benefit plan and other employee benefit obligations, net of tax	1,858			(3,004		)	(737		)
Other comprehensive income (loss)	1,858			(3,004		)	(737		)
Comprehensive loss	(160,283		)	(31,836		)	(25,809		)
Less: comprehensive income (loss) attributable to non-controlling interests	—			—			—
Comprehensive loss attributable to common stockholders	$	(160,283	)	$	(31,836	)	$	(25,809	)

See accompanying notes to consolidated financial statements.

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Armstrong Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)

(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/(Deficit)
Balance at December 31, 2012	21,871		$	219		—	$	—	$	238,713		$	(56,289	)	$	—		$	19	$	182,662
Net loss	—		—			—	—		—			(25,072		)	—			—		(25,072		)
Stock-based compensation	—		—			—	—		418			—			—			—		418
Postretirement benefit plan, net of tax of $0	—		—			—	—		—			—			(737		)	—		(737		)
Repurchase of employee stock relinquished for tax withholdings	(27	)	(1		)	—	—		(331		)	—			—			—		(332		)
Non-controlling interest contributions	—		—			—	—		—			—			—			4		4
Shares issued under employee plan	90		1			—	—		(1		)	—			—			—		—
Balance at December 31, 2013	21,934		219			—	—		238,799			(81,361		)	(737		)	23		156,943
Net loss	—		—			—	—		—			(28,832		)	—			—		(28,832		)
Stock-based compensation	—		—			—	—		(74		)	—			—			—		(74		)
Postretirement benefit plan and other employee benefit obligations, net of tax of $0	—		—			—	—		—			—			(3,004		)	—		(3,004		)
Repurchase of employee stock relinquished for tax withholdings	(15	)	—			—	—		(176		)	—			—			—		(176		)
Shares issued under employee plan	18		—			—	—		—			—			—			—		—
Balance at December 31, 2014	21,937		219			—	—		238,549			(110,193		)	(3,741		)	23		124,857
Net loss	—		—			—	—		—			(162,141		)	—			—		(162,141		)
Stock-based compensation	—		—			—	—		145			—			—			—		145
Postretirement benefit plan and other employee benefit obligations, net of tax of $1,183	—		—			—	—		—			—			1,858			—		1,858
Repurchase of employee stock relinquished for tax withholdings	(84	)	(1		)	—	—		1			—			—			—		—
Balance at December 31, 2015	21,853		$	218		—	$	—	$	238,695		$	(272,334	)	$	(1,883	)	$	23	$	(35,281	)

See accompanying notes to consolidated financial statements.

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Armstrong Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)



	Year Ended December 31,
	2015			2014			2013
Cash Flows from Operating Activities
Net loss	$	(162,141	)	$	(28,832	)	$	(25,072	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Non-cash stock compensation expense (income)	145			(74		)	418
Depreciation, depletion, and amortization	45,948			46,037			38,219
Amortization of debt issuance costs	1,538			1,197			1,153
Amortization of original issue discount	850			752			665
Asset retirement obligation expenses	3,277			2,099			2,267
Asset impairment	137,678			—			—
Income from equity affiliate	(153		)	(150		)	(31		)
(Gain) loss on disposal of property, plant, and equipment	(266		)	80			(16		)
Non-cash activity with related party, net	16,337			14,822			10,789
Non-cash interest on long-term obligations	(4		)	(4		)	288
Change in working capital accounts:
Decrease (increase) in accounts receivable	7,529			2,855			(516		)
(Increase) decrease in inventories	(4,010		)	2,130			(3,221		)
Decrease in prepaid and other assets	1,011			707			53
(Increase) decrease in other non-current assets	(752		)	(2,753		)	3,048
(Decrease) increase in accounts payable and accrued and other liabilities	(10,865		)	187			3,252
Increase in other non-current liabilities	121			2,092			1,648
Net cash provided by operating activities	36,243			41,145			32,944
Cash Flows from Investing Activities
Investment in property, plant, equipment, and mine development	(19,805		)	(24,442		)	(32,836		)
Issuance of note receivable – related party	—			—			(17,500		)
Payment of note receivable – related party	—			—			17,500
Proceeds from disposal of property, plant, and equipment	880			5			255
Net cash used in investing activities	(18,925		)	(24,437		)	(32,581		)
Cash Flows from Financing Activities
Payment on capital lease obligations	(2,714		)	(2,690		)	(4,547		)
Payments of long-term debt	(6,505		)	(5,942		)	(3,959		)
Proceeds from sale-leaseback	—			986			—
Payment of financing costs and fees	—			(1,000		)	(29		)
Repurchase of employee stock relinquished for tax withholdings	—			(176		)	(332		)
Contributions of non-controlling interest	—			—			4
Net cash used in financing activities	(9,219		)	(8,822		)	(8,863		)
Net increase (decrease) in cash and cash equivalents	8,099			7,886			(8,500		)
Cash and cash equivalents, at beginning of year	59,518			51,632			60,132
Cash and cash equivalents, at end of year	$	67,617		$	59,518		$	51,632
Supplemental cash flow information:
Cash paid for interest	$	24,244		$	24,115		$	24,045
Cash paid for income taxes	303			—			—
Non-cash transactions:
Assets acquired with long-term debt	20,205			5,410			2,082
Non-cash portion of land and reserve sale/financing with related party	18,172			8,202			4,886
Assets acquired by capital lease	1,428			2,256			—

See accompanying notes to consolidated financial statements.

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Armstrong Energy, Inc. 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. and its subsidiaries and controlled entities (collectively, AE or 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, 2015, all subsidiaries are majority owned. The Company is a producer of low chlorine, high sulfur thermal coal from the Illinois Basin, operating both surface and underground mines. 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, 2015, the Company had approximately 751 employees, none of whom are under a collective bargain arrangement.

The Company’s wholly-owned subsidiary, Elk Creek GP, LLC (ECGP), is the sole general partner of and has an approximate 0.2% ownership in Thoroughbred Resources, L.P. (Thoroughbred) (formerly Armstrong Resource Partners, L.P.). The various limited partners of Thoroughbred 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 Thoroughbred and accounts for its ownership in Thoroughbred under the equity method.

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.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

In February 2016, the Financial Accounting Standards Board (FASB) issued updated guidance regarding the accounting for leases. This update requires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is currently evaluating the effect of this update on its consolidated financial statements.

In November 2015, the FASB issued guidance that eliminates the requirement to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent. The new guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted. The Company adopted this standard as of December 31, 2015. While the adoption of this guidance impacted the Company's balance sheet disclosure, it did not affect the Company's results of operations or cash flows.

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related footnote disclosures. The new guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early adoption permitted.

In May 2014, the FASB issued a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The standard requires revenue to be recognized when promised goods or services are transferred to a customer in an amount that reflects the consideration expected in exchange for those goods or services. The standard permits the use of either the full retrospective or modified retrospective transition method. This guidance is effective for annual and interim reporting periods beginning after December 15, 2017, with early adoption permitted to the original effective date of December 15, 2016. The Company is currently evaluating the impact of this new pronouncement on its 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, 2015, other, net also includes a refund for a portion of the Kentucky sales and use taxes paid on the purchase of certain energy and energy producing fuels for the period of 2008 through 2013. The refund, including interest, totaled $4,482 and was received during the second quarter of 2015.

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, 2015 and 2014, the Company had not established an allowance for uncollectible amounts.

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, equipment, and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2015, 2014, and 2013 was $1,987, $973, and $1,641, respectively.

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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 2015, 2014, or 2013. 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.

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 15 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.

During the year ended December 31, 2015, the Company recorded an asset impairment charge of $137,678. No asset impairment charges were recorded during the years ended December 31, 2014 and 2013. See Note 3, "Asset Impairment and Restructuring Charges" for further details regarding the impairment charges recognized.

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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.

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 did not have any outstanding derivative instruments as of December 31, 2015 and 2014.

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 Accounting Standards Codification (ASC) Topic 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.

Long-Term Obligation to Related Party

The Company has entered into certain transactions with its affiliate, Thoroughbred, whereby it has sold an undivided interest in certain of its land and mineral reserves and subsequently entered into a lease agreement to mine the acquired mineral

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reserves in exchange for a production royalty. Due to its continuing involvement in the land and mineral reserves transferred, these transactions have been accounted for as financing arrangements and a long-term obligation has been established that is being amortized at an annual rate of 7% of the estimated gross revenue generated from the sale of the coal originating from the leased mineral reserves. The effective interest rate of the obligation is based on various estimates in future pricing and production quantities within the Company’s mine plans and is adjusted prospectively as significant changes in its mine plans occur. See Note 13 for further discussion of transactions with Thoroughbred.

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 income (loss). Actuarial gains and losses are amortized using the corridor approach over the average future service period of current active plan participants expected to receive benefits. See Note 19 for additional disclosures relating to these obligations.

Workers’ Compensation and Black Lung Benefits

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. For the years ended December 31, 2015, 2014, and 2013, the Company recorded $6,313, $7,341, and $7,277, respectively, of expense related to this excise tax. The Company has no liability associated with current claims 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, as any obligations are either secured by insurance or paid from the federal trust fund established for that purpose. The Company has recognized a liability for potential future claims by current employees based on the service cost method estimated by an independent actuary. The liability incorporates assumptions regarding medical costs, allocated loss adjustment expense, claim development patterns, and interest rates. For the year ended December 31, 2015, the Company recorded expense associated with future black lung claims of $668 and had a related liability of $1,884, which is included as a component of other long-term liabilities in the consolidated balance sheet.

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 years ended December 31, 2015 and 2014, the Company recognized $1,953 and $2,359, respectively, in investment credits, which were applied against certain employee payroll taxes in the statement of operations. As of December 31, 2015 and 2014, the Company had $5,328 and $7,681, respectively, in investment credit carryforwards available.

Equity Awards

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. ASSET IMPAIRMENT AND RESTRUCTURING CHARGES

Due to the significant decline in thermal coal pricing experienced during the year ended December 31, 2015 and the continuation of other adverse market conditions, the Company concluded indicators of impairment existed as of September 30, 2015. As such, the Company performed a comprehensive review of its long-lived assets for recoverability through future cash

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flows as of September 30, 2015. Based on that review, it was determined the carrying value was not recoverable, and the Company correspondingly recognized a non-cash asset impairment charge of $137,678 to reduce the carrying value of its long-lived assets to their estimated fair value. The inputs used to measure the fair value of the Company’s long-lived assets were largely unobservable, and accordingly, this measure was classified as Level 3. The fair value, which was determined through the use of a third-party specialist, was estimated primarily based on the income approach, with the significant inputs including future cash flow projections and discount rate assumptions. The impairment charge has been allocated to each of the components that comprise property, plant, equipment, and mine development, which is reflected in the amounts included in Note 6 for the year ended December 31, 2015.

In addition, the Company initiated certain restructuring activities beginning during the three months ended September 30, 2015 to better align its cost structure with current industry conditions. In order to optimize its coal production and focus on its low-cost operations, effective December 31, 2015, the Company idled its Midway surface mine, reduced operations to one section at the Parkway underground mine, and reduced the workforce at two of its preparation plants.

Costs associated with these restructuring activities primarily include voluntary and involuntary workforce rationalization. For the year ended December 31, 2015, the Company recognized restructuring charges of $1,001. The majority of cash expenditures associated with the 2015 charges are expected to be paid in the first half of 2016.

The above noted charges are included within “Asset impairment and restructuring charges” in the consolidated statements of operations.

4. PROPERTY TRANSACTIONS

In October 2013, the Company entered into a lease agreement for approximately 34 million tons of recoverable coal reserves located in Muhlenberg County, Kentucky, in exchange for a production royalty. The initial term of the lease is 20 years, with an additional term of ten years, provided mining of the reserve commenced within the first ten years of the agreement. An additional 26 million tons of contiguous recoverable coal reserves were leased in January 2014 in exchange for a production royalty. The initial term of the lease is 20 years, with an option to extend the lease for up to an additional 13 years. Mining of these reserves began in the first half of 2015.

In February 2014, the Company entered into a lease agreement with Thoroughbred for approximately 198 million tons of recoverable coal reserves in Muhlenberg and McLean Counties of Kentucky (see Note 13).

5. INVENTORIES

Inventories consist of the following amounts as of December 31, 2015 and 2014:



	2015		2014
Materials and supplies	$	9,634	$	10,378
Coal—raw and saleable	4,928		174
Total	$	14,562	$	10,552

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6. PROPERTY, PLANT, EQUIPMENT, AND MINE DEVELOPMENT

Property, plant, equipment, and mine development consist of the following as of December 31, 2015 and 2014:



	2015		2014
Land	$	41,909	$	41,892
Mineral rights	96,755		150,667
Machinery and equipment	183,810		194,958
Buildings and facilities	63,436		83,561
Office equipment, software and other	17,386		20,878
Mine development costs	54,025		64,453
ARO assets	6,798		11,336
Construction-in-progress	11,656		20,676
	475,775		588,421
Less: accumulated depreciation, depletion, and amortization	214,377		179,681
Total	$	261,398	$	408,740

Depreciation expense, including amounts from capitalized leases, for the years ended December 31, 2015, 2014, and 2013, was $31,056, $28,948, and $26,426, respectively. For the years ended December 31, 2015, 2014, and 2013, depletion expense related to mineral rights amounted to $4,835, $7,139, and $7,290, respectively; amortization expense related to mine development costs amounted to $10,032, $9,940, and $4,075, respectively; and depreciation expense related to the ARO assets amounted to $1,311, $446, and $596, respectively.

The Company has pledged substantially all buildings and equipment as security under the 11.75% Senior Secured notes due 2019 (the Notes) and asset based revolving credit facility entered into in December 2012 (2012 Credit Facility) (see Note 12), as well as under certain capital lease obligations.

The Company had outstanding construction commitments as of December 31, 2015, of approximately $303. All construction commitments are expected to be completed within the next fiscal year.

7. CLOSURE OF LEWIS CREEK UNDERGROUND MINE

The Company’s Lewis Creek underground mine, which produced coal from the West Kentucky #9 seam, experienced significant operating inefficiencies due to the geological conditions of the portion of the reserve being mined. As a result of the ongoing mining difficulties, a final decision was made in August 2014 not to continue advancing under the existing mine plan, but rather to retreat and mine only in the eastern portion of the reserve.

The Company completed mining of the Lewis Creek underground mine in March 2015 and has extracted the equipment, which will be utilized at its other mining operations in the future. As a result of the closure, the Company accelerated depreciation of the remaining net book value of the capitalized costs associated with the original development of the mine. Total expense recognized during the first quarter of 2015 to write-off the remaining asset was approximately $6,318 which is included as a component of "depreciation, depletion, and amortization" in the consolidated statement of operations for the year ended December 31, 2015.

8. OTHER NON-CURRENT ASSETS

Other non-current assets consist of the following as of December 31, 2015 and 2014:



	2015		2014
Escrows and deposits	$	5,233	$	4,649
Restricted surety and cash bonds	6,115		6,379
Advanced royalties	5,272		4,842
Deferred financing costs, net	7,226		8,765
Intangible assets, net	70		134
Total	$	23,916	$	24,769

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9. ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities consist of the following amounts as of December 31, 2015 and 2014:



	2015		2014
Payroll and related benefits	$	6,454	$	7,661
Taxes other than income taxes	3,134		4,588
Interest	987		991
Asset retirement obligations	94		342
Royalties	630		691
Other	1,746		2,844
Total	$	13,045	$	17,117

10. 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 the 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, which was determined using Level 2 inputs, and long-term obligation to related party, which was determined using Level 3 inputs, are as follows:



	December 31, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
Notes(1)	$	82,000	$	195,419	$	206,000	$	194,570
Long-term obligation to related party	94,811		128,809		115,731		110,713
Total	$	176,811	$	324,228	$	321,731	$	305,283


(1)	The carrying value of the Notes is net of the unamortized original issue discount as of December 31, 2015 and 2014.

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.

11. 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 approximately 38% and 29%, respectively, of net sales for the year ended December 31, 2015. 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.

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12. LONG-TERM DEBT

The Company’s total indebtedness as of December 31, 2015 and 2014 consisted of the following:



Type	2015		2014
Notes	$	195,419	$	194,570
Other	23,020		9,319
	218,439		203,889
Less: current maturities	8,402		4,929
Total long-term debt	$	210,037	$	198,960

Senior Secured Notes due 2019

On December 21, 2012, the Company completed a $200,000 offering of 11.75% 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, 2015 and 2014, the unamortized OID was $4,581 and $5,430, respectively. The Company incurred $8,358 of deferred financing fees related to the Notes, which have been capitalized and are being 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. 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 12 months commencing on December 15, 2016 at 105.875% of the principal amount redeemed, at any time during the 12 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 Notes were redeemable 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 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: (i) incur additional indebtedness or issue preferred equity; (ii) pay dividends or distributions on or purchase the Company’s stock or the Company’s restricted subsidiaries’ stock; (iii) make certain investments; (iv) use assets as security in other transactions; (v) create guarantees of indebtedness by restricted subsidiaries; (vi) enter into agreements that restrict dividends, distributions, or other payment by restricted subsidiaries; (vii) sell certain assets or merge with or into other companies; and (viii) 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 (SEC) 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. The exchange offer was completed in November 2013.

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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, 2015 and 2014, there were no borrowings outstanding under the 2012 Credit Facility and the Company had $16,740 and $15,920, respectively, 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.

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 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 fixed charge coverage ratio is defined as the ratio of consolidated EBITDA to fixed charges, which includes the sum of unfinanced capital expenditures, scheduled principal payments on indebtedness, cash interest payments, dividends, and cash taxes.

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.

Other Debt

Other debt consists of miscellaneous debt obligations entered into to finance the acquisition of certain equipment and land. These obligations have various maturities of one to five years and bear interest at rates between 2.99% and 6.50%.

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Maturities of Long-Term Debt

The aggregate amounts of long-term debt maturities subsequent to December 31, 2015 were as follows:



2016	$	8,401
2017	7,551
2018	4,489
2019	202,555
2020	24
2021 and thereafter	—
Total	$	223,020

13. RELATED-PARTY TRANSACTIONS

Merger of Related Parties

On February 1, 2014, Armstrong Resource Partners, L.P. merged with and into Thoroughbred Resources, LLC, with Armstrong Resource Partners, L.P. as the surviving entity (the Merger). Effective with the Merger, Armstrong Resource Partners, L.P. changed its name to Thoroughbred. The Company’s wholly-owned subsidiary, ECGP, remained the general partner of the surviving entity, under the terms of the amended and restated limited partnership agreement, which is substantially the same as the limited partnership agreement in effect immediately prior to the Merger. As a result of the Merger, ECGP’s equity interest in the combined company was reduced to approximately 0.2%.

In January 2014, the Company’s investment in Ram Terminals, LLC (RAM), an entity majority owned by Yorktown, was converted into an equal ownership percentage of Terminal Holdings, LLC, a holding company which is the sole member of both RAM and MG Midstreaming, LLC. Subsequent to the Merger, but also on February 1, 2014, Terminal Holdings, LLC merged with and into a merger subsidiary of Thoroughbred created for the purpose of the transaction, with Terminal Holdings, LLC as the surviving entity. Terminal Holdings, LLC was owned by the Company and Yorktown in the same percentage as their prior interests in RAM, and by virtue of the Merger, the Company’s equity interest in Terminal Holdings, LLC was converted into an equal number of common units representing limited partnership interests in Thoroughbred. Because of the Company’s ownership interest in Thoroughbred through ECGP, the newly converted interest, which equals an additional 0.9%, is accounted for under the equity method.

As of December 31, 2015, the Company’s total ownership interest in Thoroughbred equaled 1.1%. Income from the equity interest in Thoroughbred for the years ended December 31, 2015, 2014, and 2013 totaled $153, $150, and $31, respectively.

Sale of Coal Reserves

The Company has executed the sale of an undivided interest in certain land and mineral reserves in Ohio and Muhlenberg counties of Kentucky to Thoroughbred, through a series of transactions beginning in February 2011. Subsequently, the Company entered into lease agreements with Thoroughbred pursuant to which Thoroughbred granted the Company leases to its undivided interests in the mining properties acquired and licenses to mine and sell coal from those properties in exchange for a production royalty. Due to the Company’s continuing involvement in the land and mineral reserves transferred, these transactions have been accounted for as financing arrangements. 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. In addition, effective February 2011, the Company and Thoroughbred entered into a Royalty Deferment and Option Agreement, whereby the Company has been granted an option to defer payment of any royalties earned by Thoroughbred on coal mined from these properties. Compensation for the aforementioned transactions has consisted of a combination of cash payments and the forgiveness of amounts owed by the Company, which primarily consisted of deferred royalties.

On October 1, 2014, the Company transferred to Thoroughbred a portion of its interest in certain land and mineral reserves the Company controls in Muhlenberg county, which had been excluded from the various prior sales transactions, in exchange for Thoroughbred conveying to the Company a 7.97% undivided interest in the land and mineral reserves previously transferred by the Company to Thoroughbred.

The Company sold an additional 3.85% undivided interest in certain leased and owned land and mineral reserves to Thoroughbred on October 1, 2014 in exchange for Thoroughbred forgiving amounts owed by the Company of $8,202. On May

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1, 2015, the Company sold an additional 12.10% undivided interest in certain leased and owned land and mineral reserves to Thoroughbred in exchange for Thoroughbred forgiving amounts owed by the Company of $18,172. The amounts forgiven by Thoroughbred consisted primarily of deferred production royalties. The newly acquired interests in the mineral reserves were leased and/or subleased by Thoroughbred to the Company in exchange for a production royalty. These transactions were accounted for as financing arrangements, and additional long-term obligations to Thoroughbred of $8,202 and $18,172 were recognized on October 1, 2014 and May 1, 2015, respectively.

The percentage interests in the land and mineral reserves sold to Thoroughbred in the above transactions were based on fair values determined by a third-party specialist. In addition, these transactions were approved by the conflicts committee of the board of directors of the Company, a committee comprised of only independent directors. As a result of the above, Thoroughbred’s undivided interest in certain of the Company’s leased and owned land and mineral reserves in Muhlenberg and Ohio counties as of December 31, 2015 and 2014 was 61.38% and 49.28%, respectively.

As of December 31, 2015 and 2014, the outstanding long-term obligation to related party totaled $128,809 and $110,713, respectively. Interest expense recognized for the years ended December 31, 2015, 2014, and 2013 associated with the long-term obligation to related party was $10,049, $7,993, and $11,029, respectively. Based on the current mine plan, the effective interest rate of the obligation was adjusted to 5.0% as of December 31, 2015.

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:
2016	$	6,878
2017	6,234
2018	6,660
2019	6,489
2020	5,500
2021 and thereafter	453,828
Total payments	$	485,589

Lease of Coal Reserves

In February 2011, Thoroughbred entered into a lease and sublease agreement with the Company relating to its Elk Creek reserves and granted the Company a license to mine coal on those properties. The terms of this agreement mirror those of the lease agreements associated with the jointly owned reserves between the Company and Thoroughbred. Total production royalties owed from mining of the Elk Creek reserves, where the Company’s Kronos underground mine resides, for the years ended December 31, 2015, 2014, and 2013 totaled $7,879, $8,269, and $7,811, respectively.

In February 2014, the Company entered into an additional lease and/or sublease with Thoroughbred for certain mineral reserves located in Muhlenberg and McLean Counties of Kentucky, contiguous to its existing reserves, in exchange for a production royalty. Total proven and probable mineral reserves included as part of the transaction was approximately 198 million tons. The initial term of the lease is 10 years, with an automatic extension of up to 10 years. No mining of this reserve had commenced as of December 31, 2015.

Administrative Services Agreements

Effective as of January 1, 2011, the Company entered into an Administrative Services Agreement with Thoroughbred and its general partner, ECGP, pursuant to which the Company agreed to provide Thoroughbred with general administrative and management services, including, but not limited to, human resources, information technology, financial and accounting services and legal services. The administrative service fee, which is adjusted annually, is approved by the conflicts committee of the board of directors. As consideration for the use of the Company’s employees and services, and for certain shared fixed costs, Thoroughbred paid the Company $1,200, $1,015, and $775 for the years ended December 31, 2015, 2014, and 2013, respectively. Prior to the Merger, the Company had separate administrative services agreements with Thoroughbred Resources, LLC and RAM. For the year ended December 31, 2013, the Company was paid $172 for the associated services rendered to Thoroughbred Resources, LLC and RAM.

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Other

In 2006 and 2007, the Company entered into overriding royalty agreements with a current and a former executive employee to compensate each of 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 years ended December 31, 2015, 2014, and 2013, was $632, $817, and $811, respectively.

14. 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 $15,024, $17,873, and $20,362 for the years ended December 31, 2015, 2014, and 2013, respectively.

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, 2015, are:



	Capital Leases		Operating Leases
Year ending December 31:
2016	$	2,033	$	5,595
2017	568		4,138
2018	—		636
2019	—		95
2020 and thereafter	—		—
Total minimum lease payments	2,601		$	10,464
Less: amount representing interest	103
Present value of net minimum capital lease payments	2,498
Less: current installments of obligations under capital leases	1,943
Obligations under capital leases, excluding current installments	$	555

The net amount of leased assets capitalized on the balance sheet as of December 31, 2015 and 2014 is as follows:



	2015		2014
Asset cost	$	18,753	$	20,393
Less: accumulated depreciation	13,703		10,494
Net	$	5,050	$	9,899

15. ROYALTIES

Royalty expense, exclusive of royalties owed to a related party, for the years ended December 31, 2015, 2014, and 2013 were $13,841, $12,975, and $12,212, respectively. For the years ended December 31, 2015 and 2014, the Company recorded $1,040 and $1,483, respectively, of advance royalty payments. These payments are recoupable against royalties generated from future mining activity. As of December 31, 2015 and 2014, advance royalties totaled $5,272 and $4,841, respectively. Included in this amount is $3,381 and $2,776 as of December 31, 2015 and 2014, respectively, 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.

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Anticipated future minimum advance royalties as of December 31, 2015, are payable as follows:




2016	$	917
2017	890
2018	663
2019	661
2020 and thereafter	1,432
Total	$	4,563

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 current and former executives of management, a former minority shareholder, and sales brokers. See Note 13 for the terms of royalties to related-parties.

16. ASSET RETIREMENT OBLIGATIONS AND RECLAMATION

Asset retirement obligation and reclamation balances consist of the following as of December 31, 2015 and 2014:



	2015			2014
Balance at beginning of year	$	17,721		$	17,270
Accretion expense	1,774			1,679
Liabilities settled (net)	(2,341		)	(31		)
Revisions to estimates	(3,070		)	(1,197		)
Balance at end of year	14,084			17,721
Less: current obligation	94			342
Total obligation, less current portion	$	13,990		$	17,379

The credit-adjusted, risk-free rates used to discount the estimated liability were 11.9% and 9.7% in 2015 and 2014, respectively.

For the years ended December 31, 2015 and 2014, the reduction in the liability resulted primarily from overall changes in discount rates, estimates of the costs and scope of remaining reclamation work and fluctuations in projected mine life estimates.

17. INCOME TAXES

The loss before income taxes and non-controlling interest was ($162,798), ($28,832) and ($25,072) for the years ended December 31, 2015, 2014, and 2013, respectively. The income tax benefit recognized in the year ended December 31, 2015 is primarily related to the intraperiod allocation rules under ASC 740, which requires the income in other sources, such as other comprehensive income, be considered in determining the realization of the loss in continuing operations. Accordingly, a benefit was recorded in continuing operations with an offsetting expense recognized through other comprehensive income.

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The components of the income tax (benefit) provision are as follows:



	December 31,
	2015			2014		2013
Current:
Federal	$	—		$	—	$	—
State	526			—		—
	526			—		—
Deferred:
Federal	(1,000		)	—		—
State	(183		)	—		—
	(1,183		)	—		—
Total	$	(657	)	$	—	$	—

The income tax rate differed from the U.S. federal statutory rate as follows:



	December 31,
	2015			2014			2013
Tax benefit at federal statutory rates	$	(56,979	)	$	(9,697	)	$	(8,776	)
State income taxes	(8,115		)	(1,797		)	(2,141		)
Other permanent items	(185		)	663			369
Other	(1,183		)	(325		)	(100		)
Increase in valuation allowance	65,805			11,156			10,648
Total	$	(657	)	$	—		$	—

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,
	2015			2014
Deferred tax assets:
Tax loss and credit carryforwards	$	79,636		$	74,129
Long-term obligation to related party	51,763			43,850
Deferred organization costs and other intangibles	666			758
Vacation accrual	676			639
Charitable contributions	139			193
Other post-retirement benefits	2,378			1,310
Asset retirement obligation	6,912			6,059
Other	373			182
Total gross deferred tax assets	142,543			127,120
Deferred tax liabilities:
Property, plant, and equipment	(39,075		)	(89,301		)
Investments	(208		)	(310		)
Other	(53		)	(107		)
Total gross deferred tax liabilities	(39,336		)	(89,718		)
Valuation allowance	(103,207		)	(37,402		)
Net deferred tax assets	$	—		$	—

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Changes to the valuation allowance during the years ended December 31, 2015 and 2014, were as follows:



Valuation allowance at December 31, 2013	$	26,246
Increase in valuation allowance	11,156
Valuation allowance at December 31, 2014	37,402
Increase in valuation allowance	65,805
Valuation allowance at December 31, 2015	$	103,207

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, 2015 and 2014. Based on the anticipated reversals of the Company’s deferred tax assets and deferred tax liabilities, a valuation allowance of $103,207 and $37,402 at December 31, 2015 and 2014, respectively, has been established only for the excess of deferred tax assets over deferred tax liabilities.

The Company’s net deferred tax assets included federal and state net operating loss (NOL) carryforwards of $192,330 and $305,379, respectively, as of December 31, 2015, and $184,240 and $236,751, respectively, as of December 31, 2014. The NOLs begin to expire in 2026. The Company’s net deferred taxes also include $407 of alternative minimum tax (AMT) credits as of December 31, 2015 and 2014. 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.

During 2015, 2014, and 2013, the Company made an immaterial amount of state and local income tax payments.

There were no uncertain tax positions as of December 31, 2015 or 2014, 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.

18. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2015 and 2014 consisted of the following:



	Postretirement Benefit Plan and Other Employee Benefit Obligations			Accumulated Other Comprehensive Income(Loss)
Balance as of December 31, 2013	$	(737	)	$	(737	)
Other comprehensive loss before reclassifications	104			104
Current period change	(3,108		)	(3,108		)
Balance as of December 31, 2014	(3,741		)	(3,741		)
Amounts reclassified from accumulated other comprehensive income (loss)	64			64
Current period change	1,794			1,794
Balance as of December 31, 2015	$	(1,883	)	$	(1,883	)

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The following is a summary of reclassifications out of accumulated other comprehensive income for the years ended December 31, 2015, 2014 and 2013:



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 Years Ended December 31,
		2015			2014			2013
Amortization of postretirement benefit plan items
—Prior service cost	(a)	(104		)	(104		)	(104		)
		(104		)	(104		)	(104		)
Income taxes		40			—			—
Total reclassifications		$	(64	)	$	(104	)	$	(104	)


(a)	This component of accumulated other comprehensive income (loss) is included in the computation of net period postretirement cost. See Note 19.

19. 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 $2,689, $3,034, and $2,670, for the years ended December 31, 2015, 2014, and 2013, respectively.

Postretirement Medical Cost Reimbursement Plan

The Company provides 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 is provided to future hourly and salaried retirees in accordance with the plan document. The Company’s funding policy with respect to the plan is to fund the cost of all postretirement benefits as they are paid.

The restructuring activities undertaken during 2015, as more fully described in Note 3, reduced the estimated years of future service of the terminated employees and accelerated postretirement benefits for those participants who were eligible. This resulted in the application of curtailment accounting, triggering the immediate recognition of any unamortized gain or loss and the reduction in the projected benefit obligation.

Net periodic postretirement benefit cost included the following components for the years ended December 31, 2015 and 2014:



	December 31,
	2015			2014
Service cost for benefits earned	$	1,216		$	1,034
Interest cost on accumulated postretirement benefit obligation	122			87
Amortization of prior service cost	104			104
Curtailment gain recognized	(209		)	—
Net periodic postretirement cost	$	1,233		$	1,225

Amounts recognized in accumulated other comprehensive loss are as follows:



	December 31,
	2015			2014
Net actuarial (gain) loss	$	(38	)	$	123
Prior service cost	650			820
Total recognized in accumulated other comprehensive loss	$	612		$	943

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The estimated net actuarial gain and prior service cost that will be amortized from accumulated other comprehensive loss into net periodic benefit cost during the year ending December 31, 2016 are zero and $0.1 million, respectively.

The following table sets forth changes in benefit obligation and plan assets for the years ended December 31, 2015 and 2014 and the funded status of the plan reconciled with the amounts reported in the Company's consolidated financial statements at December 31, 2015 and 2014:



	2015			2014
Change in Benefit Obligations
Benefit obligation at January 1	$	3,367		$	1,949
Service cost	1,216			1,034
Interest cost	122			87
Plan amendment	—			—
Plan curtailment	(275		)	—
Benefits paid	(39		)	(13		)
Actuarial (gain) loss	(162		)	310
Benefit obligation at December 31	4,229			3,367
Change in Plan Assets
Value of plan assets at January 1	—			—
Employer contributions	39			13
Benefits paid	(39		)	(13		)
Value of plan assets at December 31	—			—
Funded status at December 31	$	4,229		$	3,367
Amounts Recognized in Balance Sheet
Current liability	$	316		$	218
Non-current liability	3,913			3,149
	$	4,229		$	3,367
Amounts Recognized in Accumulated Other Comprehensive Loss
Prior service cost for period	$	—		$	—
Net actuarial (gain) loss arising during year	(162		)	310
Amortization:
Prior service cost	(170		)	(104		)
Total recognized in other comprehensive loss	$	(332	)	$	206
Weighted Average Assumptions to Determine Benefit Obligation
Discount rate	4.21		%	3.73		%
Rate of compensation increase	N/A			N/A
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
Discount rate	3.73		%	4.56		%
Expected return on plan assets	N/A			N/A

Estimated future benefit payments, which reflect expected future service, as of December 31, 2015 are as follows:



2016	$	316
2017	312
2018	345
2019	467
2020	533
2021 – 2025	3,362
Total	$	5,335

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Table of Contents

The following presents information about the assumed health care cost trend rate:



	Year Ended December 31,
	2015		2014
Health care cost trend rate assumed for next year	7.10	%	7.10	%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	4.50	%	4.50	%
Year the rate reaches the ultimate trend rate	2027		2027

20. EQUITY 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 one 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.

Information regarding restricted shares activity and weighted-average grant-date fair value follows for the year ended December 31, 2015:



	Restricted Shares
	Shares		Weighted- Average Grant- Date Fair Value
Outstanding at January 1, 2015	18,500		$	11.44
Granted	63,000		4.01
Vested	—		—
Forfeited	(18,500	)	11.44
Outstanding at December 31, 2015	63,000		4.01

The total fair value of restricted stock awards granted and vested during the year ended December 31, 2015 was $252 and zero, respectively.

Unearned compensation of $50 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 0.5 years. During the years ended December 31, 2015 and 2014, the Company reversed $137 and $251, respectively, of previously recognized compensation expense due to a change in the estimated forfeiture rate from 0% to 100% on certain non-vested restricted stock grants to former executive employees who resigned. The Company recognized expense (income) of $145, $(74), and $418 related to restricted shares for the years ended December 31, 2015, 2014, and 2013, respectively.

21. 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 $901 and $1,747 related to Mine Safety and Health Administration (MSHA) fines were accrued in the results of operations for the years ended December 31, 2015 and 2014, respectively.

The Company is involved from time to time in various legal 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 has historically sold the majority of its coal under multi-year supply agreements of varying duration. 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 four years. The Company, via contractual agreements has committed volumes of sales in 2015 of 5.6 million tons.

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Coal Transportation Agreements

The Company is engaged in a lease services agreement with a third party to 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 incurred $3,056, $3,545, and $3,596 of expense during the years ended December 31, 2015, 2014, and 2013, respectively, associated with the coal transportation agreement.

Governmental Impositions

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 related to constructing the MSHA mandated safety bench at the Equality Boot mine in November 2011. The terms of the settlement include a price adjustment of $0.87 per ton for tons shipped from the Equality Boot mine subsequent to November 2011 on certain contracts with the customer. For coal shipments made between November 2011 and June 2013, a lump sum payment of approximately $2,500 was received by the Company in August 2013. The proceeds from the settlement were recognized as additional revenue in the year ended December 31, 2013.

Off-Balance Sheet Arrangements

In the normal course of business, the Company is a party to certain off-balance sheet arrangements, which are not reflected in the Company's consolidated balance sheets. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as surety bonds and performance bonds. In the Company's past, no claims have been made against these financial instruments. The Company does not expect any material adverse effects on its financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Federal and state laws require the Company to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. The Company typically secures 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, the Company would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral. The Company also posts performance bonds to secure our performance of various contractual obligations.

As of December 31, 2015, the Company had approximately $32.5 million in surety bonds outstanding to secure the performance of its reclamation obligations, which were supported by approximately $6.1 million of cash posted as collateral.

22. 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 SEC and the financial position, results of operations, and cash flows are, therefore, included in the condensed financial data of the guarantor subsidiaries.

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Supplemental Condensed Consolidating Balance Sheets



	December 31, 2015
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	67,617		$	—		$	67,617
Accounts receivable	—			14,270			—			14,270
Inventories	—			14,562			—			14,562
Prepaid and other assets	110			1,842			—			1,952
Total current assets	110			98,291			—			98,401
Property, plant, equipment, and mine development, net	10,467			250,931			—			261,398
Investments	—			3,525			—			3,525
Investments in subsidiaries	69,429			—			(69,429		)	—
Intercompany receivables	70,347			(70,347		)	—			—
Other non-current assets	7,441			16,475			—			23,916
Total assets	$	157,794		$	298,875		$	(69,429	)	$	387,240
LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)
Current liabilities:
Accounts payable	$	177		$	22,378		$	—		$	22,555
Accrued and other liabilities	1,771			11,274			—			13,045
Current portion of capital lease obligations	—			1,943			—			1,943
Current maturities of long-term debt	—			8,402			—			8,402
Total current liabilities	1,948			43,997			—			45,945
Long-term debt, less current maturities	195,419			14,618			—			210,037
Long-term obligation to related party	—			128,809			—			128,809
Related-party payables, net	(4,411		)	20,824			—			16,413
Asset retirement obligations	—			13,990			—			13,990
Long-term portion of capital lease obligations	—			555			—			555
Other non-current liabilities	142			6,630			—			6,772
Total liabilities	193,098			229,423			—			422,521
Stockholders’ equity/(deficit):
Armstrong Energy, Inc.’s equity/(deficit)	(35,304		)	69,429			(69,429		)	(35,304		)
Non-controlling interest	—			23			—			23
Total stockholders’ equity/(deficit)	(35,304		)	69,452			(69,429		)	(35,281		)
Total liabilities and stockholders’ equity/(deficit)	$	157,794		$	298,875		$	(69,429	)	$	387,240

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	December 31, 2014
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	59,518		$	—		$	59,518
Accounts receivable	—			21,799			—			21,799
Inventories	—			10,552			—			10,552
Prepaid and other assets	62			2,900			—			2,962
Total current assets	62			94,769			—			94,831
Property, plant, equipment, and mine development, net	14,648			394,092			—			408,740
Investments	—			3,372			—			3,372
Investments in subsidiaries	199,435			—			(199,435		)	—
Intercompany receivables	96,755			(96,755		)	—			—
Other non-current assets	8,980			15,789			—			24,769
Total assets	$	319,880		$	411,267		$	(199,435	)	$	531,712
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	100		$	27,493		$	—		$	27,593
Accrued and other liabilities	3,456			13,661			—			17,117
Current portion of capital lease obligations	—			2,426			—			2,426
Current maturities of long-term debt	—			4,929			—			4,929
Total current liabilities	3,556			48,509			—			52,065
Long-term debt, less current maturities	194,570			4,390			—			198,960
Long-term obligation to related party	—			110,713			—			110,713
Related-party payables, net	(3,211		)	21,383			—			18,172
Asset retirement obligations	—			17,379			—			17,379
Long-term portion of capital lease obligations	—			1,358			—			1,358
Other non-current liabilities	131			8,077			—			8,208
Total liabilities	195,046			211,809			—			406,855
Stockholders’ equity:
Armstrong Energy, Inc.’s equity	124,834			199,435			(199,435		)	124,834
Non-controlling interest	—			23			—			23
Total stockholders’ equity	124,834			199,458			(199,435		)	124,857
Total liabilities and stockholders’ equity	$	319,880		$	411,267		$	(199,435	)	$	531,712

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Supplemental Condensed Consolidated Statements of Operations



	Year Ended December 31, 2015
	Parent / Issuer			Guarantor Subsidiaries			Eliminations		Consolidated
Revenue	$	—		$	360,900		$	—	$	360,900
Costs and Expenses:
Operating costs and expenses	—			282,903			—		282,903
Production royalty to related party	—			7,879			—		7,879
Depreciation, depletion, and amortization	1,806			44,142			—		45,948
Asset retirement obligation expenses	—			3,277			—		3,277
Asset impairment and restructuring charges	4,450			134,229			—		138,679
General and administrative expenses	1,978			13,835			—		15,813
Operating loss	(8,234		)	(125,365		)	—		(133,599		)
Other income (expense):
Interest expense, net	(23,901		)	(10,784		)	—		(34,685		)
Other, net	—			5,486			—		5,486
Loss from investments in subsidiaries	(130,006		)	—			130,006		—
Loss before income taxes	(162,141		)	(130,663		)	130,006		(162,798		)
Income taxes	—			657			—		657
Net loss	(162,141		)	(130,006		)	130,006		(162,141		)
Income attributable to non-controlling interests	—			—			—		—
Net loss attributable to common stockholders	$	(162,141	)	$	(130,006	)	$	130,006	$	(162,141	)



	Year Ended December 31, 2014
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	441,833		$	—		$	441,833
Costs and Expenses:
Operating costs and expenses	—			362,294			—			362,294
Production royalty to related party	—			8,269			—			8,269
Depreciation, depletion, and amortization	1,910			44,127			—			46,037
Asset retirement obligation expenses	—			2,099			—			2,099
General and administrative expenses	3,814			15,776			—			19,590
Operating (loss) income	(5,724		)	9,268			—			3,544
Other income (expense):
Interest expense, net	(24,476		)	(8,658		)	—			(33,134		)
Other, net	—			758			—			758
Income from investments in subsidiaries	1,368			—			(1,368		)	—
(Loss) income before income taxes	(28,832		)	1,368			(1,368		)	(28,832		)
Income taxes	—			—			—			—
Net (loss) income	(28,832		)	1,368			(1,368		)	(28,832		)
Income attributable to non-controlling interests	—			—			—			—
Net (loss) income attributable to common stockholders	$	(28,832	)	$	1,368		$	(1,368	)	$	(28,832	)

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Table of Contents



	Year Ended December 31, 2013
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Revenue	$	—		$	415,282		$	—		$	415,282
Costs and Expenses:
Operating costs and expenses	—			335,904			—			335,904
Production royalty to related party	—			7,811			—			7,811
Depreciation, depletion, and amortization	1,750			36,469			—			38,219
Asset retirement obligation expenses	—			2,267			—			2,267
General and administrative expenses	4,947			16,222			—			21,169
Operating (loss) income	(6,697		)	16,609			—			9,912
Other income (expense):
Interest expense, net	(23,611		)	(11,952		)	—			(35,563		)
Other, net	—			579			—			579
Loss from investments in subsidiaries	5,236			—			(5,236		)	—
(Loss) income before income taxes	(25,072		)	5,236			(5,236		)	(25,072		)
Income taxes	—			—			—			—
Net (loss) income	(25,072		)	5,236			(5,236		)	(25,072		)
Income attributable to non-controlling interests	—			—			—			—
Net (loss) income attributable to common stockholders	$	(25,072	)	$	5,236		$	(5,236	)	$	(25,072	)

Supplemental Condensed Consolidating Statements of Comprehensive Income (Loss)



	Year Ended December 31, 2015
	Parent / Issuer			Guarantor Subsidiaries			Eliminations		Consolidated
Net loss	$	(162,141	)	$	(130,006	)	$	130,006	$	(162,141	)
Other comprehensive income (loss):
Postretirement benefit plan and other employee benefit obligations, net of tax	—			1,858			—		1,858
Other comprehensive income	—			1,858			—		1,858
Comprehensive loss	(162,141		)	(128,148		)	130,006		(160,283		)
Less: Comprehensive income (loss) attributable to non-controlling interests	—			—			—		—
Comprehensive loss attributable to common stockholders	$	(162,141	)	$	(128,148	)	$	130,006	$	(160,283	)

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Table of Contents



	Year Ended December 31, 2014
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Net (loss) income	$	(28,832	)	$	1,368		$	(1,368	)	$	(28,832	)
Other comprehensive income (loss):
Postretirement benefit plan and other employee benefit obligations, net of tax	—			(3,004		)	—			(3,004		)
Other comprehensive loss	—			(3,004		)	—			(3,004		)
Comprehensive loss	(28,832		)	(1,636		)	(1,368		)	(31,836		)
Less: Comprehensive income (loss) attributable to non-controlling interests	—			—			—			—
Comprehensive loss attributable to common stockholders	$	(28,832	)	$	(1,636	)	$	(1,368	)	$	(31,836	)



	Year Ended December 31, 2013
	Parent / Issuer			Guarantor Subsidiaries			Eliminations			Consolidated
Net (loss) income	$	(25,072	)	$	5,236		$	(5,236	)	$	(25,072	)
Other comprehensive income (loss):
Postretirement benefit plan, net of tax	—			(737		)	—			(737		)
Other comprehensive income	—			(737		)	—			(737		)
Comprehensive (loss) income	(25,072		)	4,499			(5,236		)	(25,809		)
Less: Comprehensive income (loss) attributable to non-controlling interests	—			—			—			—
Comprehensive (loss) income attributable to common stockholders	$	(25,072	)	$	4,499		$	(5,236	)	$	(25,809	)

Supplemental Condensed Consolidating Statements of Cash Flows



	Year Ended December 31, 2015
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(23,152	)	$	59,395		$	36,243
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development	(2,074		)	(17,731		)	(19,805		)
Proceeds from sale of fixed assets	—			880			880
Net cash used in investing activities	(2,074		)	(16,851		)	(18,925		)
Cash Flows from Financing Activities:
Payment on capital lease obligations	—			(2,714		)	(2,714		)
Payments of long-term debt	—			(6,505		)	(6,505		)
Transactions with affiliates, net	25,226			(25,226		)	—
Net cash provided by (used in) financing activities	25,226			(34,445		)	(9,219		)
Net change in cash and cash equivalents	—			8,099			8,099
Cash and cash equivalents, at the beginning of the period	—			59,518			59,518
Cash and cash equivalents, at the end of the period	$	—		$	67,617		$	67,617

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	Year Ended December 31, 2014
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(27,017	)	$	68,162		$	41,145
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development	(1,463		)	(22,979		)	(24,442		)
Proceeds from sale of fixed assets	—			5			5
Net cash used in investing activities	(1,463		)	(22,974		)	(24,437		)
Cash Flows from Financing Activities:
Payment on capital lease obligations	—			(2,690		)	(2,690		)
Payments of long-term debt	—			(5,942		)	(5,942		)
Payment of financing costs and fees	(1,000		)	—			(1,000		)
Repurchase of employee stock relinquished for tax withholdings	(176		)	—			(176		)
Proceeds from sale leaseback	—			986			986
Transactions with affiliates, net	29,656			(29,656		)	—
Net cash provided by (used in) financing activities	28,480			(37,302		)	(8,822		)
Net change in cash and cash equivalents	—			7,886			7,886
Cash and cash equivalents, at the beginning of the period	—			51,632			51,632
Cash and cash equivalents, at the end of the period	$	—		$	59,518		$	59,518



	Year Ended December 31, 2013
	Parent / Issuer			Guarantor Subsidiaries			Consolidated
Cash Flows from Operating Activities:
Net cash (used in) provided by operating activities:	$	(25,439	)	$	58,383		$	32,944
Cash Flows from Investing Activities:
Investment in property, plant, equipment, and mine development	(1,998		)	(30,838		)	(32,836		)
Issuance of note receivable – related party	(17,500		)	—			(17,500		)
Payment of note receivable – related party	17,500			—			17,500
Proceeds from sale of fixed assets	—			255			255
Net cash used in investing activities	(1,998		)	(30,583		)	(32,581		)
Cash Flows from Financing Activities:
Payment on capital lease obligations	—			(4,547		)	(4,547		)
Payment of long-term debt	—			(3,959		)	(3,959		)
Payment of financing costs and fees	(29		)	—			(29		)
Repurchase of employee stock relinquished for tax withholdings	(332		)	—			(332		)
Non-controlling interest contributions	—			4			4
Transactions with affiliates, net	27,723			(27,723		)	—
Net cash provided by (used in) financing activities	27,362			(36,225		)	(8,863		)
Net change in cash and cash equivalents	(75		)	(8,425		)	(8,500		)
Cash and cash equivalents, at the beginning of the period	75			60,057			60,132
Cash and cash equivalents, at the end of the period	$	—		$	51,632		$	51,632

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23. SUMMARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

A summary of the unaudited quarterly results of operations for the years ended December 31, 2015 and 2014 is presented below.



	2015
	First Quarter			Second Quarter⁽¹⁾		Third Quarter⁽²⁾			Fourth Quarter
Revenue	$	96,335		$	93,139	$	89,206		$	82,220
Gross profit	17,505			22,986		19,363			18,143
Operating (loss) income	(6,906		)	5,428		(136,683		)	4,562
Net (loss) income	(15,254		)	894		(145,786		)	(1,995		)
Net (loss) income attributable to common stockholders	(15,254		)	894		(145,786		)	(1,995		)



	2014
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenue	$	110,866		$	116,287		$	108,935		$	105,745
Gross profit	20,747			21,121			20,867			16,804
Operating income (loss)	2,762			3,907			168			(3,293		)
Net loss	(5,300		)	(4,138		)	(7,798		)	(11,596		)
Net loss attributable to common stockholders	(5,300		)	(4,138		)	(7,798		)	(11,596		)

⁽¹⁾ Operating income for the quarter ended June 30, 2015 includes the refund of $4,482 for a portion of Kentucky sales and use taxes paid on the purchase of certain energy and energy producing fuels for the period of 2008 through 2013.

⁽²⁾ Operating income for the quarter ended September 30, 2015 includes asset impairment and restructuring charges totaling $138,679.

F-34

Large accelerated filer

Accelerated filer

Non-accelerated filer

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Smaller reporting company