Item 1. Business
Overview
Our History
Armstrong Energy, Inc. (together with its subsidiaries, we 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 2013 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 2008, we completed five transactions, either directly or through our affiliate, Armstrong Resource Partners, to acquire mineral reserves and land from Peabody Energy, Inc. (Peabody). We commenced production in the second quarter of 2008 and currently operate seven mines, including four surface and three underground, and are seeking permits for three additional mines. Since 2008, we have continued to acquire additional mineral reserves, which are strategic to our operating plans and currently control approximately 571 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.
Our revenue has increased from zero in 2007 to $415.3 million in the year ended December 31, 2013 and our net loss and adjusted EBITDA for the year ended December 31, 2013 totaled $25.1 million and $58.2 million, respectively.
For the year ended December 31, 2013, we sold 9.3 million tons of coal. We are contractually committed to sell 9.6 million tons of coal in 2014 and 7.8 million tons of coal in 2015.
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, was formed in 2006 as a Delaware limited liability company, and Armstrong Energy, Inc. was previously a wholly-owned subsidiary of Armstrong Land Company, LLC. In August 2011, Armstrong Resources Holdings, LLC merged with and into Armstrong Energy,
Inc., which subsequently changed its name to Armstrong Energy Holdings, Inc. Subsequently, Armstrong Land Company, LLC was converted to a C-corporation and changed its name to Armstrong Energy, Inc., effective October 1, 2011 (the Reorganization). In connection with the Reorganization, each owner of Armstrong Land Company, LLC received 9.25 shares of Armstrong Energy, Inc. common stock for each unit held.
Our Relationship with Armstrong Resource Partners, 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. Armstrong Energy holds a 0.4% equity interest in Armstrong Resource Partners through a wholly-owned subsidiary, Elk Creek GP, LLC (Elk Creek GP), which is the general partner of Armstrong Resource Partners. The outstanding limited partnership interests (common units) of Armstrong Resource Partners, representing 97.8% of its equity interests, are owned by Yorktown. Yorktown is entitled to 97.8% of all distributions made by Armstrong Resource Partners.
Pursuant to the Amended and Restated Agreement of Limited Partnership of Armstrong Resource Partners, L.P. (ARP LPA), Elk Creek GP has the exclusive authority to conduct, direct and manage all activities of Armstrong Resource Partners. Pursuant to the ARP LPA, effective October 1, 2011, Yorktown unilaterally may remove Elk Creek GP as general partner in some circumstances. As a result, beginning October 1, 2011, Armstrong Energy no longer consolidates the results of Armstrong Resource Partners in the financial statements of Armstrong Energy.
Beginning in 2011, Armstrong Resource Partners acquired, through multiple transactions, an undivided interest in certain land and mineral reserves of Armstrong Energy in Muhlenberg and Ohio Counties, Kentucky. In conjunction with the aforementioned acquisitions, Armstrong Energy entered into lease agreements with Armstrong Resource Partners pursuant to which Armstrong Resource Partners 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. See Item 13 - “Certain Relationships and Related-Party Transactions, and Director Independence.”
On February 1, 2014, Armstrong Resource Partners merged with and into Thoroughbred Resources, LLC (Thoroughbred), an entity wholly-owned by Yorktown, with Armstrong Resource Partners as the surviving entity. Effective with the merger, Armstrong Resource Partners changed its name to Thoroughbred Resources, L.P. References to Armstrong Resource Partners and Thoroughbred in this Annual Report on Form 10-K refers to the respective entities prior to effecting the merger, unless otherwise noted. See Item 13 - “Certain Relationships and Related-Party Transactions, and Director Independence” for further information regarding the merger transaction.
Our Mining Operations
We currently operate seven active mines, all of which are located in the Illinois Basin coal region in western Kentucky. Our operations are comprised of four surface mines and three underground mines, and we have three preparation plants serving these operations. In 2013, approximately 53% of the coal that we produced came from our surface mining operations. In addition, we are seeking permits for three additional mines.
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. Coal is transported from our mines to customers by means of railroads, trucks,
and barge lines. We currently own or lease under long-term arrangements a substantial portion of the equipment utilized in our mining operations. We employ sophisticated preventative maintenance and rebuild programs and upgrade our equipment to ensure that it is productive, well-maintained and cost-competitive. Our maintenance programs also employ procedures designed to enhance the efficiencies of our operations.
We control approximately 571 million tons of coal available for production at our active and proposed mines in Ohio and Muhlenberg counties in Western Kentucky, of which we lease approximately 237 million tons from various unaffiliated landowners.
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. Stripping ratios for coal that has not undergone any processing, or “run-of-mine” coal, at the Midway mine averaged approximately 13.1-to-1 in 2013. The Midway mine produced approximately 1.3 million tons of clean coal in 2013 and is currently equipped with one dragline (45 yard bucket) and a spread of surface mining equipment, including power shovels, excavators, loaders and haul trucks. Our reserve studies have indicated that the Midway mine has approximately 17.4 million tons of proven and probable reserves. Coal from the Midway mine is transported less than one mile to the Midway Preparation Plant for processing, where it is then shipped to customers via truck, rail or barge.
Parkway Mine. The Parkway mine is an underground mine located northeast of Central City, Kentucky in Muhlenberg County that extracts thermal coal primarily from the West Kentucky #9 seam and accesses that seam from an older surface mining pit that was abandoned prior to our acquisition of the Parkway mine. The Parkway mine consists of two working super sections, and each section is currently equipped with two continuous miners that operate concurrently. The Parkway mine produced approximately 1.3 million tons of clean coal in 2013. As of December 31, 2013, the Parkway mine currently had approximately 10.7 million tons of proven and probable reserves. The majority of the coal from the Parkway mine is transported to the surface stockpile where it is processed at the Parkway Preparation Plant and trucked to a single customer via a seven mile private haul road.
East Fork Mine. The East Fork mine is a surface mine located three miles west of Centertown, Kentucky. The East Fork complex consists of two pits, the Warden and Kronos pits, which extract thermal coal from the West Kentucky #14 seam. The Kronos pit commenced operations in June 2009, and the Warden pit commenced operations in August 2009. Production at the Kronos pit ceased in August 2011 and production at the Warden pit was temporarily idled in March 2012. There were approximately 3.1 million tons of proven and probable reserves at the East Fork mine at December 31, 2013.
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 2.7 million tons of coal in 2013. The Equality Boot mine uses two draglines equipped with 45 yard buckets and a spread of surface equipment, including power shovels, excavators, loaders and haul trucks to remove overburden and interburden and construct the dragline bench. Run-of-mine stripping ratios at the Equality Boot mine averaged approximately 11.7-to-1 in 2013. The Equality Boot mine had approximately 17.7 million tons of proven and probable reserves as of December 31, 2013. Coal from the Equality Boot mine is transported less than one mile by truck to the Equality Boot run-of-mine facility, where a 4,400 foot overland conveyor system is used to transport the coal to the 2,500 tons per hour barge loadout facility located on the Green River. The coal is then loaded onto barges and transported approximately five miles to the Armstrong Dock Preparation Plant where it is unloaded, processed, reloaded onto barges and then shipped to customers.
Lewis Creek Mine. The Lewis Creek mine is a surface mine located approximately five miles south of Centertown, Kentucky and approximately 3.5 miles from the Midway Preparation Plant. Production 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 0.9 million tons of clean coal in 2013. 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, 2013, there were approximately 4.5 million tons of proven and probable reserves at the Lewis Creek surface mine. Coal mined at the Lewis Creek mine is transported by truck to the Midway Preparation Plant for processing and subsequent delivery to our customers.
Kronos Mine. The Kronos mine, which commenced operations in September 2011, is an underground mine located approximately three miles southwest of Centertown, Kentucky. It extracts thermal coal from the West Kentucky #9 seam. The Kronos mine produced approximately 2.6 million clean tons of coal in 2013. The mine utilizes four continuous miner super sections and there were approximately 35.8 million tons of proven and probable reserves at the Kronos mine as of December 31, 2013. Coal mined at Kronos is transported by truck to the Midway Preparation Plan and by conveyor to the Armstrong Dock Preparation Plant for processing and delivery.
Lewis Creek Underground Mine. The Lewis Creek underground mine, which came out of development in July 2013, produces coal from the West Kentucky #9 seam utilizing two continuous miner super sections operating concurrently. The Lewis Creek underground mine produced approximately 0.4 million clean tons of coal in 2013. We estimate that the saleable production from the Lewis Creek underground mine will be approximately 1.0 million tons annually. As of December 31, 2013, there are approximately 16.6 million tons of proven and probable reserves at the Lewis Creek reserves. Coal mined at the Lewis Creek underground mine is transported by truck to the Midway Preparation Plant for processing and subsequent delivery to our customers.
Future Mines. We continue to evaluate our mine plans and expect to open additional mines in 2015 and 2016 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 2013, 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:
Our Midway Plant is 1,200 tons-per-hour (TPH) raw coal feed, heavy media preparation plant that was constructed in 2008. The plant is connected to the P&L Railroad via a newly-constructed unit train railroad “loop” extension of approximately 16,000 feet, and also includes a coal handling system similar to that present at the Armstrong Dock Plant that permits the loading of coal into railcars or trucks.
The Parkway Preparation Plant is located adjacent to the Parkway mine and has a run-of-mine coal capacity of 400 TPH. Clean coal from the preparation plant is placed in a 60,000 ton capacity stockpile and subsequently loaded into trucks for delivery to our customers.
The Armstrong Dock Plant is a 1,200 TPH raw coal feed, heavy media preparation plant that was constructed in 2008. The plant is connected to a 10,000 ton “donut” storage stockpile and an extensive conveyor handling system. The Armstrong Dock Plant has a coal handling system that permits the loading of coal into barges adjacent to the dock conveyor or into trucks adjacent to the plant itself.
The treatments we employ at our preparation plants depend on the size of the raw coal. For coarse material, the separation process relies on the difference in the density between coal and waste rock where, for the very fine fractions, the separation process relies on the difference in surface chemical properties between coal and the waste minerals. To remove impurities, we crush raw coal and classify it into various sizes. For the largest size fractions, we use dense media vessel separation techniques in which we float coal in a tank containing a liquid of a pre-determined specific gravity. Since coal is lighter than its impurities, it floats, and we can separate it from rock and shale. We treat intermediate sized particles with dense medium cyclones, in which a liquid is spun at high speeds to separate coal from rock. Fine coal is treated in spirals, in which the differences in density between coal and rock allow them, when suspended in water, to be separated. Ultra fine coal is recovered in column flotation cells utilizing the differences in surface chemistry between coal and rock. By injecting stable air bubbles through a suspension of ultra fine coal and rock, the coal particles adhere to the bubbles and rise to the surface of the column where they are removed. To minimize the moisture content in coal, we process most coal sizes through centrifuges. A centrifuge spins coal very quickly, causing water accompanying the coal to separate. Coarse refuse from our preparation plants is back-hauled and disposed of in our mining pits or other locations in accordance with applicable regulations and permits.
Sales and Marketing
Our sales and marketing functions are handled from our St. Louis, Missouri headquarters with assistance from our Madisonville, Kentucky operations center. Prior to 2011, the majority of our coal sales were made through the use of third-party independent contractors who were paid a per-ton commission with respect to the
coal they brokered for sale. Commencing in 2011, the majority of our new coal sales have been made through our in-house Director of Coal Sales, and no new commissions are paid with respect to coal sold by our employees.
Multi-year Coal Supply Agreements
As is customary in the coal industry, we enter into multi-year coal supply agreements with many of our customers. Multi-year coal supply agreements usually have specific and possibly different volume and pricing arrangements for each year of the agreement. These agreements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In 2013, we sold approximately 99% 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, 2013, we had multi-year coal supply agreements with remaining terms ranging from one to six years.
We typically enter into multi-year coal supply agreements through a “request-for-proposal” process and after competitive bidding and negotiations. Therefore, the terms of these agreements vary by customer. Our multi-year coal supply agreements typically contain provisions to adjust the base price due to new laws and regulations that affect our costs. Additionally, some of our agreements contain provisions that allow for the recovery of costs affected by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities.
The price of coal sold under certain of our agreements is subject to fluctuation. For example, some of our agreements include index provisions that change the price based on changes in market-based indices and or changes in economic indices. Other agreements contain price reopener provisions that may allow a party to renegotiate pricing at a set time. Price reopener provisions may automatically set a new price based on then-current market prices or require us to negotiate a new price. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to terminate the agreement. In addition, certain of our agreements contain clauses that may allow customers to terminate the agreement in the event of certain changes in environmental laws and regulations that impact their operations.
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.
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, 2013, 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 six years, but we also supply coal on a spot basis for some of our customers.
In 2013, 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, 2013, we derived approximately 42% and 34% of our total coal revenues from sales to our two largest customers, Louisville Gas & Electric and Tennessee Valley Authority, respectively.
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 2013 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 2013, approximately 23% and 26 % of our coal sales tonnage also 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., Patriot Coal Corp., Peabody Energy, Inc., the Cline Group’s Foresight Energy LLC, Oxford Resource Partners, LP and Murray Energy, all of which are companies mining in the Illinois Basin. Many of these coal producers have greater financial resources and more proven and probable reserves than we do. Based on data from the Mine Safety and Health Administration (MSHA), we were the fifth largest producer of Illinois Basin coal in fiscal 2013, producing approximately 7% of the total Illinois Basin coal. As the price of domestic coal increases, we also compete with companies that produce coal from one or more foreign countries, such as Colombia, Indonesia and Venezuela.
The most important factors on which we compete are price, quality and characteristics, transportation costs and reliability of supply. The demand for our coal and the prices that we will be able to obtain for our coal are closely related to coal consumption patterns of the U.S. electric generation industry and international consumers. The patterns of coal consumption are affected by various factors beyond our control, including economic conditions, temperatures in the United States, government regulation, technological developments and the location, quality, price and availability of competing sources of fuel such as natural gas, oil and nuclear sources, and alternative energy sources such as hydroelectric power and wind.
Our Safety Programs
Our safety programs include: (i) employing 12 full-time safety professionals; (ii) implementing policies and procedures to protect employees and visitors at our mines; (iii) utilizing experienced third-party blasting professionals to conduct our blasting activities; (iv) requiring a certified surface mine foreman to be in charge of the activities at each mine; and (v) ensuring that each employee undergoes the required safety, hazard and task training.
We have won numerous awards for our safety record since 2008 recognizing our low injury and incident rates, as follows:
On October 28, 2011, an accident occurred at the Company’s Equality Boot mine and, tragically, two employees of a local blasting company were killed when rock fell from the highwall to the pit floor where they were travelling. Following the accident, pursuant to Section 103(k) of the Mine Act, MSHA issued an order prohibiting all activity at the Equality Boot Mine until MSHA determined that it was safe to resume normal mining operations. On November 2, 2011, MSHA modified the 103(k) order to permit the Company to resume mining the #14 seam in the Equality Boot mine.
On November 8, 2011, the Company submitted a ground control plan addendum to MSHA, which was approved the same day, and subsequently incorporated into the Company’s mining operations at the Equality Boot mine. As a result, on November 8, 2011, MSHA modified the 103(k) order to permit the Company to resume normal mining activities in all areas of the Equality Boot mine until such time as the Commonwealth of Kentucky completes its accident report concerning the incident.
On February 7, 2012, the Kentucky Office of Mine Safety and Licensing issued its Fatal Accident Report. The Commonwealth of Kentucky concluded that the failure of the highwall occurred where the rock strata transitioned from wide bands of shale to smaller bands on laminated rock, thus creating a slicken slide fault in the area where the rock fell. The Kentucky Office of Mine Safety and Licensing did not find any causes or circumstances, which contributed to the accident other than the aforementioned naturally occurring geological condition.
Finally, on May 7, 2012, MSHA issued its final Investigation Report concerning the accident. Similar to the findings of the Kentucky Office of Mine Safety and Licensing, MSHA concluded that the accident occurred because of a geologic anomaly located in the portion of the highwall below the #14 coal seam and above the #13 coal seam where there were two intersecting or nearly intersecting discontinuities in the rock formation. Although MSHA concluded that personnel at the Equality Boot mine had failed to recognize the anomaly and issued five Section 104(a) citations in connection with the accident, MSHA did not issue any citations finding high negligence or reckless disregard on the part of the Company or its employees.
Suppliers
We use various supplies and raw materials in our coal mining operations, such as petroleum-based fuels, explosives, tires and steel, as well as spare parts and other consumables. We use third-party suppliers for a significant portion of our equipment rebuilds and repairs, drilling services and construction. We use sole source suppliers for certain parts of our business, such as explosives and fuel, and preferred suppliers for other parts at our business, such as dragline and shovel parts and related services. We believe adequate substitute suppliers are available.
Employees
At December 31, 2013, we employed approximately 1,046 employees, none of whom is represented for collective bargaining by a union. We believe that our relations with all employees are good.
Seasonality
Our business has historically experienced some variability in its results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as floods or blizzards, can impact our ability to mine and ship our coal and our customers’ ability to take delivery of coal.
Regulation and Laws
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as:
•
employee health and safety;
•
permitting and licensing requirements;
•
air quality standards;
•
water pollution;
•
storage, treatment and disposal of wastes;
•
protection of plant life and wildlife, including endangered or threatened species;
•
reclamation and restoration of mining properties after mining is completed;
•
remediation of contaminated soil and groundwater;
•
surface subsidence from underground mining;
•
the effects of mining on surface and groundwater quality and availability; and
•
competing uses of adjacent, overlying or underlying lands, pipelines, roads and public facilities.
In addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal.
The costs of compliance with these laws and regulations have been and are expected to continue to be significant. Future laws, regulations or orders, as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders, may substantially increase equipment and operating costs, result in delays and disrupt operations or termination of operations, the extent of which cannot be predicted with any degree of certainty. Changes in applicable laws or the adoption of new laws relating to energy production may cause coal to become a less attractive source of energy. For example, if emissions rates or caps on greenhouse gases are enacted or a tax on carbon is imposed, the market share of coal as fuel used to generate electricity would be expected to decrease. Thus, future laws, regulations or enforcement priorities may adversely affect our mining operations, cost structure or the demand for coal.
We are committed to operating our mines in compliance with applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. Violations, including violations of any permit or approval, can result in substantial civil and criminal fines and penalties, including revocation or suspension of mining permits. None of the violations we have experienced to date have had a material impact on our operations or financial condition.
Mining Permits and Approvals
Numerous governmental permits and approvals are required for our coal mining operations. When we apply for some of these, we are required to assess the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization and permitting requirements imposed by governmental authorities are costly and may delay or prevent commencement or continuation of mining operations in certain locations. These requirements may also be supplemented, modified or re-interpreted from time to time. Past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
In order to obtain mining permits and approvals from federal and state regulatory authorities, mine operators or applicants must submit a reclamation plan for restoring the mined land to its prior productive use, better condition or other approved use. Typically, we submit the necessary permit applications several months, or even
years, before we plan to mine a new area. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all, particularly those permits involving the federal Clean Water Act (the CWA). Specifically, issuance of Corps permits allowing placement of material in valleys or streams has been slowed in recent years due to ongoing disputes over the requirements for obtaining such permits. While we do not engage in mountaintop mining, we are required to obtain permits from the Corps and our mining operations do impact bodies of water regulated by the Corps. The application review process takes longer to complete and permit applications are increasingly being challenged by environmental and other advocacy groups, although we are not aware of any such challenges to any of our pending permit applications. We may experience difficulty or delays in obtaining mining permits or other necessary approvals in the future, or even face denials of permits altogether.
Violations of federal, state and local laws, regulations or any permit or approval issued under such authorization can result in substantial fines and penalties, including revocation or suspension of mining permits and, in certain circumstances, criminal sanctions.
Surface Mining Control and Reclamation Act
The Surface Mining Control and Reclamation Act of 1977 (the SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement within the Department of the Interior (OSM), establishes operational, reclamation and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. Mining operators must obtain SMCRA permits and permit renewals from the OSM or from the applicable state agency if the state has obtained primacy. A state may achieve primacy if it develops a regulatory program that is no less stringent than the federal program and is approved by OSM. SMCRA stipulates compliance with many other major environmental statutes, including the federal Clean Air Act, the CWA, the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund). Our mines are located in Kentucky, which has primacy to administer the SMCRA program.
Some SMCRA mine permits take us over a year to prepare, depending on the size and complexity of the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Also, before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of all reclamation obligations. After the application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for this process to take from a year to several years for a SMCRA mine permit to be issued. This variability in time frame for permitting is a function of the discretion vested in the various regulatory authorities’ handling of comments and objections relating to the project that may be received from the governmental agencies involved and the general public. The public also has the right to comment on and otherwise engage in the permitting process, including at the public hearing and through judicial challenges to an issued permit.
Federal laws and regulations also provide that a mining permit or modification can be delayed, refused or revoked if owners of specific percentages of ownership interests or controllers (i.e., officers and directors or other entities) of the applicant have, or are affiliated with another entity that has outstanding violations of SMCRA or state or tribal programs authorized by SMCRA. This condition is often referred to as being “permit blocked” under the federal Applicant Violator Systems. Thus, non-compliance with SMCRA can provide the bases to deny the issuance of new mining permits or modifications of existing mining permits. We know of no basis to be, and are not, permit-blocked.
In 1983, the OSM adopted the “stream buffer zone rule” (SBZ Rule), which prohibited mining disturbances within 100 feet of streams if there would be a negative effect on water quality. In December 2008, the OSM finalized a revised SBZ Rule, which purported to clarify certain aspects of the 1983 SBZ Rule. Several organizations challenged the 2008 revision to the SBZ Rule in two related actions filed in the U.S. District Court for the District of Columbia. In August 2009, the District Court concluded that the revised SBZ Rule could not be
vacated without following the Administrative Procedure Act and other related requirements. In November 2009, the OSM published an advanced notice of proposed rulemaking to further revise the SBZ Rule. In a March 2010 settlement with litigation parties, OSM agreed to use its best efforts to adopt a final rule by June 2012. To date, the SBZ Rule has not been finalized, and it is unclear when the SBZ Rule will be promulgated. The revised SBZ Rule, when adopted, may be stricter than the SBZ Rule promulgated in December 2008 in order to further protect streams from the impacts of surface mining, and it may adversely affect our business and operations. In addition, legislation has been introduced in Congress in the past, and may be introduced in the future, in an attempt to preclude placing any fill material in streams. Implementation of new requirements or enactment of such legislation could negatively impact our future ability to conduct certain types of mining activities.
In addition to the bond requirement for an active or proposed permit, the Abandoned Mine Land Fund (AML), which was created by SMCRA, imposes a fee on all coal produced. The proceeds of the fee are used to restore mines closed or abandoned prior to SMCRA’s adoption in 1977. Currently, the fee is $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from 2013 to 2021. In 2013, we recorded approximately $1.8 million of expense related to these reclamation fees.
Surety Bonds
Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator 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 our reclamation obligations. Many of these bonds are renewable on a yearly basis. We cannot predict our ability to obtain bonds or other approved forms of performance security, or the cost of such security, in the future. As of December 31, 2013, we had approximately $40.0 million in surety bonds outstanding to secure the performance of our reclamation obligations which are collateralized by cash deposits of approximately $4.0 million.
On July 3, 2013, the Kentucky Department for Natural Resources (KDNR) filed administrative regulations to implement the Kentucky Reclamation Guaranty Fund (RGF). These regulations result from the March 2, 2013 enactment of House Bill 66, which established the RGF. The RGF provides money, in addition to permit specific reclamation bonds, to ensure completion of necessary reclamation imposed by mining permits. The regulations detail record keeping, reporting, and fee collection procedures for the RGF. In addition to absorbing the assets of the existing Voluntary Bond Pool, each permittee must pay a $1,500 start-up assessment, and each active permit will be assessed $10 per acre. Permittees will have 30 days after the invoice to pay or contest the initial assessment. Continued capitalization of the RGF is accomplished through yearly fees. Beginning January 2014, a coal production fee will be assessed at the rate of $0.0757 per ton of surface mined coal and $0.0357 per ton of underground mined coal. Active non-mining permits, such as preparation plants, haul roads, and refuse disposal areas, will be assessed $10 per acre. Active but non-producing permits will be assed $6 per acre. While all permittees are initially included in the RGF, each permittee may elect to opt-out in exchange for posting full-cost reclamation bonds. The regulations also detail procedures for opting out of the RGF and the method for calculating full cost reclamation bonds.
Mine Safety and Health
Stringent health and safety standards have been in effect since the enactment of the Federal Coal Mine Health and Safety Act of 1969. The Mine Act provided for MSHA and significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. It requires periodic inspections of surface and underground coal mines and the issuance of citations or orders for
the violation of a mandatory health and safety standard. A civil penalty must be assessed for each citation or order issued. Serious violations of mandatory health and safety standards may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators who knowingly or willfully violate a mandatory health and safety standard, or order and provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly or willfully violate a mandatory health and safety standard or order. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards. In addition to federal regulatory programs, the State of Kentucky in which we operate, also has programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. Such regulation has a significant effect on our operating costs.
In 2006, in response to underground mine accidents, Congress enacted the MINER Act. Among other things, it: (i) imposed additional obligations on coal operators related to (a) developing new emergency response plans that address post-accident communications, tracking of miners, breathable air, lifelines, training and communication with local emergency response personnel, (b) establishing additional requirements for mine rescue teams, and (c) promptly notifying federal authorities of incidents that pose a reasonable risk of death; and (ii) increased penalties for violations of applicable federal laws and regulations. In addition, in October, 2010, MSHA published a proposed rule to reduce the permissible concentration of respirable dust in underground coal mines from the current standard of 2.0 milligrams per cubic meter of air to 1.0 milligram per cubic meter. We believe MSHA is also likely to adopt new safety standards for proximity protection for miners that will require certain underground mining equipment to be equipped with devices that will shut the equipment down if a person is too close to the equipment to avoid injuries where individuals are caught between equipment and blocks of unmined coal. Various states also have enacted their own new laws and regulations addressing many of these same subjects. In the wake of several recent underground mine accidents, enforcement scrutiny has also increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions.
Our compliance with current or future mine health and safety regulations could increase our mining costs. At this time, it is not possible to predict the full effect that the new or proposed statutes, regulations and policies will have on our operating costs, but they will increase our costs and those of our competitors. Some, but not all, of these additional costs may be passed on to customers.
We are required to compensate employees for work-related injuries under various state workers’ compensation laws. Our costs will vary based on the number of accidents that occur at our mines and other facilities, and our costs of addressing these claims. We provide benefits to our employees by being insured through state-sponsored programs or an insurance carrier where there is no state-sponsored program.
Black Lung
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to eligible claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. The excise tax does not apply to coal shipped outside the United States. During 2013 and 2012, we recorded $7.3 million and $6.4 million, respectively, of expense related to this excise tax.
In December 2000, the Department of Labor amended regulations implementing the federal black lung laws to, among other things, establish a presumption in favor of a claimant’s treating physician and limit a coal
operator’s ability to introduce medical evidence regarding the claimant’s medical condition. Due to these changes, the number of claimants who are awarded benefits has since increased, and will continue to increase, as will the amounts of those awards. The Patient Protection and Affordable Care Act (PPACA), which was implemented in 2010, provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in coal mines and suffer from totally disabling lung disease. A coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner’s work. Second, it changed the law so black lung benefits being received by miners automatically go to their dependent survivors, regardless of the cause of the miner’s death. Our payment obligations for federal black lung benefits to claimants entitled to such benefits are either substantially secured by insurance coverage or paid from a tax exempt trust established for that purpose. Based on actuarial reports and required funding levels, from time to time we may have to supplement the trust corpus to cover the anticipated liabilities going forward. These regulations may have a material impact on our costs expended in association with the federal Black Lung program. In addition, we could be held liable under various Kentucky statutes for black lung claims.
Clean Air Act
The federal Clean Air Act and the amendments thereto and state laws that regulate air emissions both directly and indirectly affect coal mining operations. Direct impacts on our coal mining and processing operations include Clean Air Act permitting requirements and control requirements for particulate matter, which includes fugitive dust from roadways, parking lots, and equipment such as conveyors and storage piles.
In June 2010, several environmental groups petitioned the EPA to list coal mines as a source of air pollution and establish emissions standards under the Clean Air Act for several pollutants, including particulate matter, NOx, volatile organic compounds and methane. Petitioners further requested that the EPA regulate other emissions from mining operations, including dust and clouds of NOx associated with blasting operations. If the petitioners are successful, emissions of these or other materials associated with our mining operations could become subject to further regulation pursuant to existing laws such as the Clean Air Act. In that event, we may be required to install additional emissions control equipment or take other steps to lower emissions associated with our operations, thereby reducing our revenues and adversely affecting our operations.
The Clean Air Act indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, SO2, NOx, carbon monoxide, ozone, mercury and other compounds emitted by coal-fired power plants, which are the largest end users of our coal. In addition to developments directed at limiting greenhouse gas emissions, which are discussed separately further below, air emission control programs that affect our operations, directly or indirectly, include, but are not limited to, the following:
•
Acid Rain. Title IV of the Clean Air Act requires reductions of SO2 and NOx emissions by electric utilities regulated under the Acid Rain Program (AR Program). Under the AR Program, a cap on annual SO2 emissions is established and then EPA issues allowances to regulated entities up to the cap using defined formulas. Each power plant must have enough allowances to cover all its annual SO2 emissions or pay penalties. Affected power plants have sought to reduce SO2 emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading SO2 emissions allowances. The AR Program makes it more costly to operate coal-fired power plants and could make coal a less attractive fuel alternative in the planning and building of power plants in the future.
•
New National Ambient Air Quality Standards. The federal Clean Air Act requires the EPA to determine and, where appropriate, from time to time update ambient air quality standards applicable nationwide, known as national ambient air quality standards (NAAQSs) for six common air pollutants. NAAQSs can result in sources having to meet substantially stricter emissions limitations for such pollutants upon renewal of their air permits, which commonly are issued for five-year terms. Coal combustion generates or affects several pollutants subject to NAAQSs, including SO2, NOx, ozone, and particulate
matter, so when any such standard is made stricter, it may indirectly affect our customers’ current or anticipated future costs of using coal. The EPA has revised and/or proposed to revise a number of such NAAQSs in recent years. For example, in June 2010, the EPA issued a stricter NAAQS for SO2 emissions which, among other things, establishes a new one-hour standard at a level of 75 parts per billion to protect against short-term exposure and minimize health-based risks, revokes the previous 24-hour and annual standard for SO2, and imposes requirements for monitoring and reporting SO2 concentrations. In February 2010, the EPA issued a stricter NAAQS for NOx and in January 2010 also proposed a revised, stricter ground-level ozone NAAQS. In addition, in 2006 the EPA issued stricter NAAQSs for particulate matter and subsequently has been implementing, and reviewing state implementation of, those standards.
•
Mercury. In February 2012, the EPA published its final rule to establish a national standard to reduce mercury and other toxic air pollutants from coal and oil-fired power plants, sometimes referred to as the EPA’s MATS. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has also been proposed from time to time. In addition, in March 2011, EPA issued new MACT determinations for several classes of boilers and process heaters, including large coal-fired boilers and process heaters, which would require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury; in May the effective date of these rules for major sources was delayed for reconsideration of certain aspects of the rule and in December 2011, the EPA published a reconsideration proposal for public comment.
•
New Source Review. A number of enforcement actions in recent years are affecting the impact of the EPA’s New Source Review (NSR) program as applied to some existing sources, including certain coal-fired power plants. The NSR program requires existing coal-fired power plants, when undertaking certain modifications, to install the same air emissions control equipment as new plants. Enforcement proceedings alleging that such modifications were made without implementing the required control equipment have resulted in a number of settlements involving commitments, including those by coal- fired power plants, to incur extensive air emissions controls involving substantial expenses. Such enforcement, and other changes affecting the scope or interpretation of aspects of the NSR program, may impact demand for coal, but we are unable to predict the magnitude of any such impact on us with any reasonable degree of certainty.
Climate Change
CO2 is a “greenhouse gas,” the man-made emissions of which are of major concern under any regulatory framework intended to control what is sometimes referred to as “global warming” or, due to other possible impacts on climate that many policy-makers and scientists believe such warming may have, “climate change.” CO2 is a major by-product of the combustion process within coal-fired power plants. Methane, which must be expelled from our underground coal mines for mining safety reasons, also is classified as a greenhouse gas.
Considerable and increasing government attention in the United States and other countries is being paid to reducing greenhouse gas emissions, including CO2 from coal-fired power plants and methane emissions from mining operations. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. To date, the U.S. has not ratified the Kyoto Protocol, which was scheduled to expire in 2012, but was extended for five years at the UNFCCC Conference of Parties in Durban, South Africa in December 2011. A replacement treaty or other international arrangement requiring additional reductions in greenhouse gas emissions could have a potentially significant impact on the demand for coal, particularly if the United States were to adopt it but, depending on the requirements it imposes and the extent to which other nations adopt it, even if the United States does not adopt it.
Future regulation of greenhouse gases in the United States could occur pursuant to, for example, future U.S. treaty commitments; new domestic legislation that imposes a tax on greenhouse gas emissions, a greenhouse gas cap-and-trade program or other programs aimed at greenhouse gas reduction; or regulatory programs that may be established by the EPA under its existing authority. Congress has actively considered various proposals to reduce greenhouse gas emissions, mandate electricity suppliers to use renewable energy sources to generate a certain percentage of power, promote the use of clean energy and require energy efficiency measures. In June 2009, the House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act, and the Senate has considered similar legislation that would, among other things, impose a nationwide cap on greenhouse gas emissions and require major sources, including coal-fired power plants, to obtain “allowances” to meet that cap. Passage of such comprehensive climate change or energy legislation could impact the demand for coal. Any reduction in the demand for coal by North American electric power generators could reduce the price of coal that we mine and sell and thereby reduce our revenues, which could have a material adverse effect on our business and the results of our operations.
Even in the absence of new federal legislation, greenhouse gas emissions may be regulated in the future by the EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. Environmental Protection Agency that the EPA has authority to regulate greenhouse gas emissions under the Clean Air Act, the EPA has taken several steps towards implementing regulations regarding greenhouse gas emissions. In December 2009, the EPA issued a finding that CO2 and certain other greenhouse gases emitted by motor vehicles endanger public health and the environment. This finding allows the EPA to begin regulating greenhouse gas emissions under existing provisions of the Clean Air Act. In October 2009, the EPA published a final rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their greenhouse gas emissions to the EPA beginning in 2011 for emissions occurring in 2010. In May 2010, the EPA issued a final “tailoring rule” that determines which stationary sources of greenhouse emissions need to obtain a construction or operating permit, and install best available control technology for greenhouse gas emissions, under the Clean Air Act’s Prevention of Significant Deterioration or Title V programs when such facilities are built or significantly modified. Without the tailoring rule, permits would have been required for stationary sources with emissions that exceed either 100 or 250 tons per year (depending on the type of source), which the EPA considered not feasible. The tailoring rule substantially increases this threshold for greenhouse gas emissions to 75,000 tons per year beginning in January 2011, and further modifies the threshold after July 2011; the EPA has stated that the rule will be limited to the largest greenhouse gas emitters in the United States, primarily power plants, refineries, and cement production facilities that the EPA estimates are responsible for nearly 70% of greenhouse gas emissions from the country’s stationary sources. The tailoring rule also commits the EPA to undertake and complete another rulemaking by no later than July 2012 to, among other things, consider expanding permitting requirements to sources with greenhouse gas emissions greater than 50,000 tons per year; in March 2012, the EPA proposed to continue using the current threshold rather than expand the permitting requirements at this point. A number of lawsuits have been filed challenging the tailoring rule. The final outcome of federal legislative action on greenhouse gas emissions may change one or more of the foregoing final or proposed EPA findings and regulations. If the EPA were to set emission limits or impose additional permitting requirements for CO2 from coal-fired power plants, the amount of coal our customers purchase from us could decrease.
On March 27, 2012, the EPA proposed new emission standards seeking to limit the amount of CO2 emissions from new fossil fuel-fired electric utility generating power plants. The proposed rule would require new plants greater than 25 megawatts electric to meet an output based standard of 1,000 pounds of CO2 per megawatt hour, based on the performance of natural gas combined cycle technology. New coal-fired power plants could meet the standard either by employing carbon capture and storage technology at start up or through later application of such technologies provided that the aforementioned output standard was met on average over a 30-year period. On September 20, 2013, the EPA issued revised proposed standards for new electric utility generating units and simultaneously withdrew the previously published 2012 proposed standards. The proposed standards for new power plants would set an output based emissions limit of 1,100 pounds of carbon dioxide per megawatt-hour over a 12 month operating period or 1,000 to 1,050 lbs/MWh of electricity for fossil fuel-fired
electric utility generating units over an 84 month operating period, respectively, and a standard of 1,000 lbs/MWh or 1,100 lbs/MWh for new natural gas-fired plants (depending on the size). These new standards could require fossil fuel-fired electric utility generating units to install CCS technologies. If adopted, the proposed rules could negatively impact the price of coal such that it would be less attractive to utilities and ratepayers. Moreover, there is currently no large-scale use of carbon capture and storage technologies in domestic coal-fired power plants, and as a result, there is a risk that such technology may not be commercially practical for use in limiting emissions as otherwise required by the proposed rule.
Many states and regions have adopted greenhouse gas initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of greenhouse gases by certain facilities. For example, beginning in January 2009, the Regional Greenhouse Gas Initiative (RGGI), a regional greenhouse gas cap-and-trade program, began its first control period, operating with 10 Northeastern and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont). Midwestern states and Canadian provinces have also adopted initiatives to reduce and monitor greenhouse gas emissions. In November 2007, Illinois, Iowa, Kansas, Michigan, Minnesota, South Dakota and Wisconsin signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce greenhouse gas emissions; also, Indiana, Ohio and Manitoba signed as observers. Climate change initiatives are also being considered or enacted in some western states.
Also, litigation to address climate change impacts is being pursued against major emitters of greenhouse gases. A federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of CO2; while the United States Supreme Court recently reversed the appeals court, it did not reach the question whether state common law is available for such claims because that question had not been addressed by the lower court. A second federal appeals court had earlier dismissed a case seeking damages allegedly caused by climate change that had been filed against scores of large corporate defendants, including a number of electrical power generating companies and coal companies, but the dismissal was on procedural grounds; the case has since been re-filed. Claims seeking remedies to address conditions or losses allegedly caused by climate change that in turn allegedly has resulted from greenhouse gas-generating conduct by the defendants remain pending in the courts. Such claims could continue to be asserted against our customers in the future, and might also be asserted against us; accordingly, such claims could adversely affect us either directly or indirectly.
In addition to direct regulation of greenhouse gases, over 30 states have adopted mandatory “renewable portfolio standards,” which require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Several other states have renewable portfolio standard goals that are not yet legal requirements. Additional states may adopt similar goals or requirements, and federal legislation has been repeatedly proposed in this area although no bills imposing such requirements have been enacted into law to date. To the extent these requirements affect our current and prospective customers, their demand for coal-fueled power may decline, which may reduce long-term demand for our coal.
These and other current or future climate change rules, court orders or other legally enforceable mechanisms may in the future require, additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to switch from coal to lower greenhouse gas emitting fuels or to shut down coal-fired power plants. There can be no assurance at this time that a greenhouse gas cap-and-trade program, a greenhouse gas tax or other regulatory regime, if implemented by the states in which our customers operate or at the federal level, or future court orders or other legally enforceable mechanisms, will not affect the future market for coal in those regions. The permitting of new coal-fired power plants has also recently been contested by some state regulators and environmental organizations based on concerns relating to greenhouse gas emissions. Increased efforts to control greenhouse gas emissions could result in reduced demand for coal.
Clean Water Act
The CWA and corresponding state and local laws and regulations affect coal mining operations by restricting the discharge of pollutants, including the discharge of dredged or fill materials, into waters of the United States. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. Recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease our costs and time spent on CWA compliance.
CWA requirements that may directly or indirectly affect our operations include the following:
•
Wastewater Discharge. Section 402 of the CWA regulates the discharge of “pollutants” into navigable waters of the United States. The National Pollutant Discharge Elimination System (NPDES) requires a permit for any such discharges and entails regular monitoring, reporting and compliance with performance standards, all of which are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. Failures to comply with the CWA or the NPDES permits can lead to the imposition of penalties, compliance costs and delays in coal production. The CWA and corresponding state laws also protect waters that states have designated for special protections, including those designated as: impaired (i.e., as not meeting present water quality standards) through Total Maximum Daily Load (TMDL) regulations and “high quality/exceptional use” streams through anti-degradation regulations, which restrict or prohibit discharges which result in degradation. Likewise, when water quality in a receiving stream is better than required, states are required to adopt an “anti-degradation policy” by which further “degradation” of the existing water quality is reviewed and possibly limited. In the case of both the TMDL and anti-degradation review, the limits in our NPDES discharge permits could become more stringent, thereby potentially increasing our treatment costs and making it more difficult to obtain new surface mining permits. Other requirements may result in obligations to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; and to take measures intended to protect streams, wetlands, other regulated water sources and associated riparian lands from surface mining and/or the surface impacts of underground mining. Individually and collectively, these requirements may cause us to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.
•
Dredge and Fill Permits. Many mining activities, including the development of settling ponds and other impoundments, may require a Section 404 permit from the Corps, prior to conducting such mining activities where they involve discharges of “fill” into navigable waters of the United States. The Corps is empowered to issue “nationwide” permits (each, an NWP) for specific categories of filling activities that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404 of the CWA. Using this authority, the Corps issued NWP 21, which authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Individual Section 404 permits are required for activities determined to have more significant impacts to waters of the United States.
Since 2003, environmental groups have pursued litigation primarily in West Virginia and Kentucky challenging the validity of NWP 21 and various individual Section 404 permits authorizing valley fills associated with surface coal mining operations (primarily mountain-top removal operations). This litigation has resulted in delays in obtaining these permits and has increased permitting costs. The most recent major decision in this line of litigation is the opinion of the U.S. Court of Appeals for the Fourth Circuit in Ohio Valley Environmental Council v. Aracoma Coal Company, 556 F.3d 177 (2009) (Aracoma), issued in February 2009. In Aracoma, the Court rejected all of the substantive challenges to the Section 404 permits involved in the case primarily by deferring to the expertise of the Corps in review of the permit applications. After this decision was published, however, the EPA undertook several initiatives to address the issuance of Section 404 permits for coal mining activities in the Eastern U.S. First, the EPA began to comment on Section 404 permit applications pending before
the Corps raising many of the same issues decided in favor of the coal industry in Aracoma. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. These letters have created regulatory uncertainty regarding the issuance of Section 404 permits for coal mining operations and have substantially expanded the time required for issuance of these permits, particularly in the Appalachian region.
In June 2009, the Corps, the EPA and the Department of the Interior announced an interagency action plan for “enhanced coordination procedures” in reviewing any project that requires both a SMCRA and a CWA permit, designed to reduce the harmful environmental consequences of mountain-top mining in the Appalachian region. As part of this interagency memorandum of understanding, the Corps proposed to suspend and modify NWP 21 in the Appalachian region of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia to prohibit its use to authorize discharges of fill material into waters of the United States for mountain-top mining.
On February 16, 2012, but effective March 19, 2012, the Corps reissued 49 NWPs, including NWP 21, authorizing mining activities in streams and wetlands under Section 404 of the CWA and Section 10 of the Rivers and Harbors Act of 1899. In June 2010, the Corps announced the suspension of the NWP 21 permitting process in the Appalachian region of six states until the Corps took further action on it. The reissued NWP 21 will allow surface mining operations to disturb up to 0.5-acre of waters of the U.S. and 300 linear feet of stream bed. The 300 linear foot limit can be waived by the District Engineer for intermittent and ephemeral streams. Valley fills are specifically excluded from NWP 21. The most frequent use of this permit is most likely to be for placement of sediment control structures in intermittent or ephemeral streams when mining in steep terrain. To qualify for a NWP 21, a Pre-Construction Notification must be submitted to the Corps. If a mining operation has a NWP 21 permit authorized under the 2007 NWP 21 criteria and all or part of the permitted area is undisturbed as of March 18, 2012, the original NWP can be reauthorized by the Corps District Engineer without the newly introduced 0.5-acre limit of waters of the U.S. and 300 linear feet of stream bed. Requests for reauthorization of the 2007 NWP must be submitted to the District Engineer by February 1, 2013, and this reauthorization does not apply to valley fill construction.
The EPA is also taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia, and announced in September 2009 that it was delaying the issuance of 74 Section 404 permits in central Appalachia. This is especially true in West Virginia, where the EPA plans to review all applications for NPDES permits even though the State of West Virginia is authorized to issue NPDES permits in West Virginia. In addition, in April 2010, the EPA issued an interim guidance document on water quality requirements for coal mines in Appalachia. This guidance follows up on the June 2009 enhanced coordination procedures memorandum for the issuance of Section 404 permits whereby the EPA undertook a new level of review of Section 404 permits than it had previously undertaken. Ultimately, the EPA identified 79 coal-related applications for Section 404 permits that would need to go through that process. The EPA’s actions in issuing the enhanced coordination procedures memorandum and the guidance are being challenged in a lawsuit pending before the U.S. District Court of the District of Columbia in a case captioned National Mining Assoc. v. U.S. Environmental Protection Agency. In a ruling issued in January 2011, the District Court held that these measures “are legislative rules that were adopted in violation of notice and comment requirements.” The court would not grant the motion for a preliminary injunction to enjoin further use of these measures but also refused to dismiss the Complaint as the EPA had sought. In July 2011, after a notice and comment process, the EPA issued final guidance on review of Appalachian surface coal mining operations that replaced the interim guidance it had issued in April 2010.
In January 2011 the EPA exercised its “veto” power under Section 404(c) of the CWA to withdraw or restrict the use of previously issued permits in connection with the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action is the first time that such power was exercised with regard to a previously permitted coal mining
project. These initiatives have extended the time required for operations affected by them to obtain permits for coal mining, and the costs associated with obtaining and complying with those permits may increase substantially. Additionally, while it is unknown precisely what other future changes will be implemented as a result of the interagency action plan, any future changes could further restrict our ability to obtain other new permits or to maintain existing permits.
Section 404(q) of the CWA establishes a requirement that the Secretary of the Army and the Administrator of the EPA enter into an agreement assuring that delays in the issuance of permits under Section 404 are minimized. In August 1992, the Department of the Army and the EPA entered into such an agreement. The 1992 Section 404(q) MOA outlines the current process and time frames for resolving disputes in an effort to issue timely permit decisions. Under this MOA, the EPA may request that certain permit applications receive a higher level of review within the Department of Army. In these cases, the EPA determines that issuance of the permit will result in unacceptable adverse effects to ARNI. Alternately, the EPA may raise concerns over Section 404 program policies and procedures. An ARNI is a resource-based threshold used to determine whether a dispute between the EPA and the Corps regarding individual permit cases are eligible for elevation under the MOA. Factors used in identifying ARNIs, include the economic importance of the aquatic resource, rarity or uniqueness, and/or importance of the aquatic resource to the protection, maintenance, or enhancement of the quality of the waters.
Resource Conservation and Recovery Act
The RCRA was enacted in 1976 to establish requirements for the management of hazardous wastes from the point of generation through treatment and disposal. RCRA does not apply to certain wastes generated at coal mines, such as overburden and coal cleaning wastes, because they are not considered hazardous wastes as the EPA applies that term. Only a small portion of the wastes generated at a mine are regulated as hazardous wastes.
Although RCRA has the potential to apply to wastes from the combustion of coal, the EPA determined in 1993 with respect to certain coal combustion wastes, and in May 2000 with respect to others, that coal combustion wastes do not warrant regulation as hazardous wastes under RCRA. Most state solid waste laws also regulate coal combustion wastes as non-hazardous wastes. In May 2010, the EPA issued proposed regulations governing management and disposal of coal ash from coal-fired power plants. The EPA sought public comment on two regulatory options. Under the more stringent option, the EPA would regulate coal ash as a “special waste” subject to hazardous waste standards when disposed in landfills or surface impoundments, which would be subject to stringent design, permitting, closure and corrective action requirements. Alternatively, coal ash would be regulated as non-hazardous waste under RCRA subtitle D, with national minimum criteria for disposal but no federal permitting or enforcement. Under both options, the EPA would establish dam safety requirements to address the structural integrity of surface impoundments to prevent catastrophic releases. The EPA did not address in the proposed regulations the use of coal combustion wastes as minefill, but indicated that it would separately work with the Office of Surface Mining in order to develop effective federal regulations ensuring that such placement is adequately controlled. If coal ash from coal-fired power plants is re-classified as hazardous waste, regulations may impose restrictions on ash disposal, provide specifications for storage facilities, require groundwater testing and impose restrictions on storage locations, which could increase our customers’ operating costs and potentially reduce their ability to purchase coal. If coal ash is regulated under RCRA subtitle D, it could also adversely affect our customers and potentially reduce the desirability of coal for them. In addition, contamination caused by the past disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under RCRA or other federal or state laws and potentially reduce the demand for coal. The EPA had been expected to issue a final decision by the end of 2011, but did not. It was sued in federal court in April 2012 by environmental and health advocacy groups to compel agency action, and the federal court has ordered the EPA to take final action on the EPA’s proposed revision of the Resource Conservation and Recovery Act (RCRA) subtitle D regulations pertaining to coal combustion residuals (CCRs) by December 19, 2014.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)
CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners, lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of CERCLA or similar state laws. Thus, we may be subject to liability under CERCLA and similar state laws for coal mines that we currently own, lease or operate, and sites to which we have sent waste materials. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our mine sites. We may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination and natural resource damages at sites where we own surface rights.
Endangered Species Act
The federal Endangered Species Act (ESA) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (USFWS), works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. A number of species indigenous to the areas in which we operate are protected under the ESA, and compliance with ESA requirements could have the effect of prohibiting or delaying us from obtaining mining permits. These requirements may also include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. Should more stringent protective measures be applied, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures.
Use of Explosives
Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to regulatory requirements. We presently do not directly engage in blasting activities; instead, all of our blasting activities are conducted by independent contractors that use certified blasters.
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: Senior Vice President, Finance and Administration and Chief Financial Officer. The information on our website is not part of this Annual Report on Form 10-K.
Item 1A.
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;
•
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 Notes, may be materially adversely affected if we cannot make such capital expenditures.
Our coal mining operations are subject to operating risks that are beyond our control, which could result in materially increased operating expenses and decreased production levels and could materially and adversely affect our profitability.
We mine coal both at underground and at surface mining operations. Certain factors beyond our control, including those listed below, could disrupt our coal mining operations, adversely affect production and shipments and increase our operating costs:
•
poor mining conditions resulting from geological, hydrologic or other conditions that may cause instability of mining portals, highwalls or spoil piles or cause damage to mining equipment, nearby infrastructure or mine personnel;
•
delays or challenges to and difficulties in obtaining or renewing permits necessary to produce coal or operate mining or related processing and loading facilities;
•
adverse weather and natural disasters, such as heavy rains or snow, flooding and other natural events affecting operations, transportation or customers;
•
a major incident at the mine site that causes all or part of the operations of the mine to cease for some period of time;
•
mining, processing and plant equipment failures and unexpected maintenance problems;
•
unexpected or accidental surface subsidence from underground mining;
•
accidental mine water discharges, fires, explosions or similar mining accidents; and
•
competition and/or conflicts with other natural resource extraction activities and production within our operating areas, such as coalbed methane extraction or oil and gas development.
If any of these conditions or events occurs, we could experience a delay or halt of production or shipments or our operating costs could increase significantly.
Competition within the coal industry could put downward pressure on coal prices and, as a result, materially and adversely affect our revenues and profitability.
We compete with numerous other coal producers in the Illinois Basin and in other coal producing regions of the United States, primarily Central Appalachia and the Powder River Basin. The most important factors on which we compete are:
•
delivered price (i.e., the cost of coal delivered to the customer on a cents per million Btu basis, including transportation costs, which are generally paid by our customers either directly or indirectly);
•
coal quality characteristics (primarily heat, sulfur, ash and moisture content); and
•
reliability of supply.
Our competitors may have, among other things, greater liquidity, greater access to credit and other financial resources, newer or more efficient equipment, lower cost structures, partnerships with transportation companies or more effective risk management policies and procedures. Our failure to compete successfully could have a material adverse effect on our business, financial condition or results of operations.
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 decline, this decline could cause competition among coal
producers for the sale of coal in the United States to intensify, potentially resulting in significant downward pressure on domestic coal prices.
Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect coal prices and materially and adversely affect our results of operations.
Our coal is used primarily as fuel for electricity generation. Overall economic activity and the associated demand for power by industrial users can have significant effects on overall electricity demand. An economic slowdown can significantly slow the growth of electrical demand and could result in contraction of demand for coal. Declines in international prices for coal generally will impact U.S. prices for coal. During the past several years, international demand for coal has been driven, in significant part, by increases in demand due to economic growth in emerging markets, including China and India. Significant declines in the rates of economic growth in these regions could materially affect international demand for U.S. coal, which may have an adverse effect on U.S. coal prices.
Our business is closely linked to domestic demand for electricity and any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. In 2013, we sold a substantial majority of our coal to domestic electric power generators, and we have multi-year coal supply agreements in place with electric power generators for a significant portion of our future production. The amount of coal consumed by electric power generation is affected by, among other things:
•
general economic conditions, particularly those affecting industrial electric power demand, such as the downturn in the U.S. economy and financial markets in 2008 and 2009;
•
environmental and other governmental regulations, including those impacting coal-fired power plants;
•
energy conservation efforts and related governmental policies; and
•
indirect competition from alternative fuel sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power, and the location, availability, quality and price of those alternative fuel sources, and government subsidies for those alternative fuel sources.
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 2013, 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 EIA projects that electricity generation will grow at an annual average rate of 0.9% through 2040, it projects that the percentage of electricity generated from coal will decrease to 32% of total generation by 2040, compared with 39% during 2013.
In addition, state and federal mandates for increased use of electricity from renewable energy sources could have an adverse impact on the market for our coal. Many states have mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national energy portfolio standard in the U.S., although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by domestic electric power generators could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.
Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.
Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. The estimates of our reserves are based on engineering, economic and geological data assembled, analyzed and reviewed by internal and third-party engineers and consultants. We update our estimates of the quantity and quality of proven and probable coal reserves periodically to reflect the production of coal from the reserves, updated geological models and mining recovery data, the tonnage contained in new lease areas acquired and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:
•
quality of the coal;
•
geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;
•
the percentage of coal ultimately recoverable;
•
the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;
•
assumptions concerning the timing for the development of the reserves; and
•
assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs, including the cost of reclamation bonds.
As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary materially due to changes in the above factors and assumptions. Actual production recovered from identified reserve areas and properties, and revenues and expenditures associated with our mining operations, may vary materially from estimates. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.
Increases in the costs of mining and other industrial supplies, including steel-based supplies, diesel fuel, rubber tires and explosives, or the inability to obtain a sufficient quantity of those supplies, may adversely affect our operating costs or disrupt or delay our production.
Our coal mining operations use significant amounts of steel, electricity, diesel fuel, explosives, rubber tires and other mining and industrial supplies. The cost of roof bolts we use in our underground mining operations depends on the price of scrap steel. We also use significant amounts of diesel fuel and tires for the trucks and other heavy machinery we use. If the prices of mining and other industrial supplies, particularly steel-based supplies, diesel fuel and rubber tires, increase, our operating costs may be adversely affected. In addition, if we are unable to procure these supplies, our coal mining operations may be disrupted or we could experience a delay or halt in our production.
A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.
We conduct part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties or to royalties owed to those third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.
We outsource certain aspects of our business to third-party contractors, which subjects us to risks, including disruptions in our business.
We contract with third parties to provide blasting services at all of our mines and loading services at our barge loadout facility located on the Green River. In addition, we contract with third parties to provide truck transportation services between our mines and our preparation plants. Accordingly, we are subject to the risks associated with the contractors’ ability to successfully provide the necessary services to meet our needs. If the contractors are unable to adequately provide the contracted services, and we are unable to find alternative service providers in a timely manner, our ability to conduct our coal mining operations and deliver coal to our customers may be disrupted.
The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.
We depend upon barge, rail and truck transportation systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to supply coal to our customers. In addition, increases in transportation
costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. If transportation of our coal is disrupted or if transportation costs increase significantly and we are unable to find alternative transportation providers, our coal mining operations may be disrupted, we could experience a delay or halt of production or our profitability could decrease significantly.
Our profitability depends in part upon the multi-year coal supply agreements we have with our customers. Changes in purchasing patterns in the coal industry could make it difficult for us to extend our existing multi-year coal supply agreements or to enter into new agreements in the future.
We sell a majority of our coal under multi-year coal supply agreements. Under these arrangements, we fix the prices of coal shipped during the initial year and may adjust the prices in later years. As a result, at any given time the market prices for similar-quality coal may exceed the prices for coal shipped under these arrangements. Changes in the coal industry may cause some of our customers not to renew, extend or enter into new multi-year coal supply agreements with us or to enter into agreements to purchase fewer tons of coal than in the past or on different terms or prices. In addition, uncertainty caused by federal and state regulations, including the Clean Air Act, could deter our customers from entering into multi-year coal supply agreements.
Because we sell a majority of our coal production under multi-year coal supply agreements, our ability to capitalize on more favorable market prices may be limited. Conversely, at any given time we are subject to fluctuations in market prices for the quantities of coal that we are planning to produce but which we have not committed to sell. As described above under “Coal prices are subject to change and a substantial or extended decline in prices could materially and adversely affect our profitability and the value of our coal reserves,” the market prices for coal may be volatile and may depend upon factors beyond our control. Our profitability may be adversely affected if we are unable to sell uncommitted production at favorable prices or at all. For more information about our multi-year coal supply agreements, you should see the section entitled Item 1 - “Business - Sales and Marketing - Multi-Year Coal Supply Agreements.”
Our multi-year coal supply agreements subject us to renewal risks.
We sell most of the coal we produce under multi-year coal supply agreements. To the extent we are not successful in renewing, extending or renegotiating our multi-year coal supply agreements on favorable terms, we may have to accept lower prices for the coal we sell or sell reduced quantities of coal in order to secure new sales contracts for our coal.
Prices and quantities under our multi-year coal supply agreements are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or reopened. The expectation of future prices for coal depends upon factors beyond our control, including the following:
•
domestic and foreign supply and demand for coal;
•
domestic demand for electricity, which tends to follow changes in general economic activity;
•
domestic and foreign economic conditions;
•
the price, quantity and quality of other coal available to our customers;
•
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
•
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 - Sales and Marketing.”
The loss of, or significant reduction in purchases by, our largest customers could adversely affect our profitability.
For the year ended December 31, 2013, we derived approximately 76% 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, 2013, our total long-term debt was approximately $202.7 million, which is comprised of the following: $193.8 million in borrowings under the 11.75% Senior Secured Notes due 2019 (the Notes) and $8.9 million in other long-term debt. As of December 31, 2013, we had a long-term obligation owed to our
affiliate, Armstrong Resource Partners, associated with the financing transactions in connection with the transfers of undivided interests in certain land and mineral reserves to Armstrong Resource Partners totaling $106.3 million. We also have significant lease and royalty obligations, including, but not limited to, our capital lease obligations that totaled approximately $4.7 million as of December 31, 2013 and our obligations under non-cancelable operating leases that totaled approximately $38.6 million. Future minimum advance royalties totaled approximately $3.0 million as of December 31, 2013. In addition to advance royalties, production royalties are payable based on the quantity of coal mined in future years and prospective changes to mine plans. Our ability to satisfy our debt, lease and royalty obligations, and our ability to refinance our indebtedness, will depend upon our future operating performance. The amount of indebtedness we have incurred could have significant consequences to us, such as:
•
increasing our vulnerability to adverse economic, industry or competitive developments;
•
requiring a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;
•
making it more difficult for us to satisfy our obligations with respect to the Notes;
•
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, if there are borrowings under the Revolving Credit Facility and also subject to certain exceptions, restrict our ability and the ability of our subsidiaries to, among other things:
•
incur or assume liens or additional debt (including capital leases) or provide guarantees in respect of obligations of other persons;
•
pay dividends or distributions or redeem or repurchase capital stock;
•
make loans, capital expenditures and investments;
•
enter into agreements that restrict distributions from our subsidiaries;
•
sell, divest or transfer assets;
•
enter into certain transactions with affiliates; and
•
consolidate or merge with or into, or sell substantially all of our assets to, another person.
In addition, at any time when (i) undrawn availability is less than the greater of (a) $10.0 million or (b) an amount equal to 20% of the borrowing base or (ii) an event of default (as such term is defined in the Revolving Credit Facility) has occurred and is continuing, we will be required to maintain a fixed charge coverage ratio, calculated as of the end of each calendar month for the 12 months then ended, greater than 1.0-to-1.0. The Revolving Credit Facility also contains customary affirmative covenants and events of default. If an event of default occurs, the lenders under the Revolving Credit Facility will be entitled to take various actions, including the acceleration of amounts due under the Revolving Credit Facility and all actions permitted to be taken by a secured creditor. If our debt is accelerated, we may not be able to borrow sufficient funds to refinance our debt or be able to repay all of it. In 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.
Our assets and operations are concentrated in Western Kentucky and the Illinois Basin, and a disruption within that geographic region could adversely affect the Company’s performance.
We rely exclusively on sales generated from products distributed from the Illinois Basin and Western Kentucky. Due to our lack of diversification in geographic location, an adverse development in these areas, including adverse developments due to catastrophic events or weather and decreases in demand for coal or electricity, could have a significantly greater adverse impact on our ability to operate our business and our results of operations than if we held more diverse assets and locations.
The general partner of Armstrong Resource Partners may be removed or control of Armstrong Resource Partners, L.P. may be otherwise transferred to a third party without our consent.
Armstrong Resource Partners is majority-owned by Yorktown. Pursuant to the ARP LPA, Yorktown may remove our subsidiary, Elk Creek GP, as general partner of Armstrong Resource Partners or otherwise cause a change of control of Armstrong Resource Partners without our consent. If such a change in control of Armstrong Resource Partners were to occur, our ability to enter into, or obtain renewals of, coal lease or mining license agreements with Armstrong Resource Partners could be adversely affected. We may then have to seek alternative agreements or arrangements with unrelated parties and such alternative agreements or arrangements may not be available or may be on less favorable terms.
Some officers of Armstrong Energy may spend a substantial amount of time managing the business and affairs of Armstrong Resource Partners and its affiliates other than us.
These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Armstrong Resource Partners. Armstrong Energy intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs, notwithstanding that our business may be adversely affected if the officers spend less time on our business and affairs than would otherwise be available as a result of such officers’ time being split between the management of Armstrong Energy and of Armstrong Resource Partners. These officers may also be conflicted when negotiating the terms of contracts between Armstrong Energy and Armstrong Resource Partners.
The fiduciary duties of officers and directors of Elk Creek GP, as general partner of Armstrong Resource Partners, may conflict with those of officers and directors of Armstrong Energy.
As the general partner of Armstrong Resource Partners, our subsidiary Elk Creek GP has a legal duty to manage Armstrong Resource Partners in a manner beneficial to the limited partners of Armstrong Resource Partners This legal duty originates in Delaware statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because Elk Creek GP is owned by Armstrong Energy, the officers and directors of Elk Creek GP also have fiduciary duties to manage the business of Elk Creek GP and Armstrong Resource
Partners in a manner beneficial to Armstrong Energy. The board of directors of Elk Creek GP, which includes some of the directors and executive officers of Armstrong Energy, may resolve any conflict between the interests of Armstrong Energy on the one hand, and Armstrong Resource Partners, on the other hand, and has broad latitude to consider the interests of all parties to the conflict.
Conflicts of interest may arise between Armstrong Energy and Armstrong Resource Partners with respect to matters such as the allocation of opportunities to acquire coal reserves in the future, the terms and amount of any related royalty payments. In addition, we may determine to permit Armstrong Resource Partners to engage in other activities, including the acquisition of coal reserves that will not be used by Armstrong Energy, and we may decide to fund certain of these activities, subject to the limitations imposed by our debt agreements.
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 on 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.
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 impact the creditworthiness of our customers. If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for all of the coal we sell to that customer. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If we are able to withhold shipments, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all. Furthermore, the bankruptcy of any of our customers could have a material adverse effect on our financial position. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk of payment default.
Our consolidated balance sheets include interests in coal reserves for which legal title has been transferred to Armstrong Resource Partners.
As described in Note 13, “Related-Party Transactions,” to our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K, we have sold certain of our coal reserves to Armstrong Resource Partners. 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 Armstrong Resource Partners. As a result, the collateral agent’s ability to foreclose on and liquidate our assets comprising coal reserves that are the subject of these lease transactions will be limited to the portion of the
reserves owned by us. As of December 31, 2013, approximately 17% of the net book value of our “property, plant, equipment, and mine development, net” reflected assets for which legal title has been transferred to Armstrong Resource Partners.
Risks Related to Environmental and Other Regulations and Legislation
New regulatory requirements limiting greenhouse gas emissions could adversely affect coal-fired power generation and reduce the demand for coal as a fuel source, which could cause the price and quantity of the coal we sell to decline materially.
One major by-product of burning coal is carbon dioxide (CO2), which is a greenhouse gas and a source of concern with respect to global warming, also known as Climate Change. Future regulation of greenhouse gas emissions may require additional controls on, or the closure of, coal-fired power plants and industrial boilers and may restrict the construction of new coal-fired power plants.
On March 27, 2012, the EPA released its proposed rule that would establish, for the first time, new source performance standards under the federal Clean Air Act for CO2 emissions from new fossil fuel-fired electric utility generating power plants. New coal-fired power plants could meet the proposed standards either by employing carbon capture and storage technology at start up or through later application of such technologies provided that the aforementioned output standard was met on average over a 30-year period. If adopted, the proposed standards could negatively impact the price of coal. Moreover, there is currently no large-scale use of carbon capture and storage technologies in domestic coal-fired power plants, and as a result, there is a risk that such technology may not be commercially practical in limiting emissions as otherwise required by the proposed rule.
Future regulation, litigation and permitting related to greenhouse gas emissions may cause some users of coal to switch from coal to a lower-carbon fuel, or otherwise reduce the use of and demand for fossil fuels, particularly coal, which could have a material adverse effect on our business, financial condition or results of operations. See Item 1 - “Business - Regulation and Laws - Climate Change.”
Extensive environmental requirements, including existing and potential future requirements relating to air emissions, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.
The operations of our customers may be subject to extensive environmental requirements concerning air emissions. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide (SO2), particulate matter, nitrogen oxides (NOx), and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, SO2, NOx, toxic gases and other air pollutants have been proposed or could become effective in coming years. In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.
Stringent air emissions limitations are either in place or may be imposed in the short to medium term, and these limitations will likely require significant emissions control expenditures for many coal-fired power plants. As a result, these power plants may switch to other fuels that generate fewer of these emissions and the construction of new coal-fired power plants may become less desirable. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal.
In addition, contamination caused by the disposal of coal combustion byproducts, including coal ash, can lead to material liability to our customers under federal and state laws. In addition, the EPA has proposed a rule concerning management of coal combustion residuals. New EPA regulation of such management would likely
increase the ultimate costs to our customers of coal combustion. Such liabilities and increased costs in turn could have a material adverse effect on the demand for and prices received for our coal.
See Item 1 - “Business - Regulation and Laws” for more information about the various governmental regulations affecting us.
Legal requirements that we expect to significantly expand scrubbed coal-fired electricity generating capacity may be overturned or not enacted at all, which could result in less demand for Illinois Basin coal than we anticipate and materially and adversely affect our coal prices and/or sales.
Although a number of legal requirements have been or are in the process of being implemented that are expected to expand significantly the scrubbed coal-fired electricity generating capacity in the U.S., regulations driving this trend are subject to legal challenge, and could also be the subject of future legislation that withdraws any authorization for such requirements. For example, on August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) vacated the Cross-State Air Pollution Rule (CSAPR), which would have required states to reduce power plant emissions that contribute to ozone and/or fine particle pollution in other states, and ordered the EPA to continue administering the Clean Air Interstate Rule (CAIR) pending the promulgation of a replacement rate. On October 5, 2012, the EPA filed a petition seeking enhanced rehearing of the August 21, 2012, decision regarding CSAPR. On January 24, 2013, the D.C. Circuit denied the EPA’s petition for rehearing, and on March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit’s decision on the CSAPR. The CAIR remains in place pending such ruling. The outcome of such legal proceedings, or the enactment by Congress of more lenient air pollution laws than are currently in effect, could result in significantly less expansion of scrubbed coal-fired electricity generating capacity than we anticipate. This in turn could mean that the strong increase in demand for relatively high-sulfur Illinois Basin coal we believe will occur in the future may not materialize, or may not materialize as soon as it otherwise would. This could adversely affect the demand for our coal and the price we will receive, which could materially and adversely affect our coal prices and/or sales.
Our failure to obtain and renew permits and approvals necessary for our mining operations could negatively affect our business.
Coal production is dependent on our ability to obtain and maintain various federal and state permits and approvals to mine our coal reserves within the timeline specified in our mining plans. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, which may increase the costs or possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. The slowing pace at which necessary permits are issued or renewed for new and existing mines has materially impacted coal production, especially in Central Appalachia. Permitting by the Army Corps of Engineers (the Corps), the EPA and the Department of the Interior has become subject to “enhanced review” under both the SMCRA and the CWA.
Typically, we submit the necessary permit applications 12 to 30 months before we plan to mine a new area. Some of our required mining permits are becoming increasingly difficult to obtain within the time frames to which we were previously accustomed, and in some instances we have had to delay the mining of coal in certain areas covered by the application in order to obtain required permits and approvals. Permits could be delayed in the future if the EPA continues its enhanced review of CWA applications. If the required permits are not issued or renewed in a timely fashion or at all, or if permits issued or renewed are conditioned in a manner that restricts our ability to efficiently and economically conduct our mining activities, we could suffer a material reduction in our production and our operations, and there could be a material adverse effect on our ability to produce coal profitably. See “Item 1 - Business - Regulation and Laws.”
Section 404(q) of the CWA establishes a requirement that the Secretary of the Army and the Administrator of the EPA enter into an agreement assuring that delays in the issuance of permits under Section 404 are minimized. In August 1992, the Department of the Army and the EPA entered into such an agreement. The 1992 Section 404(q) Memorandum of Agreement (MOA) outlines the current process and time frames for resolving disputes in an effort to issue timely permit decisions. Under this MOA, the EPA may request that certain permit applications receive a higher level of review within the Department of Army. In these cases, the EPA determines that issuance of the permit will result in unacceptable adverse effects to Aquatic Resources of National Importance (ARNI). Alternately, the EPA may raise concerns over Section 404 program policies and procedures. An ARNI is a resource-based threshold used to determine whether a dispute between the EPA and the Corps regarding individual permit cases are eligible for elevation under the MOA. Factors used in identifying ARNIs include the economic importance of the aquatic resource, rarity or uniqueness, and/or importance of the aquatic resource to the protection, maintenance, or enhancement of the quality of the waters.
Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially and adversely affect our ability to meet our customers’ demands.
Federal or state regulatory agencies have the authority under certain circumstances following significant health and safety incidents, such as fatalities, to order a mine to be temporarily or permanently closed. If this were to occur, capital expenditures could be required in order for us to be allowed could be required in order for us to be allowed to reopen the mine. In the event that these agencies order the closing of our mines, our coal sales contracts generally allow us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, to fulfill these obligations, incur capital expenditures to reopen the mines and/or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or terminate customers’ contracts. Any of these actions could have a material adverse effect on our business and results of operations.
Extensive environmental laws and regulations impose significant costs on our mining operations, and future laws and regulations could materially increase those costs or limit our ability to produce and sell coal.
The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to environmental matters such as:
•
limitations on land use;
•
mine permitting and licensing requirements;
•
reclamation and restoration of mining properties after mining is completed;
•
management of materials generated by mining operations;
•
the storage, treatment and disposal of wastes;
•
remediation of contaminated soil and groundwater;
•
air quality standards;
•
water pollution;
•
protection of human health, plant-life and wildlife, including endangered or threatened species;
•
protection of wetlands;
•
the discharge of materials into the environment;
•
the effects of mining on surface water and groundwater quality and availability; and
•
the management of electrical equipment containing polychlorinated biphenyls.
The costs, liabilities and requirements associated with the laws and regulations related to these and other environmental matters may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. We cannot assure you that we have been or will be at all times in compliance with the applicable laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may incur material costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for sanctions, costs and liabilities in respect of these matters, we could be materially and adversely affected.
New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us to change operations significantly or incur increased costs. Such changes could have a material adverse effect on our financial condition and results of operations. See 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 considered the estimated current costs of reclamation and mine closure and applied inflation rates and a third-party profit, as required. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. The resulting estimated reclamation and mine closure obligations could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time, which may affect runoff or drainage water or other aspects of the environment. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and cleanup of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.
We maintain extensive coal refuse areas and slurry impoundments at a number of our mines. Such areas and impoundments are subject to extensive regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches,
as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which could pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for civil or criminal fines and penalties.
Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
Changes in the legal and regulatory environment could complicate or limit our business activities, increase our operating costs or result in litigation.
The conduct of our businesses is subject to various laws and regulations administered by federal, state and local governmental agencies in the United States. These laws and regulations may change, sometimes dramatically, as a result of political, economic or social events or in response to significant events. Certain recent developments particularly may cause changes in the legal and regulatory environment in which we operate and may impact our results or increase our costs or liabilities. Such legal and regulatory environment changes may include changes in:
•
the processes for obtaining or renewing permits;
•
costs associated with providing healthcare benefits to employees;
•
health and safety standards;
•
accounting standards;
•
taxation requirements; and
•
competition laws.
In 2006, the Federal Mine Improvement and New Emergency Response Act of 2006 (the MINER Act), was enacted. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977 (the Mine Act), imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities.
Following the passage of the MINER Act, MSHA issued new or more stringent rules and policies on a variety of topics, including:
•
sealing off abandoned areas of underground coal mines;
•
mine safety equipment, training and emergency reporting requirements;
•
substantially increased civil penalties for regulatory violations;
•
training and availability of mine rescue teams;
•
underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
•
flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and
•
post-accident two-way communications and electronic tracking systems.
Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania, Ohio and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Other states may pass similar legislation in the future. Also, additional federal and state legislation that further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has been considered in light of recent fatal mine accidents. Future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.
In response to the April 2010 explosion at Massey Energy Company’s Upper Big Branch Mine and the ensuing tragedy, we expect that safety matters pertaining to underground coal mining operations may be the topic of additional new federal and/or state legislation and regulation, as well as the subject of heightened enforcement efforts. For example, federal authorities have announced special inspections of coal mines to evaluate several safety concerns, including the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, federal authorities have announced that they are considering changes to mine safety rules and regulations which could potentially result in additional or enhanced required safety equipment, more frequent mine inspections, stricter and more thorough enforcement practices and enhanced reporting requirements. Any new environmental, health and safety requirements may be replicated in the states in which we operate and could increase our operating costs or otherwise may prevent, delay or reduce our planned production, any of which could adversely affect our financial condition, results of operations and cash flows.
Although we are unable to quantify the full impact, implementing and complying with new laws and regulations could have an adverse impact on our business and results of operations and could result in harsher sanctions in the event of any violations. See Item 1 - “Business - Regulation and Laws.”
The current challenging economic environment, along with difficult and volatile conditions in the capital and credit markets, could materially adversely affect our financial position, results of operations or cash flows, and we are unsure whether these conditions will improve in the near future.
The United States economy and global credit markets remain volatile. Worsening economic conditions or factors that negatively affect the economic health of the United States and Europe could reduce our revenues and thus adversely affect our results of operations. The recent financial and sovereign debt crises in North America and Europe have led to a global economic slowdown, with the economics of those regions showing significant signs of weakness resulting in greater volatility in the United States economy and in the global capital and credit markets. These markets have been experiencing disruption, including, among other things, volatility in security prices, diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, failure and potential failures of major financial institutions, unprecedented government support of financial institutions and high unemployment rates. Instability in consumer confidence and increased unemployment have increased concerns of prolonged economic weakness, Furthermore, these developments may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. We are unable to predict the duration and severity of the current crisis or determine the specific impact of the current economic conditions on our business at this time, but we believe that further deterioration or a prolonged period of economic weakness will have an adverse impact on our results of operations, business and financial condition, as well as our ability to satisfy our obligations under the Notes.
Item 1b.
Item 1b. Unresolved Staff Comments
None.
Item 2.
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 Transactions, and Director Independence” for specific information about our leases with related parties.
Coal Reserves
As of December 31, 2013, we controlled approximately 347 million tons of proven and probable coal reserves. In the first quarter of 2014, we executed two leases for an additional 224 million tons of proven and probable coal reserves, increasing our total controlled proven and probable coal reserves to approximately 571 million tons.
Our coal reserve estimates were prepared by Weir International, Inc., a mining and geological consultant. 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.
The following tables provide a summary of information regarding our coal reserves as of December 31, 2013, unless otherwise noted.
(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, 53.4% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2013.
(5) Warden and Kronos pits. Production at the Kronos pit ceased in August 2011 and the Warden pit was temporarily idled in March 2012.
(6) Based on internal estimates, recoverable reserves are split among the three mines that will produce coal from the underground properties and coal reserves located in Ohio County, Kentucky that are owned by Armstrong Resource Partners and leased to Armstrong Energy (the Elk Creek Reserves).
(7) Of these reserves, excluding an estimated 11.9 million tons of Elk Creek Reserves, 53.4% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2013.
(8) Reserves are controlled through a lease executed in February 2014.
(9) Amount includes 25.6 million tons of proven and probable coal reserves that were leased from a third-party in March 2014. Of these reserves, excluding an estimated 11.9 million tons of Elk Creek Reserves and the 25.6 million tons of newly leased reserves, 53.4% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2013.
(10) Includes production from our Big Run mine, which ceased production in October 2011.
(1) For surface mines, clean recoverable tons are based on a 90% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For underground mines other than Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.55 specific gravity and a 95% preparation plant efficiency. For Union/Webster Counties, clean recoverable tons are based on a 50% mining recovery, preparation plant yield at 1.60 specific gravity and a 95% preparation plant efficiency. “Proven and probable reserves” refers to coal that can be economically extracted or produced at the time of the reserve determination.
(2) Of these reserves, 53.4% of the interests controlled by Armstrong Energy are leased from Armstrong Resource Partners as of December 31, 2013.
(3) Warden and Kronos pits. Production at the Kronos pit ceased in August 2011 and the Warden pit was temporarily idled in March 2012.
(4) Based on internal estimates, recoverable reserves are split among the three mines that will produce coal from the underground properties and coal reserves located in Ohio County, Kentucky that are owned by Armstrong Resource Partners and leased to Armstrong Energy (the Elk Creek Reserves).
(5) Of these reserves, excluding an estimated 11.9 million tons of Elk Creek Reserves, 53.4% of the interests controlled by Armstrong Energy were leased from Armstrong Resource Partners as of December 31, 2013.
Item 3.
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.
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 (Dodd-Frank Act) and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report on Form 10-K.
PART II
Item 5.
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, 2014, there were approximately 17 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.
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 and Armstrong Energy, Inc.’s predecessor, Armstrong Land Company, LLC and its subsidiaries (our Predecessor). The selected historical financial data for the years ended December 31, 2013, 2012, 2011, 2010, and 2009 and the balance sheet data as of December 31, 2013, 2012, 2011, 2010, and 2009 are derived from the audited consolidated financial statements of Armstrong Energy, Inc. and our Predecessor.
As of October 1, 2011, we no longer consolidate the results of operations of Armstrong Resource Partners in our consolidated financial statements and we account for our ownership in Armstrong Resource Partners under the equity method of accounting. As a result, our financial results for the years ended December 31, 2009 and 2010 are not directly comparable to our financial results for the years ended December 31, 2011, 2012 and 2013. For more information, please see Note 3, “Deconsolidation of Armstrong Resource Partners,” to our audited consolidated financial statements included herein.
Historical results are not necessarily indicative of results we expect in future periods. The following selected financial data should be read in conjunction with Item 7
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 a risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described under “Cautionary Statement Concerning Forward-Looking Statements” and Item 1A - “Risk Factors.” We assume no obligation to update any of these forward-looking statements.
Overview
We are a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin, with both surface and underground mines. We market our coal primarily to proximate and investment grade electric utility companies as fuel for their steam-powered generators. Based on 2013 production, we are the fifth largest producer in the Illinois Basin and the second largest in Western Kentucky. We were formed in 2006 to acquire and develop a large coal reserve holding. We commenced production in the second quarter of 2008 and currently operate seven mines, including four surface and three underground. We control approximately 571 million tons of proven and probable coal reserves. Our reserves and operations are located in the Western Kentucky counties of Ohio, Muhlenberg, Union and Webster. We also own and operate three coal processing plants, which support our mining operations. From our reserves, we mine coal from multiple seams that, in combination with our coal processing facilities, enhance our ability to meet customer requirements for blends of coal with different characteristics. The locations of our coal reserves and operations, adjacent to the Green River, together with our river dock coal handling and rail loadout facilities, allow us to optimize our coal blending and handling, and provide our customers with rail, barge and truck transportation options.
We market our coal primarily to large utilities with coal-fired, base-load, scrubbed power plants under multi-year coal supply agreements. Our multi-year coal supply agreements usually have specific and possibly different volume and pricing arrangements for each year of the agreement. These agreements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. At December 31, 2013, we had multi-year coal supply agreements with terms ranging from one to six years and are contractually committed to sell 9.6 million tons of coal in 2014 and 7.8 million tons of coal in 2015.
During 2013 and 2012, we produced 9.3 million and 8.7 million tons of coal, respectively, and during the same periods, we sold 9.3 million and 8.5 million tons of coal, respectively. For the year ended December 31, 2013, our revenue from coal sales was $415.3 million, and we generated operating income of $9.9 million, net loss of $25.1 million, and Adjusted EBITDA of $58.2 million. Our revenue, operating income, net loss and Adjusted EBITDA for the year ended December 31, 2012 were $382.1 million, $6.6 million, $18.0 million, and $50.9 million, respectively. Our continued growth is being perpetuated through the expansion of our operations by opening new mines, which in 2013 and 2012 included the completion of the Lewis Creek underground and Kronos mines, 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 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 our coal blending and handling and provide our customers with rail, barge and truck transportation options.
Evaluating the Results of Our Operations
We evaluate the results of our operations based on several key measures:
•
our coal production, sales volume and weighted average sales prices;
•
our cost of coal sales; and
•
our Adjusted EBITDA, a non-GAAP financial measure.
We define our coal sales price per ton, or average sales price, as total coal sales divided by tons sold. We review coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis. We define Adjusted EBITDA as net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, non-cash production royalty to related party, loss on settlement of interest rate swap, loss on deferment of equity offering, gain on settlement of asset retirement obligations, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis, the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness, our operating performance and return on investment compared to those of other companies in the coal energy sector, without regard to financing or capital structures, and the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. Adjusted EBITDA has several limitations that are discussed under 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).
Coal Production, Sales Volume and Sales Prices
We evaluate our operations based on the volume of coal we produce, the volume of coal we sell and the prices we receive for our coal. Because we sell substantially all of our coal under multi-year coal supply agreements, our coal production, sales volume and sales prices are largely dependent upon the terms of those contracts. The volume of coal we sell is also a function of the productive capacity of our mines and changes in our inventory levels and those of our customers.
Our multi-year coal supply agreements typically provide for a fixed price, or a schedule of fixed prices, over the contract term. In addition, the contracts typically contain price reopeners that provide for a market-based adjustment to the initial price after the initial years of those contracts have been fulfilled. These contracts would terminate if we cannot agree upon a market-based price with the customer. In addition, many of our multi-year coal supply agreements have full or partial cost pass through or inflation adjustment provisions; specifically, costs related to fuel, explosives and new government impositions are subject to certain pass-through provisions under many of our multi-year coal supply agreements. Cost pass-through provisions typically provide for increases in our sales prices in rising operating cost environments and for decreases in declining operating cost environments. Inflation adjustment provisions typically provide some protection in rising operating cost environments. We also receive premiums, or pay penalties, based upon the actual quality of the coal we deliver, which is measured for characteristics such as heat (Btu), sulfur and moisture content.
We evaluate the price we receive for our coal on an average sales price per ton basis. The following table provides operational data with respect to our coal production, coal sales volume and average sales prices per ton for the periods indicated:
Cost of Coal Sales
We evaluate our cost of coal sales on a cost per ton basis. Our cost of coal sales per ton represents our production costs divided by the tons of coal we sell. Our production costs include labor and associated benefits, fuel, lubricants, explosives, operating lease expenses, repairs and maintenance, royalties, and all other costs that are directly related to our mining operations, other than the cost of depreciation, depletion and amortization (DD&A) expenses. Our production costs also exclude any indirect or selling related costs, such as general and administrative (G&A) expenses and selling and other related 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:
Adjusted EBITDA
Although Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, our management believes that it is useful in evaluating our financial performance. Adjusted EBITDA has several limitations that are discussed under “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 Impact Our Business
For the past three years, over 90% of our coal sales were made under multi-year coal supply agreements. We intend to continue to enter into multi-year coal supply agreements for a substantial portion of our annual coal production, using our remaining production to take advantage of market opportunities as they present themselves. We believe our use of multi-year coal supply agreements reduces our exposure to fluctuations in the spot price for coal and provides us with a reliable and stable revenue base. Using multi-year coal supply agreements also allows us to partially mitigate our exposure to rising costs, to the extent those contracts have full or partial cost pass through provisions or inflation adjustment provisions. For example, 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.
As of March 1, 2014, we have approximately 9.6 million tons and 7.8 million tons of coal committed for 2014 and 2015, respectively. The average price per committed ton for 2014 is $46.79 and the average price per committed ton for 2015 is $47.76.
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. Total coal consumption in the United States in 2013 increased by approximately 35 million tons, or 4%, from 2012 levels. The increase in U.S. domestic coal consumption during 2013 was primarily a function of increased consumption in the electric power sector due to higher natural gas prices. However, according to the EIA, coal is expected to remain the dominant energy source for electric power generation for the foreseeable future.
Results of Operations
Factors Affecting the Comparability of Our Results of Operations
The comparability of our operating results for the years ending December 31, 2013, 2012 and 2011 is impacted by the opening of additional mines or expansion of existing mines during each of the periods. We began production of coal mid-year 2008 at one underground mine and one surface mine. Our coal production has continued to increase substantially and totaled 9.3 million tons in 2013. The increase in production was primarily
the result of opening two mines in 2011, while expanding production at one mine in 2012 and opening a third mine in 2013. Partially offsetting the impact of opening these new mines is the closure of one mine in 2011 and the temporary idling of another in 2012. Due to these changes in the number of operating mines during the aforementioned periods, it is difficult to provide direct comparisons of reported results during each period.
As of October 1, 2011, we no longer consolidate the results of operations of Armstrong Resource Partners in our consolidated financial statements and account for our ownership in Armstrong Resource Partners under the equity method of accounting. As a result, our financial results for the year ended December 31, 2011 are not directly comparable to our financial results for the years ended December 31, 2012 and 2013. For more information, please see Note 3, “Deconsolidation of Armstrong Resource Partners” in our audited financial statements included elsewhere in this Annual Report on Form 10-K.
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.”
(1) Adjusted EBITDA is a non-GAAP financial measure which represents net income (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization, non-cash production royalty to related party, loss on settlement of interest rate swap, loss on deferment of equity offering, gain on settlement of asset retirement obligations, non-cash stock compensation expense, non-cash charges related to non-recourse notes, gain on deconsolidation, and (gain) loss on extinguishment of debt. For these purposes, “GAAP” refers to U.S. generally accepted accounting principles. Please see Item 6 - “Selected Financial Data” for a reconciliation of Adjusted EBITDA to net income (loss).
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Overview
We reported revenue of $415.3 million for the year ended December 31, 2013, compared to $382.1 million for the year ended December 31, 2012. Coal sales increased 8.7% to 9.3 million tons in 2013, compared to 8.5 million tons in the prior year. Our average sales price per ton in the year ended December 31, 2013 totaled $44.82 per ton, as compared to $44.84 for the prior year. Our net loss and Adjusted EBITDA for 2013 totaled $25.1 million and $58.2 million, respectively, as compared to net loss and Adjusted EBITDA for 2012 of $18.0 million and $50.9 million, respectively.
Coal Production and Sales Volume
Our tons of coal produced increased to 9.3 million tons in the year ended December 31, 2013 from 8.7 million tons in the prior year. This increase is primarily attributable to increased production at the Kronos mine, which completed development early in 2012, and at the Lewis Creek underground mine, which completed development in mid-2013, partially offset by a decline in production at the Midway surface mine in the current year due to poor geological conditions. For the year ended December 31, 2013 and 2012, we sold 9.3 million tons and 8.5 million tons, respectively.
Average Sales Price Per Ton
Our average sales price per ton decreased to $44.82 for the year ended December 31, 2013 from $44.84 for 2012. This slight per ton decrease is due to unfavorable customer mix and new contracts entered into in 2013 being at a lower average per ton price due to a year-over-year decline in market pricing, partially offset by annual price increases on our multi-year coal supply agreements. In addition, we entered into a settlement agreement with one of our customers regarding a governmental imposition claim in August 2013, which positively impacted revenue by approximately $3.5 million in the current year, of which $2.5 million was associated with prior shipments.
Revenue
Our coal sales revenue for the year ended December 31, 2013 increased by $33.2 million, or 8.7%, to $415.3 million, as compared to 2012. This increase is primarily attributable to a favorable volume variance of approximately $33.4 million due to the sale of 0.7 million additional tons in the current year from increased production at our Kronos mine in 2013, as compared to 2012, and the completion of the Lewis Creek underground mine in the current year, partially offset by a decline in production at the Midway mine due to poor geological conditions in the current year. In addition, the settlement of a governmental imposition claim positively impacted revenue for 2013 by approximately $3.5 million. Negatively impacting revenue for the year ended December 31, 2013, as compared to the prior year, was an unfavorable price variance of $0.2 million, as discussed above.
Cost of Coal Sales
Cost of coal sales increased 7.2% to $303.0 million in the year ended December 31, 2013, from $282.6 million in 2012. This increase was primarily attributable to the sale of 0.7 million additional tons in the current year, as compared to 2012. On a per ton basis, our cost of coal sales decreased during the year ended December 31, 2013, compared to 2012, from $33.16 per ton to $32.70 per ton. This decrease is due to efficiencies gained in the current year at the Kronos mine due to the lack of restrictions on the depth of advancement that can be made at the mine and favorable mining conditions at our Equality Boot mine in 2013, partially offset by less favorable mining conditions at our Midway and Lewis Creek underground mines in 2013.
Production Royalties to Related Party
Production royalties to related party increased $2.1 million, or 37.2%, to $7.8 million for the year ended December 31, 2013, as compared to $5.7 million in 2012. The increase in production royalties earned by Armstrong Resource Partners is due to the increased production levels at the Kronos mine during the current year as a result of operating at full production capacity in 2013.
Depreciation, Depletion and Amortization
DD&A expenses increased by $5.2 million, or 15.6%, during the year ended December 31, 2013 to $38.2 million, as compared to $33.1 million in 2012. The increase is primarily due to an increase in depreciation of machinery and equipment as we continued to expand our operations in 2012 and 2013 with the completion of the development of the Kronos and Lewis Creek underground mines. In addition, depletion and amortization expenses were slightly higher as a result of the higher production in 2013.
Asset Retirement Obligation Expense
Asset retirement obligation expense decreased by $1.5 million, or 37.8%, to $2.5 million in the year ended December 31, 2013, as compared to 2012. 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 $21.2 million for the year ended December 31, 2013, which was $0.3 million, or 1.2%, higher than the year ended December 31, 2012. The increase is primarily due to higher expense for compensation and related benefits ($1.2 million) and legal and other professional fees ($0.8 million) in the current year, partially offset by lower information technology related expenses ($0.2 million) and non-income related taxes ($1.5 million).
Selling and Other Related Expenses
Selling and other related expenses were $32.7 million for the year ended December 31, 2013, which was $4.0 million, or 14.0%, higher than the year ended December 31, 2012. The increase is related directly to the 8.7% increase in total sales in the current year, as compared to 2012. In addition, we experienced higher royalty expenses in the current year based on the areas being mined, as compared to the prior year.
Interest Expense, Net
Interest expense, net is derived from the following components:
Interest expense, net increased $16.4 million to $35.6 million for the year ended December 31, 2013, as compared to $19.2 million for the year ended December 31, 2012. The increase is principally attributable to a higher average interest rate in the current year due to the Notes, which were entered into in December 2012. We
also have higher average borrowings in the current year, as compared to 2012, due to the incremental increase in borrowings from completing the Notes offering and the repayment of the then outstanding senior secured credit facility (2011 Credit Facility). In addition, the closing of the reserve transfers to Armstrong Resource Partners in March 2012 and April 2013 increased the principal balance of the long-term obligation to related party by $25.7 million and $4.9 million, respectively.
Other Income (Expense), Net
Other income (expense), net totaled income of $0.6 million for the year ended December 31, 2013, as compared to expense of $1.5 million for the year ended December 31, 2012. The current year amount relates primarily to ancillary income from timber, scrap, and crop sales. Other income (expense), net for 2012 included a loss on settlement of interest rate swap of $1.4 million associated with terminating an interest rate swap in conjunction with the prepayment and termination of the 2011 Credit Facility and a loss on deferment of equity offering of $1.1 million. We had previously deferred costs incurred related to a proposed equity offering. In the fourth quarter of 2012, as the offering had been delayed for an extended period of time, a charge was recognized to write-off all deferred amounts associated with the proposed equity offering. Partially offsetting these charges in 2012 was revenue earned from timber, scrap, and crop sales.
Loss on Extinguishment of Debt
A loss on extinguishment of debt of $4.0 million was recognized in the year ended December 31, 2012. In December 2012, we completed the Notes offering and used the proceeds from which to prepay and terminate our then outstanding 2011 Credit Facility. As a result, a loss was recognized associated with the write-off of a portion of the unamortized deferred financing costs.
Net Loss
Net loss for the year ended December 31, 2013 was $25.1 million, as compared to $18.0 million for 2012. The increase is largely due to the increase in interest expense from higher average borrowings and an increase in the average interest rate in the current year, partially offset by the impact of higher operating income in the current year and the recognition of certain periodic charges in 2012 that did recur in 2013, including a loss on settlement of interest rate swap, loss on deferment of equity offering, and loss on extinguishment of debt.
Adjusted EBITDA
Our Adjusted EBITDA for the year ended December 31, 2013 was $58.2 million, or $6.28 per ton, as compared to $50.9 million, or $5.97 per ton, for the year ended December 31, 2012. The increase resulted primarily from higher gross margin as a result of selling 0.7 million tons more in the current year, as compared to 2012, partially offset by higher sales and other related expenses.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Overview
We reported revenue of $382.1 million for the year ended December 31, 2012, compared to $299.3 million for the year ended December 31, 2011. Coal sales increased 21.2% to 8.5 million tons in 2012, compared to 7.0 million tons in 2011. Our average sales price per ton for the year ended December 31, 2012 increased 5.3%, to $44.84 per ton, compared to 2011. Our net loss and Adjusted EBITDA for the year ended December 31, 2012 was $18.0 million and $50.9 million, respectively, as compared to net income and Adjusted EBITDA for 2011 of $3.5 million and $41.6 million, respectively.
Coal Production and Sales Volume
Our tons of coal produced increased 30.4% to 8.7 million tons in 2012 from 6.6 million tons in 2011. This increase is primarily attributable to (a) the commencement of production at the Lewis Creek mine and Kronos mine in June 2011 and September 2011, respectively, and (b) increased production at our Equality Boot mine in 2012, which resulted in an incremental increase in our sales by 2.9 million tons, year over year. This increase was partially offset by the closure of the Big Run mine in October 2011 and the temporary idling of the East Fork mine in March 2012.
Average Sales Price Per Ton
Our average sales price per ton increased 5.3% to $44.84 in 2012 from $42.57 in 2011. This $2.27 per ton increase resulted from the combination of (a) higher pricing due to annual increases on our multi-year coal supply agreements, (b) an increase in spot sales that did not occur in 2011, and (c) the addition of new customers in the current year whose pricing is commensurate with current market prices.
Revenue
Our coal sales revenue for the year ended December 31, 2012 increased by $82.8 million, or 27.7%, compared to the year ended December 31, 2011. This increase is primarily attributable to increased sales volume year over year, as we had a full year of production from our Lewis Creek and Kronos mines, which were opened during June 2011 and September 2011, respectively, and increased productivity at our Equality Boot mine in 2012. Partially offsetting the increase in volume is the closure of the Big Run mine in October 2011 and the temporary idling of the East Fork mine in March 2012. These factors contributed to a year-over-year increase in revenue of $63.5 million. In addition, revenue was positively impacted by increased pricing year over year, as discussed above, which resulted in a year-over-year increase in revenue of approximately $19.3 million.
Cost of Coal Sales
Cost of coal sales increased 27.5% to $282.6 million in the year ended December 31, 2012, from $221.6 million in the prior year. This increase was primarily attributable to a full year of production from the Lewis Creek and Kronos mines, which increased operating costs by $69.6 million during 2012, as compared to 2011. In addition, cost of coal sales declined in the current year due to the closure of the Big Run mine and temporary idling of the East Fork mine, which was offset by increased costs at the Equality Boot mine due to the implementation of the new ground control plan in the fourth quarter of 2011 and less favorable mining conditions at the Parkway and Midway mines during 2012. On a per ton basis, our cost of coal sales increased from the year ended December 31, 2011 to 2012 from $31.52 per ton to $33.16 per ton, due primarily to the expansion of our underground operations with the opening of the Kronos mine, which are higher cost operations as compared to our surface mines and higher costs at our Equality Boot mine resulting from changes in the ground control plan implemented in the fourth quarter of 2011. In addition, we experienced operating inefficiencies at our Kronos mine in the first half of the year from restrictions on the depth of advancement that can be made.
Production Royalties to Related Party
Production royalties to related party increased $5.1 million to $5.7 million in 2012, as compared to $0.6 million in 2011. The increase in production royalties earned by Armstrong Resource Partners is due to a full year of production from the Kronos underground mine in 2012.
Depreciation, Depletion and Amortization Expenses
DD&A expenses increased by $5.4 million, or 19.5%, during 2012, as compared to 2011. The primary reason for the increase was a $5.2 million increase in depreciation associated with the opening of the Lewis
Creek and Kronos mines in the latter half of 2011. Depletion and amortization expenses were also higher as a result of the higher production in 2012, partially offset by a reduction in depreciation and amortization expenses from the closure of the Big Run mine in September 2011 and temporary idling of the East Fork mine in March 2012.
Asset Retirement Obligation Expense
Asset retirement obligation expense for the year ended December 31, 2012 is comparable to the amount incurred in 2011. Increased expense in 2012 from the opening of the Lewis Creek and the Kronos mines in 2011 was offset by the impact of the closure of the Big Run mine in 2011 and Maddox mine in 2012.
General and Administrative Expenses
G&A expenses were $21.4 million for the year ended December 31, 2012, which was $7.7 million, or 56.2%, higher than the year ended December 31, 2011. The increase is primarily due to increased compensation and benefits ($1.8 million), legal and other professional fees ($1.3 million), insurance costs ($0.8 million), and non-income related taxes ($1.3 million) related to the continued expansion of our operations with the development of the Lewis Creek and Kronos mines in 2011.
Selling and Other Related Expenses
Selling and other related expenses increased $5.0 million, or 20.8%, to $28.7 million for the year ended December 31, 2012, as compared to $23.8 million for the year ended December 31, 2011. The increase is related directly to the 21.2% increase in total tons sold in 2012, as compared to 2011.
Interest Expense, Net
Interest expense, net is derived from the following components:
Interest expense, net was $19.2 million for the year ended December 31, 2012, as compared to $10.7 million for the year ended December 31, 2011. The increase was principally attributable to interest expense incurred in 2012 associated with the long-term obligation to related party totaling $9.3 million that was recognized as a result of the deconsolidation of Armstrong Resource Partners on October 1, 2011. Interest expense recognized in 2011 related to the long-term obligation to related party totaled $2.5 million.
Other Income (Expense), Net
Other income (expense), net totaled expense of $1.5 million for the year ended December 31, 2012, as compared to expense of $0.2 million for the year ended December 31, 2011. Other income (expense), net for 2012 included a loss on settlement of interest rate swap of $1.4 million associated with terminating an interest rate swap in conjunction with the prepayment and termination of the 2011 Credit Facility and a loss on deferment of equity offering of $1.1 million. We had previously deferred costs incurred related to a proposed equity
offering. In the fourth quarter of 2012, as the offering had been delayed for an extended period of time, a charge was recognized to write-off all deferred amounts associated with the proposed equity offering. Partially offsetting these charges in 2012 was revenue earned from timber, scrap, and crop sales. Expense incurred in the year ended December 31, 2011 consisted of multiple items which were individually immaterial.
(Loss) Gain on Extinguishment of Debt
In February 2011, we entered into the 2011 Credit Facility and repaid our then outstanding promissory notes with the proceeds. As a result of the aforementioned repayment, we recorded a gain on extinguishment of debt of $7.0 million in the year ended December 31, 2011. On December 21, 2012, we completed the Notes offering, the proceeds of which were used to prepay and terminate the 2011 Credit Facility. As a result, we recognized a loss on extinguishment of debt of $4.0 million associated with the write-off of a portion of the unamortized deferred financing costs.
Income Taxes
We recorded an income tax provision of zero and $0.9 million for the years ended December 31, 2012 and 2011, respectively. The 2011 provision related primarily to current alternative minimum tax and certain state income tax as a result of taxable income generated from certain of our subsidiaries in 2011.
Net Income (Loss)
Our net loss for the year ended December 31, 2012 was $18.0 million, as compared to net income of $3.5 million for the year ended December 31, 2011. The decline in net earnings is due to an increase in per ton operating costs resulting from the increase in underground production, higher DD&A expenses as a result of the continued expansion of our overall operations and increased production, and an increase in interest expense resulting from the recognition of a long-term obligation to related party as a result of the deconsolidation of Armstrong Resource Partners on October 1, 2011. Partially offsetting the overall earnings decline is an increase in revenue from both favorable price and volume variances.
Adjusted EBITDA
Our Adjusted EBITDA for the year ended December 31, 2012 was $50.9 million, or $5.97 per ton, as compared to $41.6 million, or $5.92 per ton, for the year ended December 31, 2011. The increase resulted primarily from an increase in revenue related to the higher average sales prices, as well as an increase in the tons sold due to the increase in the number of mines in operation. This increase was partially offset by higher operating costs at the Kronos and Parkway underground mines and Equality Boot and Midway surface mines in 2012.
Liquidity and Capital Resources
Liquidity
Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in mining our reserves, as well as complying with applicable environmental laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and to service our debt. Historically, our primary sources of liquidity to meet these needs have been cash generated by our operations, borrowings under our credit facilities and contributions from our equity holders.
On December 21, 2012, we completed a $200.0 million offering of 11.75% senior secured Notes due 2019 and received proceeds of $193.1 million, as the Notes were issued at an OID of 96.567%. Interest on the Notes is
due semiannually on June 15 and December 15 of each year, with the first payment made on June 15, 2013. In connection with the offering, we prepaid and terminated our then existing 2011 Credit Facility and recognized a loss on extinguishment of debt of $4.0 million associated with the write-off of a portion of the unamortized deferred financing costs incurred on the 2011 Credit Facility. In addition, we entered into the Revolving Credit Facility, which provides for revolving borrowings of up to $50.0 million.
We believe that existing cash balances, cash generated from operations and borrowings under our Revolving Credit Facility will be sufficient to meet working capital requirements, anticipated capital expenditures and debt service requirements. We manage our exposure to changing commodity prices for our long-term coal contract portfolio through the use of multi-year coal supply agreements. We generally enter into fixed price, fixed volume supply contracts with terms greater than one year with customers with whom we have historically had limited collection issues. Our ability to satisfy debt service obligations, to fund planned capital expenditures, and to make acquisitions, will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.
The principal indicators of our liquidity are our cash on hand and availability under our Revolving Credit Facility. As of December 31, 2013, our available liquidity was $70.9 million, comprised of cash on hand of $51.6 million and $19.3 million available under our Revolving Credit Facility.
Our long-term debt consisted of the following as of the dates indicated:
Senior Secured Notes due 2019
On December 21, 2012, we completed the $200.0 million Notes offering. The Notes were issued at an original issue 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, 2013 and 2012, the unamortized OID was $6.2 million and $6.8 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, we may redeem the Notes with the net cash proceeds received from one or more Equity Offerings (as defined in the indenture governing the Notes) at a redemption price equal to 111.75% of the principal amount redeemed plus
accrued and unpaid interest to the applicable redemption date, in an aggregate principal amount for all such redemptions not to exceed 35% of the original aggregate principal amount of the Notes.
Upon the occurrence of an event of a Change in Control (as defined in the indenture governing the Notes), unless we have exercised our right to redeem the Notes, we will be required to make an offer to purchase the Notes at a redemption price of 101.000%, plus accrued and unpaid interest to the date of repurchase.
Subject to certain customary release provisions, the Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by us and substantially all of our current and future domestic restricted subsidiaries (as defined). They are also secured, subject to certain exceptions and permitted liens, on a first-priority basis by substantially all of our and the guarantors’ assets that do not secure the Revolving Credit Facility (see below) on a first-priority basis. Subject to certain exceptions and permitted liens, the Notes will also be secured on a second-priority basis by a lien on the assets securing our obligations under the Revolving Credit Facility on a first-priority basis.
The indenture governing the Notes contains restrictive covenants which, among other things, limit the ability (subject to exceptions) of us and our restricted subsidiaries (as defined) to (a) incur additional indebtedness or issue preferred equity; (b) pay dividends or distributions on or purchase our stock or our restricted subsidiaries’ stock; (c) make certain investments; (d) use assets as security in other transactions; (e) create guarantees of indebtedness by restricted subsidiaries; (f) enter into agreements that restrict dividends, distributions, or other payment by restricted subsidiaries; (g) sell certain assets or merge with or into other companies; and (h) enter into transactions with affiliates.
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, 2013 and 2012, there were no borrowings outstanding under the Revolving Credit Facility and we had $19.3 million and $20.0 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 Revolving Credit Facility also contains customary affirmative covenants and events of default. If an event of default occurs, the lenders under the Revolving Credit Facility will be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.
Prepayments and Commitment Reductions
Voluntary prepayments and commitment reductions will be permitted, in whole or in part, in minimum amounts without premium or penalty, other than customary breakage costs with respect to LIBOR loans.
2011 Credit Facility
On February 9, 2011, we entered into the 2011 Credit Facility, which was comprised of a $100.0 million term loan and a $50.0 million revolving credit facility. The term loan was a five-year term loan that required principal payments in the amount of $5.0 million on the first day of each quarter commencing on January 1, 2012 through January 1, 2016, with the remaining outstanding principal and interest balance due upon maturity on February 9, 2016. On December 21, 2012, in connection with the offering of the Notes, we voluntarily prepaid and terminated the 2011 Credit Facility, and repaid all outstanding amounts under the agreement. As a result of the prepayment and termination of the 2011 Credit Facility, we recognized a loss on extinguishment of debt of $4.0 million in connection with the write-off of related unamortized deferred financing costs.
Cash Flows
The following table reflects cash flows for the applicable periods:
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Net cash provided by operating activities was $32.9 million for the year ended December 31, 2013, an increase of $2.2 million from net cash provided by operating activities of $30.8 million for 2012. We experienced an increase in operating income in 2013 due to higher gross margin from an increase in shipments and favorable operating costs, as compared to 2012, partially offset by higher selling and other related costs from higher
production taxes and royalties associated with the increased sales tonnage. The higher production levels and completion of the Kronos and Lewis Creek underground mines also increased depreciation, depletion, and amortization by $5.2 million in 2013, as compared to the prior year. 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 Armstrong Resource Partners. 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 $13.9 million to $32.6 million for the year ended December 31, 2013, compared to $46.5 million for 2012. The current year investment is largely attributable to capital expenditures on equipment and mine development for the completion of the Lewis Creek underground mine, whereas the 2012 investment relates primarily to capital expenditures for the completion of the Kronos mine and the initial development of the Lewis Creek underground mine.
Net cash used in financing activities was $8.9 million for the year ended December 31, 2013, compared to net cash provided by financing activities of $56.3 million for the year ended December 31, 2012. The current year activity relates primarily to scheduled capital lease and other long-term debt payments. The 2012 activity consists of the $200.0 million Notes offering, issuance of $30.0 million of Series A convertible preferred stock and borrowings of $18.5 million under the 2011 Credit Facility, offset by the payment of long-term debt obligations of $169.9 million, which includes scheduled debt maturities and the repayment and termination of the 2011 Credit Facility with proceeds from the Notes offering and the payment of financing fees totaling $11.1 million primarily related to the Notes offering and the establishment of the Revolving Credit Facility.
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net cash provided by operating activities was $30.8 million for the year ended December 31, 2012, a decrease of $17.4 million from net cash provided by operating activities of $48.2 million for 2011. We experienced a decline in operating income in the year ended December 31, 2012, as compared to 2011. While there was an increase in tons sold from operating more mines, as well as improved pricing in 2012, this was partially offset by higher average operating costs, G&A expenses, and selling and other related expenses. The operation of additional mines and higher production levels also increased DD&A by $5.4 million in 2012, as compared to 2011. Further, the continued expansion has impacted the cash flows from operating assets and liabilities in 2012, primarily by leading to an increase in accounts receivable and a decline in advanced royalties, which is included as a component of other non-current assets. In addition, we recognized a loss on extinguishment of debt in 2012 of $4.0 million associated with the prepayment and termination of the 2011 Credit Facility. Impacting cash flows from operations for the year ended December 31, 2011 was the inclusion of a non-cash gain on early extinguishment of debt, as well as our opening of the Equality Boot, Lewis Creek, and Kronos mines in September 2010, June 2011, and September 2011, respectively, that resulted in a net increase in cash from operating assets and liabilities resulting from increased accounts payable and payroll and other accrued incentives, partially offset by an increase in accounts receivable. In addition, positively impacting cash flows from operations was a decline in inventories of approximately $1.6 million in 2011 due to lower productivity levels at certain of our mines resulting from weather and other mining related issues earlier in the year.
Net cash used in investing activities was $46.5 million for the year ended December 31, 2012, compared to $75.8 million for 2011. The 2012 investment is primarily attributable to capital expenditures on equipment and mine development for the continued expansion of our Kronos mine and development of our Lewis Creek underground mine, whereas the 2011 investment relates to capital expenditures on the initial development of the Kronos mine and development of the Lewis Creek surface mine. In addition, we made an investment in 2011 of approximately $2.5 million in an affiliate for the planned construction of an export facility on the lower Mississippi River.
Net cash provided by financing activities was $56.3 million for the year ended December 31, 2012, compared to net cash provided by financing activities of $39.1 million for the year ended December 31, 2011. The 2012 activity consists of the $200.0 million Notes offering, issuance of $30.0 million of Series A convertible preferred stock and borrowings of $18.5 million under the 2011 Credit Facility, offset by the payment of long-term debt obligations of $169.9 million, which includes scheduled debt maturities and the repayment and termination of the 2011 Credit Facility with proceeds from the Notes offering and the payment of financing fees totaling $11.1 million primarily related to the Notes offering and the establishment of the Revolving Credit Facility. The 2011 net cash inflow is primarily attributable to the closing of the 2011 Credit Facility and the repayment of our then existing long-term debt in connection therewith.
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, 2013:
(1) Long-term obligation to related party is an obligation associated with a financing arrangement with Armstrong Resource Partners. Payments due are estimated based on current mine plans and estimated sales prices of the coal and will be revised as mine plans change. For the foreseeable future, we are deferring the payment of any production royalty amounts due to Armstrong Resource Partners. In consideration for granting the option to defer these payments, we granted to Armstrong Resource Partners the option to acquire an additional undivided interest in certain of our coal reserves in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which we would satisfy payment of any deferred fees by selling part of our interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.
Capital Expenditures
Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental regulations. Our anticipated total capital expenditures for 2014 are estimated in a range of $36.0 million to $38.0 million. Management anticipates funding 2014 capital requirements with current cash balances and cash flows provided by operations. We will continue to have significant capital requirements over the long-term, which may require us to incur debt or seek additional equity capital. The availability and cost of additional capital will depend upon prevailing market conditions and several other factors over which we have limited control, as well as our financial condition and results of operations.
Mine Development Costs
Mine development costs are capitalized until production commences, other than production incidental to the mine development process, and are amortized on a units-of-production method based on the estimated proven
and probable reserves. Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels. The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Our estimate of when construction of the mine for economic extraction is substantially complete is based upon a number of assumptions, such as expectations regarding the economic recoverability of reserves, the type of mine under development, and the completion of certain mine requirements, such as ventilation. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.
In April 2012, development of the Kronos mine was completed with the installation of the third and fourth units, which expanded annual production capacity to approximately 2.3 million tons. Capitalized development costs totaled $66.4 million, which are being amortized over the life of the mine.
The Lewis Creek underground mine, a two unit underground mine, came out of development in July 2013. Annual saleable production from the mine is estimated to be approximately 1.0 million tons. Capitalized development costs, which are being amortized over the life of the mine, totaled approximately $24.2 million.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as surety bonds and performance bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral. We also post performance bonds to secure our performance of various contractual obligations.
As of December 31, 2013, we had approximately $40.0 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $4.0 million of cash posted as collateral.
Related-Party Transactions
Sale of Coal Reserves
Armstrong Energy is majority-owned by Yorktown. Effective February 9, 2011, Armstrong Energy and several of its affiliates participated in a transaction with Armstrong Resource Partners, an entity also majority-owned by Yorktown, and several of its affiliates. In 2009 and 2010, Armstrong Energy borrowed an aggregate principal amount of $44.1 million from Armstrong Resource Partners. The borrowings were evidenced by promissory notes in favor of Armstrong Resource Partners in the principal amounts of $11.0 million on November 30, 2009, $9.5 million on March 31, 2010, $12.6 million on May 26, 2010 and $11.0 million on November 9, 2010, respectively. The promissory notes had a fixed interest rate of 3%. In addition, contingent interest equal to 7% of revenue would be accrued to the extent it exceeds the fixed interest amount. In consideration for Armstrong Resource Partners making these loans, Armstrong Energy granted it a series of options to acquire interests in the majority of coal reserves then held by us in Muhlenberg and Ohio Counties. On February 9, 2011, Armstrong Resources Partners exercised its options, paid Armstrong Energy an additional $5.0
million in cash and offset $12.0 million in accrued advance royalty payments owed by Armstrong Energy to Ceralvo Resources, LLC, and thereby acquired a 39.45% undivided interest as a joint tenant in common with Armstrong Energy’s subsidiaries in the aforementioned coal reserves. The aggregate amount paid by Armstrong Resource Partners to acquire its interest was the equivalent of approximately $69.5 million.
In December 2011, Armstrong Energy entered into a Membership Interest Purchase Agreement with Armstrong Resource Partners pursuant to which Armstrong Energy agreed to sell to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. In exchange for the agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners paid Armstrong Energy $20.0 million. In addition to the cash paid, certain amounts due by us to Armstrong Resource Partners totaling $5.7 million were forgiven by Armstrong Resource Partners, which resulted in aggregate consideration of $25.7 million. The partial undivided interest in additional reserves must be transferred to Armstrong Resource Partners within 90 days after delivery of the purchase price. This transaction, which closed on March 30, 2012, resulted in the transfer by us of an 11.36% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease.
In April 2013, pursuant to the Royalty Deferment and Option Agreement, Armstrong Energy sold to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. See “ - Royalty Deferment and Option Agreement.” In exchange for the agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners forgave certain amounts due by us to Armstrong Resource Partners, including cash royalty payments owed to Armstrong Resource Partners, offset by amounts due to us pursuant to the Administrative Services Agreement, totaling approximately $4.9 million. This transaction resulted in the transfer by us of a 2.59% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. As a result of this transaction, Armstrong Resource Partners’ undivided interest in certain of our land and mineral reserves in Muhlenberg and Ohio Counties increased to 53.4%. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease.
Lease Agreements
On February 9, 2011, Armstrong Energy’s subsidiary, Armstrong Coal, entered into a number of coal mining lease agreements with Western Mineral (a subsidiary of Armstrong Resource Partners) and two of Armstrong Energy’s wholly-owned subsidiaries. Pursuant to these agreements, Western Mineral granted Armstrong Coal a lease to its 39.45% undivided interest in certain mining properties and a license to mine coal on those properties that it had acquired in the above-described option transaction. The initial term of the agreement is 10 years, and it renews for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. Armstrong Coal must pay the lessors a production royalty equal to 7% of the sales price of the coal it mines from the properties.
On February 9, 2011, Armstrong Coal also entered into a lease and sublease agreement with Ceralvo Holdings, LLC, a subsidiary of Armstrong Resource Partners (Ceralvo Holdings). Pursuant to this agreement, Ceralvo Holdings granted Armstrong Coal leases and subleases, as applicable, to the Elk Creek Reserves and an exclusive license to mine coal on those properties. The initial term of the agreement is 10 years, and it automatically renews for 10 one-year terms and thereafter until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. Armstrong Coal must pay the lessor a production royalty equal to 7% of the sales price of the coal it mines from
the properties. In addition, Armstrong Coal must pay any royalties due for coal leased (not owned in fee) by Ceralvo Holdings. As of December 31, 2013, Armstrong Energy has paid $12 million of advance royalties under the lease, of which the entire amount has been recouped against production royalties.
Royalty Deferment and Option Agreement
Effective February 9, 2011, Armstrong Coal, Western Diamond and Western Land, each of which is a wholly owned subsidiary of Armstrong Energy, entered into a Royalty Deferment and Option Agreement with Western Mineral and Ceralvo Holdings, both wholly owned subsidiaries of Armstrong Resource Partners. Pursuant to this agreement, Western Mineral and Ceralvo Holdings agreed to grant to Armstrong Coal and its affiliates the option to defer payment, in whole or in part, of their pro rata share of the 7% production royalty described above. In consideration for the granting of the option to defer these payments, Armstrong Coal and its affiliates granted to Western Mineral the option to acquire an additional undivided interest in certain of the coal reserves held by Armstrong Energy, Inc. in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which Armstrong Coal and its affiliates would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.
Since this agreement was executed in February 2011, Armstrong Energy and its subsidiaries have paid cash royalties to Armstrong Resource Partners totaling $1.1 million, but expects to defer any royalties earned in the foreseeable future. In addition, Armstrong Energy has transferred reserves with a total fair market value, at the time of transfer, of $10.6 million in lieu of paying cash royalties. During this period, Armstrong Resource Partners has also acquired additional reserves from the Company for cash of $20.0 million. If Armstrong Energy continues to satisfy its royalty obligations to Armstrong Resource Partners by additional transfers of coal reserves, Armstrong Energy expects that it will transfer all of its existing fee-owned reserves to Armstrong Resource Partners by 2018.
Administrative Services Agreement
Effective as of January 1, 2011, Armstrong Energy entered into an Administrative Services Agreement with Armstrong Resource Partners (f/k/a Elk Creek LP) and its general partner, Elk Creek GP, pursuant to which Armstrong Energy will provide Armstrong Resource Partners with general administrative and management services, including, but not limited to, human resources, information technology, financial and accounting services and legal services. The fees charged are subject to adjustment annually in accordance with the terms of the Administrative Services Agreement. For the years ended December 31, 2013, 2012, and 2011, the fees due to Armstrong Energy pursuant to the Administrative Services Agreement totaled $0.8 million, $0.8 million, and $0.7 million, respectively. Armstrong Resource Partners shall also be liable for all taxes that are applicable from time to time to the services Armstrong Energy provides on its behalf.
Investment in Ram Terminals, LLC
On May 26, 2011, Armstrong Energy made a capital contribution in Ram in the amount of $2.47 million. Upon amendment of the Limited Liability Company Agreement of Ram (the Operating Agreement) on July 2, 2012, Armstrong Energy’s equity interest in Ram constituted 5.0%. The remaining membership interest is owned by Yorktown Energy Partners IX, L.P., a fund managed by Yorktown. Armstrong Energy is majority-owned by Yorktown. Yorktown Energy Partners IX, L.P. will provide the funds for future capital expenditures related to the development of the site. Armstrong Energy will be involved in the initial design and construction of the terminal and will provide accounting and bookkeeping assistance to Ram. Pursuant to the Operating Agreement, Armstrong Energy will not be liable for the debts, liabilities and other obligations of Ram. On February 1, 2014, Ram became an indirect subsidiary of Thoroughbred Resources, LP through its parent company, Terminal Holdings, LLC and our ownership interest in Ram was converted into an equity interest in Thoroughbred Resources, LP (see Item 13 - “Certain Relationships and Related Party Transactions, and Director Independence - Merger of Related Parties”).
Western Diamond and Western Land Coal Reserves Sale Agreement
On October 11, 2011, two of our subsidiaries, Western Diamond and Western Land (together, the Sellers), entered into an agreement with Western Mineral, a subsidiary of Armstrong Resource Partners, pursuant to which the Sellers agreed to sell an additional partial undivided interest in substantially all of the coal reserves and real property owned by the Sellers previously subject to the options exercised by Armstrong Resource Partners on February 9, 2011 (see “- Sale of Coal Reserves”), other than any of Sellers’ real property and related mining rights associated with the Parkway mine.
Thoroughbred Resources, LLC
On June 28, 2013, Thoroughbred, an entity wholly owned by Yorktown, acquired approximately 175 million tons of fee-owned coal reserves and 23 million tons of leased coal reserves from Peabody. The acquired coal reserves are located in Muhlenberg and McLean Counties of Kentucky, contiguous to Armstrong Energy’s reserves. In February 2014, we entered into a lease of these reserves in exchange for a production royalty.
In connection with Thoroughbred’s acquisition of these reserves, we loaned Thoroughbred $17.5 million, which was repaid in July 2013. The proceeds of the loan, which was evidenced by a promissory note, were used to make a portion of the down payment to Peabody for the reserves.
On February 1, 2014, Armstrong Resource Partners merged with and into Thoroughbred, with Armstrong Resource Partners as the surviving entity. Effective with the merger, Armstrong Resource Partners changed its name to Thoroughbred Resources, L.P. (see Item 13 - “Certain Relationships and Related Party Transactions, and Director Independence - Merger of Related Parties”).
Madisonville Office Lease
Beginning in 2008, pursuant to an oral agreement, Armstrong Coal leased from a then executive officer, and his spouse, certain property to be used by Armstrong Coal as its office space in Madisonville, Kentucky. Armstrong Coal agreed to pay $4,700 per month in exchange for the leased property, equipment, furniture, supplies and use of employees. On August 1, 2009, Armstrong Coal entered into a written lease agreement regarding the subject matter of the oral agreement. The terms of the written lease were the same as the terms of the prior oral agreement. The lease term ends on July 31, 2014, but automatically renews for additional 12-month periods unless either party gives written notice of termination no later than 30 days prior to the end of the term or a renewal term. Rent of $56,000, $61,000, and $56,000 were paid during the years ended December 31, 2013, 2012, and 2011, respectively.
Overriding Royalty Agreement
In 2006 and 2007, Armstrong Energy entered into overriding royalty agreements with a current and former executive officer to compensate them $0.05/ton of coal mined and sold from properties owned or leased by certain subsidiaries of Armstrong Energy. 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. We account for these royalty arrangements as expense in the period in which the coal is sold. Expense recorded in the years ended December 31, 2013, 2012, and 2011, was $0.8 million, $0.7 million, and $0.7 million, respectively.
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 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.
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 initially assembled by our staff and analyzed by a third party consultant, Weir International, Inc. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results. These factors and assumptions relate to geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine; the percentage of coal in the ground ultimately recoverable; historical production from the area compared with production from other producing areas; the assumed effects of regulation and taxes by governmental agencies; and assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.
For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Certain account classifications within our financial statements such as depreciation, depletion, and amortization and certain liability calculations such as asset retirement obligations may depend upon estimates of coal reserve quantities and values. Accordingly, when actual coal reserve quantities and values vary significantly from estimates, certain accounting estimates and amounts within our consolidated financial statements may be materially impacted. Coal reserve values are reviewed annually, at a minimum, for consideration in our consolidated financial statements.
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 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. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the years ended December 31, 2013, 2012, and 2011 was $2.5 million, $4.0 million and $4.0 million, respectively. At December 31, 2013 and 2012, our balance sheets reflected asset retirement obligation liabilities of $17.3 million and $18.5 million, respectively, including amounts classified as a current liability. See Note 19 to our audited consolidated financial statements for additional details regarding our asset retirement obligations.
Income Taxes
We account for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or the entire deferred tax asset will not be realized. In our evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our evaluation, we may record a change in valuation allowance through income tax expense in the period such determination is made. We believe that the judgments and estimates are reasonable; however, actual results could differ.
Based on our cumulative loss position and after evaluating other available evidence, we concluded the realizability of our net deferred tax assets was not more likely than not, and have established a valuation allowance against our net deferred tax assets. We have scheduled the reversals of our deferred tax assets and deferred tax liabilities and have concluded that based on the anticipated reversals, a valuation allowance is necessary only 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, Armstrong Resource Partners, 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, 2013, the effective interest on the long-term obligation to related party was 7.0%.
New Accounting Standards Issued and Adopted
We are an “emerging growth company,” as defined in Section 2(a)(19) of the Securities Act, as modified by the JOBS Act. Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards, and delay compliance with new or revised accounting standards until those standards are applicable to private companies. However, we 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.
In February 2013, the Financial Accounting Standards Board (FASB) issued an amendment to the accounting guidance for the reporting of amounts reclassified out of accumulated other comprehensive income (AOCI). The amendment expands the existing disclosure by requiring entities to present information about significant items reclassified out of AOCI by component. In addition, an entity is required to provide information about the effects on net income (loss) of significant amounts reclassified out of each component of AOCI to net income (loss) either on the face of the statement where net income (loss) is presented or as a separate disclosure in the notes of the financial statements. The amendment is effective prospectively for annual or interim reporting periods beginning after December 15, 2012. The adoption of this accounting pronouncement did not have a material impact on our financial statement disclosures.
Item 7A.
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. See Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Factors that Impact our Business” for more information about our multi-year coal supply agreements.
Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward purchases to manage a portion of our exposure related to diesel fuel volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have increased net loss by $0.9 million for the year ended December 31, 2013. A hypothetical increase of 10% in steel prices would have increased net loss by $2.1 million for the year ended December 31, 2013. A hypothetical increase of 10% in explosives prices would have increased net loss by $1.6 million for the year ended December 31, 2013.
Credit Risk
In 2013, approximately 99% of our coal sales were made to electric utilities. Therefore, our credit risk is primarily with domestic electric power generators. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into a transaction with the customer and to constantly monitor outstanding accounts receivable against established credit limits. When deemed appropriate, we will take steps to reduce credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. Credit losses are provided for in the financial statements and have historically been minimal.
Seasonality
Our business has historically experienced some variability in its results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as floods or blizzards, can impact our ability to mine and ship our coal and our customers’ ability to take delivery of coal.
Item 8.
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 through of this report and are incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements with Accountant on Accounting and Financial Disclosure
None.
Item 9A.
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, 2013. 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.
Changes in Internal Control over Financial Reporting
During the fourth quarter of 2013, 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.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
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, 2014. 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
Chairman (Class II) and Chief Executive Officer
Martin D. Wilson
President and Director (Class I)
Kenneth E. Allen
Executive Vice President of Operations
J. Richard Gist
Senior Vice President, Finance and Administration and Chief Financial Officer
Brian G. Landry
Vice President, Information Technology
Anson M. Beard, Jr.
Director (Class I)
James C. Crain
Director (Class III)
Richard F. Ford
Director (Class III)
Bryan H. Lawrence
Director (Class III)
Greg A. Walker
Director (Class II)
Biographical information concerning the directors and executive officers listed above is set forth below. The term of our Class I directors expires in 2015, the term of our Class II directors expires in 2016, and the term of our Class III directors expires in 2014.
J. Hord Armstrong, III - Mr. Armstrong served as our Predecessor’s Chairman and Chief Executive Officer, and as a member of our Predecessor’s board of managers, from its formation in 2006 until 2011. Since 2011, Mr. Armstrong has been our Chairman and Chief Executive Officer. Previously, Mr. Armstrong worked for the Morgan Guaranty Trust Company and was elected Assistant Treasurer in 1967. He subsequently spent 10 years with White Weld & Company as First Vice President until the firm was acquired by Merrill Lynch in 1978. Mr. Armstrong then joined Arch Mineral Corporation, St. Louis, as Treasurer (1978-1981), and ultimately became its Vice President and Chief Financial Officer (1981-1987). Mr. Armstrong left Arch Mineral in 1987, when he founded D&K Healthcare Resources. Mr. Armstrong served as D&K’s Chief Executive Officer from 1987 to 2005. D&K Healthcare Resources became a public company in 1992 and was acquired by McKesson Corporation in 2005. Mr. Armstrong served for 10 years as a member of the Board of Trustees of the St. Louis College of Pharmacy, as well as a Director of Jones Pharma Incorporated. He was formerly Chairman of the Board of Trustees of the Pilot Fund, a registered investment company. He was also formerly a Director of BHA, Inc. of Kansas City, Missouri, and a Director of GeoMet, Inc. of Houston, Texas. He currently serves as Advisory Director of US Bancorp. The board selected Mr. Armstrong to serve as a director because of his extensive experience in the coal industry and public company management, as well as his previous tenure with our company. The board believes his prior experiences afford him unique insights into our company’s strategies, challenges and opportunities.
Martin D. Wilson - Mr. Wilson served as our Predecessor’s President, and as a member of our Predecessor’s board of managers, from its formation in 2006 until 2011. Since 2011, Mr. Wilson has been our President. From 1985 to 1988, Mr. Wilson was employed by KPMG Peat Marwick. From 1988 until 2005, Mr. Wilson served as President and Chief Operating Officer of D&K Healthcare Resources. The board selected Mr. Wilson to serve as a director because of his experience in public company management.
Kenneth E. Allen - Mr. Allen served as our Predecessor’s Vice President of Operations from 2007 until 2011. Since 2011, Mr. Allen has been our Executive Vice President of Operations. In December 2013, Mr. Allen
was also named Chief Operating Officer of Armstrong Coal Company, a wholly-owned subsidiary of Armstrong Energy. He started his career with Peabody Coal Company in 1967 and has over 40 years of experience in the coal industry. In 1971, he moved into a supervisory position and continued to hold various supervisory and management positions, including Chief Electrical Engineer, Mine Superintendent, Operations Manager and Vice President of Resource Development and Conservancy. Prior to joining our company in 2007, Mr. Allen held the position of President and General Manager of Bluegrass Coal Company, a subsidiary of Peabody Energy. Mr. Allen is Chairman of the Upper Pond River Conservancy District and a member of the Kentucky Workforce Investment Board of Directors, the West Kentucky Consortium for Energy and Environment, 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 the Western Kentucky Coal Association.
J. Richard Gist - Mr. Gist served as our Predecessor’s Vice President and Controller from 2009 until 2011. Since 2011, Mr. Gist has been our Senior Vice President, Finance and Administration and Chief Financial Officer. Mr. Gist began his career with Arthur Andersen in 1978 and subsequently held a number of positions at St. Joe Minerals, an entity which owned part of Massey Energy, NERCO, Ziegler Coal and Peabody Energy. From 2000 until its purchase by McKesson Corporation in 2005, Mr. Gist was the Vice President and Controller of D&K Healthcare Resources. From 2005 until 2006, Mr. Gist worked as part of the transition team with McKesson. From 2006 until 2009, he served as Vice President-Marketing Administration of Arch Coal. Mr. Gist is a Certified Public Accountant.
Brian G. Landry - Mr. Landry served as our Predecessor’s Vice President, Information Technology from 2010 until 2011. Since 2011, Mr. Landry has been our Vice President, Information Technology. From 2007 until 2010, Mr. Landry served as Senior Vice President of Information Technology of H.D. Smith Drug Company. Prior to that, Mr. Landry spent 10 years with D&K Healthcare Resources, Inc., ultimately serving as its Senior Vice President of Operations and Chief Information Officer.
Anson M. Beard, Jr. - Mr. Beard was appointed to our board in 2011. He joined Morgan Stanley & Co. as a Vice President to found Private Client Services in 1977. He was promoted to Principal in 1979 and Managing Director in 1980. In 1981, he was put in charge of the Firm’s Equity Division, responsible for sales and trading relationships with institutional and individual investors of all equity and related products worldwide. In 1987, he was elected to the Firm’s Management Committee and the Board of Directors of Morgan Stanley Group. Mr. Beard was also the former Chairman of Morgan Stanley Security Services, Inc., a subsidiary of Morgan Stanley Group, which engaged in stock borrowing/lending, customer and dealer clearance, international settlements and custody. He previously served as a Trustee of the Morgan Stanley Foundation, Vice Chairman of the National Association of Securities Dealers, and Chairman of its NASDAQ, Inc. subsidiary. In 1994, Mr. Beard retired and became an Advisory Director of Morgan Stanley. He continues to serve in this capacity. Mr. Beard was selected for board membership because of his past board and committee experience and his knowledge of securities markets and publicly traded companies.
James C. Crain - Mr. Crain was appointed to our board of directors in 2011. Mr. Crain has been in the energy industry for over 30 years, both as an attorney and as an executive officer. In July 2013, Mr. Crain retired as President of Marsh Operating Company, an investments management company, a position he held since 1989. Before joining Marsh in 1984, Mr. Crain was a partner in the law firm of Jenkens & Gilchrist, where he headed the firm’s energy section. Mr. Crain is a director of Crosstex Energy, Inc., a midstream natural gas company, GeoMet, Inc., a natural gas exploration and production company, and Approach Resources, Inc., an independent oil and natural gas company. During the past five years, Mr. Crain has also been a director of Crosstex Energy, GP, LLC, the general partner of a midstream natural gas company, and Crusader Energy Group Inc., an oil and gas exploration and production company. The board selected Mr. Crain to serve as a director because of his extensive legal, investment and transactional experience, as well as his public company board experience.
Richard F. Ford - Mr. Ford was appointed to our board in 2011. Mr. Ford is the retired general partner of Gateway Associates, L.P., a venture capital management firm that he formed in 1984. Mr. Ford serves as a member of the board of directors and a member of the audit committees of Barry-Wehmiller Company. Until 2012, Mr. Ford served as a director of Stifel Financial Corp. Mr. Ford also serves as a member of the board of directors and chair of the audit committee of Spartan Light Metal Products, Inc., a privately-held company. He currently serves on the board of directors of Washington University in St. Louis, Missouri. The board selected Mr. Ford to serve as a director because of his substantial experience in the financial services industry. He also has considerable board and committee leadership experience at other publicly held and large private companies.
Bryan H. Lawrence - Mr. Lawrence served as a member of our Predecessor’s board of managers from its formation in 2006 until 2011. He was appointed to our board of directors in 2011. 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. 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, 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 serves on our board of directors because of his significant knowledge of all aspects of the energy industry.
Greg A. Walker - Mr. Walker was appointed to our board of directors in 2011. From 2009 to 2011, he served as a Senior Vice President of Alpha Natural Resources, Inc., assisting with integration issues after the merger of Alpha Natural Resources, Inc. and Foundation Coal Holdings, Inc. From 2004 to 2009, Mr. Walker served as the Senior Vice President, General Counsel and Secretary of Foundation Coal Holdings, Inc. From 1999 to 2004, he served as the Senior Vice President, General Counsel and Secretary of RAG American Coal Holdings, Inc., which was the predecessor entity to Foundation Coal Holdings, Inc. From 1989 to 1999, he served in various capacities in the law department of Cyprus Amax Minerals Company. 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 are working with the U.S. Department of Energy to build and operate a commercial scale oxy-combustion coal-fired power plant with carbon dioxide capture and sequestration. He currently also serves as the Treasurer and Secretary of FutureGen. From 2007 through 2010, he served as an appointee from the United States to the Coal Industry Advisory Board, an international advisory panel to the International Energy Administration with respect 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 seven directors. Our board has established the following committees: an audit committee, a compensation committee, a nominating, corporate governance and risk management committee and a conflicts committee. The composition and responsibilities of each committee are described below. Members serve on these committees until their resignation or until otherwise determined by our board.
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, 2013 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, 2013, 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
•
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, 2013.
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 new compensation philosophy and objectives, administrate our executive and director compensation programs and plans, and review and approve the compensation of our named executive officers.
The 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, Corporate Governance and Risk Management Committee
Messrs. Beard, Crain and Ford, each an independent director, serve on our nominating, corporate governance and risk management committee. Mr. Crain is the chair of this committee. The committee is responsible for: (i) assisting the board by identifying individuals qualified to become board members, and recommending to our board nominees for election as director, (ii) leading the board in its annual performance review, (iii) recommending to the board members and chairpersons for each committee, (iv) monitoring the attendance, preparation and participation of individual directors and conducting a performance evaluation of each director prior to the time he or she is considered for re-nomination to the board of directors, (v) monitoring and evaluating corporate governance issues and trends, and (vi) discharging the board’s responsibilities relating to compensation of our directors by reviewing such compensation annually and then recommending any changes in such compensation to the full board of directors.
Conflicts Committee
Messrs. Beard, Crain and Walker, each an independent director, serve on our conflicts committee. Mr. Walker is the chair of this committee. The committee is responsible for: (i) reviewing specific matters that the board believes may involve conflicts of interest, (ii) reviewing specific matters requiring action of the conflicts committee pursuant to any agreement to which we are a party, (iii) advising the board on actions to be taken by us upon the board’s request, and (iv) carrying out any other duties delegated to the conflicts committee by the board of directors.
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, 2013.
Item 11.
Item 11. Executive Compensation
2013 Summary Compensation Table
The following table sets forth all compensation paid to our named executive officers for the years ending December 31, 2013 and 2012.
(1) Amounts disclosed in this column relate to grants of Armstrong Energy common stock and Armstrong Resource Partners common units. The amounts reflect the grant date fair value computed in accordance with FASB Accounting Standards Codification (ASC) Topic 718.
(2) Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Armstrong ($12,250), an allowance for personal automobile usage ($12,000), the incremental cost to the Company of Mr. Armstrong’s personal use of our corporate aircraft ($40,124), and an allowance for club membership dues ($9,276). 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.
(3) Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Wilson ($12,250), an allowance for personal automobile usage ($12,000), the incremental cost to the Company of Mr. Wilson’s use of our corporate aircraft ($18,470), and an allowance for club membership dues ($9,221).
(4) Represents overriding royalties paid to Mr. Allen ($401,756) (see “- Overriding Royalty Agreements” 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 ($12,250), and an allowance for personal automobile usage ($12,000).
(5) Mr. Cobb was appointed Executive Vice President of Business Development effective October 1, 2011. Prior to this time, Mr. Cobb was our Vice President of Business Development. Mr. Cobb retired effective December 31, 2013. (See - “Employment Agreements” for additional information on his retirement).
(6) Represents overriding royalties paid to Mr. Cobb ($401,756 (see “- Overriding Royalty Agreements” for a description of Mr. Cobb’s agreement with us regarding the payment of overriding royalties), our matching contributions paid to our 401(k) plan on behalf of Mr. Cobb ($11,567), and an allowance for personal automobile usage ($12,000).
(7) Represents our matching contributions paid to our 401(k) plan on behalf of Mr. Gist ($5,300), the incremental cost to the Company of Mr. Gist’s use of our corporate aircraft ($2,845), and an allowance for personal automobile usage ($12,000).
Elements of Compensation
Prior Compensation Program
Historically, our executive officers have received annual salaries as their compensation for services. In addition, our board had the ability to grant discretionary cash bonuses and equity to our executive officers in order to align the compensation interests of our executive officers with our short-term and long-term interests. Decisions regarding compensation of our executive officers generally were made by the compensation committee, based upon the recommendations of our president. The base salary for each of our named executive officers is set forth in his employment agreement and is subject to adjustment annually as determined by the board of directors. See “ - Employment Agreements.” Historically, we had not set any specific performance targets for Armstrong Energy or for individual executive officers. Determinations regarding salary adjustments were made based on a number of objective and subjective factors, including cost of living increases, our financial performance in a general sense, including our Adjusted EBITDA, and a qualitative analysis of each individual officer’s performance during the preceding year, taking into account such factors as leadership, commitment and execution of corporate initiatives and special projects assigned by the board of directors. We also considered whether there had been any material change in the officer’s title, duties and responsibilities in the preceding year. Finally, we would make a market adjustment in salaries, if we determined that salary levels for one or more of our named executive officers had fallen materially below levels that we considered appropriate in order to maintain a competitive compensation package and to discourage valued executives from leaving their positions with us to pursue other opportunities. In making market adjustments, we informally analyzed publicly available data relating to historical compensation paid to certain executive officers at several public coal mining companies. The specific companies included in the analysis could change from year to year. For 2013, we included the following companies in our analysis: Hallador Energy Company, James River Coal Company, Oxford Resource Partners, LP, Rhino Resource Partners LP and Westmoreland Coal Company. We have not utilized a compensation consultant in the past.
Each year, the compensation committee determined the amount of any discretionary bonuses to be paid to our named executive officers, based upon the recommendations of our president. The bonuses were determined in a manner similar to the annual base salary adjustments described above, i.e. based on a number of objective and subjective factors, including the target bonus set forth in the respective officer’s employment agreement, if any (see “ - Employment Agreements - Armstrong and Wilson Employment Agreements” and “ - Employment Agreements - 2011 Gist Employment Agreement”), our financial performance in a general sense, and a qualitative analysis of each individual officer’s performance during the preceding year, taking into account such factors as leadership, commitment, and execution of corporate initiatives and special projects assigned by the board. However, no specific pre-established performance objectives were set and, ultimately, the amount of annual bonuses was determined at the final discretion of the compensation committee. The discretionary bonuses were also considered together with the base salary adjustments in ensuring that our executive officers are provided a competitive level of cash compensation each year, but the discretionary bonus portion provided flexibility to adjust total annual cash compensation to align with current performance.
In making bonus recommendations to the compensation committee for 2013, Mr. Wilson, our president, informally conducted a subjective evaluation considering the target bonus set forth in the respective officer’s employment agreement, if any, internal equity among the named executive officers, current aggregate
compensation levels, performance, long-term career goals, future leadership potential, succession planning, and other individual intangible contributions that enhance operating and financial performance. Neither Mr. Wilson nor the compensation committee used a formula to weight these factors, but instead used these factors to provide context within which to assess the significance of comparative market data and to differentiate the level of compensation among our named executive officers.
On June 1, 2011, prior to the approval of the LTIP, we granted to each of Messrs. Armstrong, Wilson, Allen and Cobb 18,500 restricted shares of common stock of Armstrong Energy, which vested on April 1, 2013. The aggregate grant date fair value of each award was $257,600.
Also, on October 1, 2011, Armstrong Resource Partners granted 22,500 and 20,000 restricted units of limited partner interest to Mr. Armstrong and Mr. Wilson, respectively. The aggregate grant date fair value of Mr. Armstrong’s award was $3,082,500, and the aggregate grant date fair value of Mr. Wilson’s award was $2,740,000. Pursuant to the terms of each of the Restricted Unit Award Agreements, the grantee was required to deliver to us that number of restricted units, valued at the fair market value of such units at the time of such delivery, to satisfy any federal, state or local taxes due in connection with the grant. Effective January 25, 2012, Mr. Armstrong entered into an Assignment of Limited Partnership Units with us, pursuant to which Mr. Armstrong transferred and assigned 9,405 units to us, in exchange for our agreement to pay any federal, state or local taxes arising from the grant, the total amount of which has been determined to be equal to approximately $1.3 million. Also effective January 25, 2012, Mr. Wilson entered into an Assignment of Limited Partnership Units with us, pursuant to which Mr. Wilson transferred and assigned 8,360 units to us, in exchange for our agreement to pay any federal, state or local taxes arising from the grant, the total amount of which has been determined to be equal to approximately $1.1 million.
The LTIP provides for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, performance grants and other equity-based incentive awards to those who contribute significantly to our strategic and long-term performance objectives and growth. No awards were made under the LTIP in 2013, 2012 or 2011. The LTIP is more fully described below under “ - 2011 Long-Term Incentive Plan.”
New Compensation Program for 2014
Our compensation committee reevaluated and restructured our compensation program for 2014. 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 chief executive officer and president, respectively, to a low of approximately 27% to a high of approximately 53% for the other named executive officers, other than Mr. Cobb, who retired effective December 31, 2013.
Our compensation committee will continue to consider informally the executive compensation data of certain publicly traded coal companies. The compensation committee will use 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 do not intend to utilize a compensation consultant in 2014. The compensation committee will consider internal pay equity when making compensation decisions for executive officers, excluding any overriding royalties that may be due to executive officers. See “ - Overriding Royalty Agreements.” However, the compensation committee does not use a fixed ratio or formula when comparing compensation among executive officers.
The new 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. It is the compensation committee’s intention to maintain salaries at or near peer group medians. However, as discussed above, the compensation committee uses peer group data as a point of reference for comparative purposes, and 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 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 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 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.
Other Executive Benefits
Our named executive officers are eligible for the following benefits on the same basis as other eligible employees:
•
Health insurance;
•
Vacation, personal holidays and sick time;
•
Life insurance and supplemental life insurance;
•
Short-term and long-term disability; and
•
A 401(k) plan with matching contributions.
In addition, we provide our named executive officers with an annual car allowance and a payment equal to the group term life insurance premium paid on each named executive officer’s behalf. Also, we provide Messrs. Armstrong and Wilson with an allowance for club membership dues. Company aircraft may occasionally be used by executive officers for personal travel.
Employment Agreements
2007 Allen and Cobb Employment Agreements
Effective June 1, 2007, we entered into an employment agreement (the “2007 Allen Employment Agreement”) with Mr. Allen. Effective January 1, 2007, we entered into an employment agreement (the “2007 Cobb Employment Agreement” and together with the Allen Employment Agreement, the “2007 Agreements”). Pursuant to the 2007 Agreements, we agreed to pay Messrs. Allen and Cobb initial base salaries of $240,000 and $180,000, respectively. The base salaries are subject to adjustment annually as determined by the board of
directors. Effective January 1, 2012, the base salaries of Messrs. Allen and Cobb were increased to $300,000 and $260,000, respectively. Effective January 1, 2013, the base salaries of Messrs. Allen and Cobb were increased to $350,000 and $280,000, respectively.
The term of each of the 2007 Agreements is three years, and each shall be automatically renewed for additional one-year terms until such time, if any, as we or the respective executive give written notice to the other party that such automatic extension shall cease. In the case of the 2007 Allen Employment Agreement, such notice must be given at least 60 days prior to the expiration of the then current term.
The 2007 Agreements contain non-competition and non-solicitation provisions that endure for a period of 12 months following the executives’ termination of employment with us.
In addition, pursuant to each of the 2007 Agreement and the related overriding royalty agreement, as amended, between Mr. Allen and us, and the 2007 Cobb Employment Agreement and the related overriding royalty agreement, as amended, between Mr. Cobb and us, Messrs. Allen and Cobb each receive an overriding royalty equal to $0.05 per ton sold by us from certain reserves described in those agreements. See “ - Overriding Royalty Agreements.”
Pursuant to the 2007 Agreements, we may terminate each agreement at any time for cause, which is defined as: (i) the executive’s failure substantially to perform his duties under the agreement in a manner satisfactory to the board, (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, (viii) resignation by the executive under circumstances where a termination for “cause” was impending or could have reasonably been foreseen.
We also may terminate each of the 2007 Agreements without cause, as defined above. In the event of such termination without cause, the executive shall be entitled to receive (i) the executive’s base salary for 12 months following termination, and (ii) health insurance premiums for 12 months. In addition, the respective overriding royalty will run with the land per the provisions of the overriding royalty agreements. See “ - Overriding Royalty Agreements.”
Under each of the 2007 Agreements, the executive may resign for good reason, which is defined as a material demotion or reduction 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 agreements. See “ - Overriding Royalty Agreements.”
In the event of a termination of the executive’s employment, other than for cause, within 12 months of a change in control, the executive shall be entitled to receive health insurance premiums for 12 months. In addition, 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.
Effective December 31, 2013, Mr. Cobb retired from his position as Executive Vice President of Business Development of Armstrong Energy, Inc. (the “Company”). Mr. Cobb’s duties will be split among several other members of management.
Effective January 1, 2014, the Company and Mr. Cobb entered into a Retirement, Consulting and Release Agreement (the “Agreement”) in connection with Mr. Cobb’s retirement from his position as Executive Vice President of Business Development of the Company. The Agreement will terminate on June 30, 2014. For purposes of transitioning his duties, Mr. Cobb has agreed to perform those services which he previously performed for the Company on an as-needed basis through June 30, 2014. The Agreement provides that during the term of the Agreement Mr. Cobb will (1) continue to receive his current salary; (2) continue to receive and/or be eligible for all regular benefits offered to full-time employees; and (3) be reimbursed for reasonable business and travel expenses incurred on behalf of the Company. Mr. Cobb will continue to be bound by confidentiality and non-competition provisions set forth in his restated employment agreement until December 31, 2014.
Gist Employment Agreement
Effective October 1, 2011, we entered into a new employment agreement with Mr. Gist (the Gist Agreement).
Pursuant to the Gist Agreement, we agreed to pay Mr. Gist $210,000 for his services as our Senior Vice President, Finance and Administration and Chief Financial Officer. Effective January 1, 2012, Mr. Gist’s base salary was increased to $235,000 and increased to $265,000 effective January 1, 2013. In addition, Mr. Gist is entitled to an annual target bonus equal to a percentage of his then annual salary based upon the achievement of certain performance criteria. As of December 31, 2013, the Company had not established any performance criteria pursuant to the Gist Agreement. However, the board granted Mr. Gist a discretionary cash bonus in the amount of $170,000 for 2013 and $120,000 for 2012.
The term of the Gist Agreement is one year, and shall be automatically renewed for additional one year terms until such time as we or Mr. Gist gives written notice to the other party that such automatic extension shall cease.
Pursuant to the Gist Agreement, we may terminate the agreement at any time for cause, which is defined as: (i) Mr. Gist’s failure substantially to perform his duties in a manner satisfactory to the board, (ii) Mr. Gist has engaged in gross misconduct, dishonest, disloyal, illegal or unethical conduct, or any other conduct which has or could reasonably have a detrimental impact on our company or its reputation, (iii) Mr. Gist has acted in a dishonest or disloyal manner, or breached any fiduciary duty to our company that, in either case, results or was intended to result in personal profit to Mr. Gist at the expense of our company or any of its customers, (iv) Mr. Gist has been convicted of or pleads guilty or no contest to any felony, (v) Mr. Gist has one or more physical or mental impairments which have substantially impaired his ability to perform the essential functions of his job, (vi) Mr. Gist’s death, (vii) any breach by Mr. Gist of certain obligations under the agreement, (viii) resignation by Mr. Gist under circumstances where a termination for “cause” was impending or could have reasonably been foreseen.
We also may terminate the Gist Agreement without cause, as defined above. In the event of such termination without cause, Mr. Gist shall be entitled to receive (i) his base salary for 12 months following termination, plus any accrued but unpaid bonus, and (ii) health insurance premiums for 12 months.
Pursuant to the Gist Agreement, Mr. Gist may resign for good reason, which is defined as a material demotion or reduction in Mr. Gist’s duties. In the event of a resignation for good reason, Mr. Gist shall be entitled to receive (i) his base salary for 12 months following termination, and (ii) health insurance premiums for 12 months.
In the event of a termination of Mr. Gist’s employment, other than for cause, within 12 months of a change in control, Mr. Gist shall be entitled to receive health insurance premiums for 12 months. In addition, we will pay, promptly following such termination, a lump sum payment equal to one times Mr. Gist’s annual base salary, plus one year’s bonus in an amount equal to 50% of his then existing annual base salary.
The 2011 Gist Agreement contains non-competition and non-solicitation provisions that endure for a period of 12 months following Mr. Gist’s termination of employment with us.
Armstrong and Wilson Employment Agreements
Effective October 1, 2011, we entered into an employment agreement with each of Messrs. Armstrong and Wilson (together, the “Armstrong and Wilson Agreements”).
Pursuant to each of the Armstrong and Wilson Agreements, we agreed to pay each of Messrs. Armstrong and Wilson a base salary of $300,000. Effective January 1, 2012, the base salary of each of Messrs. Armstrong and Wilson was increased to $350,000 and effective January 1, 2013 the base salary for each was raised to $400,000. In addition, each of Messrs. Armstrong and Wilson is entitled to an annual bonus based upon achievement of certain performance criteria. The target amount will not be less than 75% of the executive’s then annual base salary. The executive’s base salary and bonus will be reviewed from time to time and may be increased. As of December 31, 2013, the Company had not established any performance criteria pursuant to the Armstrong and Wilson Agreements. However, the board granted each of Messrs. Armstrong and Wilson a discretionary cash bonus in the amount of $400,000 and $400,000, respectively, for 2013 and $262,500 and $300,000, respectively, for 2012.
The term of each of the Armstrong and Wilson Agreements is three years, and each shall automatically renew for successive one-year terms unless either party gives the other a notice of non-renewal at least 90 days before the end of the then current term.
Pursuant to the Armstrong and Wilson Agreements, we may terminate Mr. Armstrong’s and Mr. Wilson’s employment at any time without cause (as defined below), and each of Mr. Armstrong and Mr. Wilson may terminate his own employment at any time for good reason (as defined below). In the event of a termination without cause, failure by us to renew the agreement or termination by the executive for good reason, (i) we will continue to pay the executive’s base salary and provide his other benefits (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); plus (z) if such notice is given within the first 12 months after October 1, 2011, then, the salary the executive should have been paid from the date of termination through the end of such 12-month period; and
(b) during the portion, if any, of the 24-month period commencing on the date of the executive’s separation from service that the executive is eligible to elect and elects to continue coverage for himself and his eligible dependents under our health plan pursuant to COBRA or a similar state law, we shall reimburse the executive for the difference between the amount the executive pays to effect and continue such coverage and the employee contribution amount that our active senior executive employees pay for the same or similar coverage.
The Armstrong and Wilson Agreements contain non-competition provisions that continue for 18 months following a termination of employment with us. In addition, the Armstrong and Wilson Agreements contain non-solicitation provisions that endure for a period of 24 months following the executive’s termination.
Overriding Royalty Agreements
On December 3, 2008, we entered into an amended and restated overriding royalty agreement with Mr. Cobb pursuant to which we agreed to pay Mr. Cobb a royalty of five cents ($0.05) per ton of all coal thereafter mined or extracted and subsequently sold from certain of our reserves. The term of the royalty began on November 22, 2006, and is set to continue until the later of: (i) November 22, 2026, or (ii) such time as all of the mineable and saleable coal from the subject properties has been mined. The agreement also states that the overriding royalty shall constitute an independent and enforceable obligation that shall run with the land and shall be binding on us, our respective assigns and successors, and any subsequent owner of the subject properties.
On December 3, 2008, we entered into an amended and restated overriding royalty agreement with Mr. Allen pursuant to which we agreed to pay Mr. Allen a royalty of five cents ($0.05) per ton of all coal thereafter mined or extracted and subsequently sold from certain of our reserves. The term of the royalty began on February 9, 2007, and is set to continue until the later of: (i) February 9, 2027, or (ii) such time as all of the mineable and saleable coal from the subject properties has been mined. The agreement also states that the overriding royalty shall constitute an independent and enforceable obligation that shall run with the land and shall be binding on us, our respective assigns and successors, and any subsequent owner of the subject properties.
Tax Considerations
In the past, we have not taken into consideration the tax consequences to employees and us when considering the types and levels of awards and other compensation granted to executives and directors. However, we anticipate that the compensation committee will consider these tax implications when determining executive compensation in the future.
Outstanding Equity Awards at 2013 Fiscal Year-End
There were no outstanding option and stock awards held by the named executive officers as of December 31, 2013.
2011 Long-Term Incentive Plan
Our board of directors has adopted the 2011 Long Term Incentive Plan (the LTIP) for our employees and directors, as well as for consultants and independent contractors who perform services for us. The LTIP is
administered by the compensation committee, which has the authority to select recipients of awards and determine the type, size, terms and conditions of awards. The maximum aggregate number of shares of common stock available for issuance under the LTIP is 10% of our authorized shares of common stock. No awards were made under the LTIP in 2013 or 2012.
The LTIP provides for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, performance grants and other equity-based incentive awards to those who contribute significantly to our strategic and long-term performance objectives and growth, as the compensation committee may determine.
Except with respect to restricted stock awards and unless otherwise determined by the committee in its discretion, the recipient of an award has no rights as a stockholder until he or she receives a stock certificate or has his or her ownership entered into the books of the Company.
The compensation committee has the authority to administer the LTIP and may determine the type, number and size of the awards, the recipients of awards and the terms and conditions applicable to awards made under the LTIP. The committee may also generally amend the terms and conditions of awards, subject to certain restrictions.
The LTIP will terminate upon the earlier of the adoption of a board resolution terminating the LTIP or 10 years from its effective date.
The following is a brief summary of the types of awards available for issuance under the LTIP:
Stock Options
The committee may grant non-qualified and incentive stock options under the LTIP, provided that incentive stock options shall be granted to employees only. The exercise price of stock options must be no less than the fair market value of the common stock on the date of grant and expire 10 years after the date of grant. The exercise price of incentive stock options granted to holders of at least 10% of the Company’s stock must be no less than 110% of such fair market value, and incentive stock options expire five years from the date of grant.
Stock Appreciation Rights
An award of a stock appreciation right entitles the recipient to receive, without payment, the number of shares of common stock having an aggregate value equal to the excess of the fair market value of one share of common stock at the time of exercise over the exercise price, times the number of shares of common stock subject to the award. Stock appreciation rights shall have an exercise price no less than the fair market value of the common stock on the date of grant.
Restricted Stock and Restricted Stock Units
In addition to other terms and conditions applicable to restricted stock and restricted stock unit awards, the compensation committee shall establish the restricted period applicable to such awards. The awards shall vest in one or more increments during the restricted period, which shall not be less than three years; provided, however, that this limitation shall not apply to awards granted to non-employee directors. As may be subject to additional conditions in the committee’s discretion, recipients of such awards shall have voting, dividend and other stockholder rights with respect to the awards from the date of grant.
Performance Grants
Performance grants shall consist of a right that is (i) denominated in cash, common stock or any other form of award issuable under the LTIP, (ii) valued in accordance with the achievement of certain performance goals
applicable to performance periods as the committee may establish, and (iii) payable at such time and in such form as the committee shall determine. The committee may reduce the amount of any performance grant in its discretion if it believes a reduction is necessary based on the recipient’s performance, comparisons with compensation received by similarly-situated recipients within the industry, the Company’s financial results, or any other factors deemed relevant.
Other Share-Based Awards
Other share-based awards may consist of any other right payable in, valued by, or otherwise related to common stock. The awards shall vest in one or more increments during a service period, which shall not be less than three years; provided, however, that this limitation shall not apply to awards granted to non-employee directors.
Compensation of Directors
Each of our independent directors receives (a) an annual cash retainer of $50,000, and (b) $1,500 per meeting of the board of directors attended by such director ($500 in the case of telephonic participation). Our nominating, corporate governance and risk management committee reviews and makes recommendations to the board regarding compensation of directors, including equity-based plans. We reimburse our non-employee directors for reasonable travel expenses incurred in attending board and committee meetings. We also intend to allow our non-employee directors to participate in the LTIP and any other equity compensation plans that we adopt in the future.
The following table discloses compensation paid for the fiscal year ended December 31, 2013 to our independent directors for serving as members of the Board.
2013 Director Compensation Table
Item 12.
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, 2014 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 21,925,976 shares of common stock outstanding as of March 1, 2014.
A person is a “beneficial owner” of a security if that person has or shares voting or investment power over the security or if he or she has the right to acquire beneficial ownership within 60 days. Unless otherwise noted, these persons, to our knowledge, have sole voting and investment power over the shares listed. The following table includes equity awards granted to our executive officers on a discretionary basis. Except as otherwise noted,
the principal address for the stockholders listed below is c/o Armstrong Energy, Inc., 7733 Forsyth Boulevard, Suite 1625, St. Louis, Missouri 63105.
* Less than 1%.
(1) Does not reflect any fractional shares beneficially owned.
(2) The address of this beneficial owner is 410 Park Avenue, 19th Floor, New York, New York 10022.
(3) These shares are held of record by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP is the sole general partner of Yorktown Energy Partners VII, L.P. Yorktown VII Associates LLC is the sole general partner of Yorktown VII Company LP. As a result, Yorktown VII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP and Yorktown VII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VII, L.P. in excess of their pecuniary interests therein.
(4) These shares are held of record by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP is the sole general partner of Yorktown Energy Partners VIII, L.P. Yorktown VIII Associates LLC is the sole general partner of Yorktown VIII Company LP. As a result, Yorktown VIII Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP and Yorktown VIII Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners VIII, L.P. in excess of their pecuniary interests therein.
(5) These shares are held of record by Yorktown Energy Partners IX, L.P. Yorktown IX Company LP is the sole general partner of Yorktown Energy Partners IX, L.P. Yorktown IX Associates LLC is the sole general partners of Yorktown IX Company LP. As a result, Yorktown IX Associates LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the shares owned by Yorktown Energy Partners IX, L.P. Yorktown IX Company LP and Yorktown IX Associates LLC disclaim beneficial ownership of the securities owned by Yorktown Energy Partners IX, L.P. in excess of their pecuniary interests therein.
Item 13.
Item 13. Certain Relationships and Related-Party Transactions, and Director Independence
Sale of Coal Reserves
Armstrong Energy is majority-owned by Yorktown. Effective February 9, 2011, Armstrong Energy and several of its affiliates participated in a transaction with Armstrong Resource Partners, an entity also majority-owned by Yorktown, and several of its affiliates. In 2009 and 2010, Armstrong Energy borrowed an aggregate principal amount of $44.1 million from Armstrong Resource Partners. The borrowings were evidenced by promissory notes in favor of Armstrong Resource Partners in the principal amounts of $11.0 million on November 30, 2009, $9.5 million on March 31, 2010, $12.6 million on May 26, 2010 and $11.0 million on November 9, 2010, respectively. The promissory notes had a fixed interest rate of 3%. In addition, contingent interest equal to 7% of revenue would be accrued to the extent it exceeds the fixed interest amount. In consideration for Armstrong Resource Partners making these loans, Armstrong Energy granted it a series of options to acquire interests in the majority of coal reserves then held by us in Muhlenberg and Ohio Counties. On February 9, 2011, Armstrong Resources Partners exercised its options, paid Armstrong Energy an additional $5.0 million in cash and offset $12.0 million in accrued advance royalty payments owed by Armstrong Energy to Ceralvo Resources, LLC, and thereby acquired a 39.45% undivided interest as a joint tenant in common with Armstrong Energy’s subsidiaries in the aforementioned coal reserves. The aggregate amount paid by Armstrong Resource Partners to acquire its interest was the equivalent of approximately $69.5 million.
In December 2011, Armstrong Energy entered into a Membership Interest Purchase Agreement with Armstrong Resource Partners pursuant to which Armstrong Energy agreed to sell to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. In exchange for the agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners paid Armstrong Energy $20.0 million. In addition to the cash paid, certain amounts due by us to Armstrong Resource Partners totaling $5.7 million were forgiven by Armstrong Resource Partners, which resulted in aggregate consideration of $25.7 million. The partial undivided interest in additional reserves must be transferred to Armstrong Resource Partners within 90 days after delivery of the purchase price. This transaction, which closed on March 30, 2012, resulted in the transfer by us of an 11.36% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease.
In April 2013, pursuant to the Royalty Deferment and Option Agreement, Armstrong Energy sold to Armstrong Resource Partners, indirectly through contribution of a partial undivided interest in reserves to a limited liability company and transfer of our membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by Armstrong Energy. See “ - Royalty Deferment and Option Agreement.” In exchange for the agreement to sell a partial undivided interest in those reserves, Armstrong Resource Partners forgave certain amounts due by us to Armstrong Resource Partners, including cash royalty payments owed to Armstrong Resource Partners, offset by amounts due to us pursuant to the Administrative Services Agreement, totaling approximately $4.9 million. This transaction resulted in the transfer by us of a 2.59% undivided interest in certain of our land and mineral reserves to Armstrong Resource Partners. As a result of this transaction, Armstrong Resource Partners’ undivided interest in certain of our land and mineral reserves in Muhlenberg and Ohio Counties increased to 53.4%. Armstrong Resource Partners agreed to lease the newly transferred mineral reserves to us on the same terms as the February 2011 lease.
Lease Agreements
On February 9, 2011, Armstrong Energy’s subsidiary, Armstrong Coal, entered into a number of coal mining lease agreements with Western Mineral (a subsidiary of Armstrong Resource Partners) and two of
Armstrong Energy’s wholly-owned subsidiaries. Pursuant to these agreements, Western Mineral granted Armstrong Coal a lease to its 39.45% undivided interest in certain mining properties and a license to mine coal on those properties that it had acquired in the above-described option transaction. The initial term of the agreement is 10 years, and it renews for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. Armstrong Coal must pay the lessors a production royalty equal to 7% of the sales price of the coal it mines from the properties.
On February 9, 2011, Armstrong Coal also entered into a lease and sublease agreement with Ceralvo Holdings, LLC, a subsidiary of Armstrong Resource Partners (Ceralvo Holdings). Pursuant to this agreement, Ceralvo Holdings granted Armstrong Coal leases and subleases, as applicable, to the Elk Creek Reserves and an exclusive license to mine coal on those properties. The initial term of the agreement is 10 years, and it automatically renews for 10 one-year terms and thereafter until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it is terminated upon proper notice. Armstrong Coal must pay the lessor a production royalty equal to 7% of the sales price of the coal it mines from the properties. In addition, Armstrong Coal must pay any royalties due for coal leased (not owned in fee) by Ceralvo Holdings. As of December 31, 2013, Armstrong Energy has paid $12 million of advance royalties under the lease, of which the entire amount has been recouped against production royalties.
Royalty Deferment and Option Agreement
Effective February 9, 2011, Armstrong Coal, Western Diamond and Western Land, each of which is a wholly owned subsidiary of Armstrong Energy, entered into a Royalty Deferment and Option Agreement with Western Mineral and Ceralvo Holdings, both wholly owned subsidiaries of Armstrong Resource Partners. Pursuant to this agreement, Western Mineral and Ceralvo Holdings agreed to grant to Armstrong Coal and its affiliates the option to defer payment, in whole or in part, of their pro rata share of the 7% production royalty described above. In consideration for the granting of the option to defer these payments, Armstrong Coal and its affiliates granted to Western Mineral the option to acquire an additional undivided interest in certain of the coal reserves held by Armstrong Energy, Inc. in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which Armstrong Coal and its affiliates would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.
Since this agreement was executed in February 2011, Armstrong Energy and its subsidiaries have paid cash royalties to Armstrong Resource Partners totaling $1.1 million, but expects to defer any royalties earned in the foreseeable future. In addition, Armstrong Energy has transferred reserves with a total fair market value, at the time of transfer, of $10.6 million in lieu of paying cash royalties. During this period, Armstrong Resource Partners has also acquired additional reserves from the Company for cash of $20.0 million. If Armstrong Energy continues to satisfy its royalty obligations to Armstrong Resource Partners by additional transfers of coal reserves, Armstrong Energy expects that it will transfer all of its existing fee-owned reserves to Armstrong Resource Partners by 2018.
Administrative Services Agreement
Effective as of January 1, 2011, Armstrong Energy entered into an Administrative Services Agreement with Armstrong Resource Partners (f/k/a Elk Creek LP) and its general partner, Elk Creek GP, pursuant to which Armstrong Energy will provide Armstrong Resource Partners with general administrative and management services, including, but not limited to, human resources, information technology, financial and accounting services and legal services. The fees charged are subject to adjustment annually in accordance with the terms of the Administrative Services Agreement. For the years ended December 31, 2013, 2012, and 2011, the fees due to Armstrong Energy pursuant to the Administrative Services Agreement totaled $0.8 million, $0.8 million, and $0.7 million, respectively. Armstrong Resource Partners shall also be liable for all taxes that are applicable from time to time to the services Armstrong Energy provides on its behalf.
Investment in Ram Terminals, LLC
On May 26, 2011, Armstrong Energy made a capital contribution in Ram in the amount of $2.47 million. Upon amendment of the Limited Liability Company Agreement of Ram (the Operating Agreement) on July 2, 2012, Armstrong Energy’s equity interest in Ram constituted 5.0%. The remaining membership interest is owned by Yorktown Energy Partners IX, L.P., a fund managed by Yorktown. Armstrong Energy is majority-owned by Yorktown. Yorktown Energy Partners IX, L.P. will provide the funds for future capital expenditures related to the development of the site. Armstrong Energy will be involved in the initial design and construction of the terminal and will provide accounting and bookkeeping assistance to Ram. Pursuant to the Operating Agreement, Armstrong Energy will not be liable for the debts, liabilities and other obligations of Ram. On February 1, 2014, Ram became an indirect subsidiary of Thoroughbred Resources, LP through its parent company, Terminal Holdings, LLC and our ownership interest in Ram was converted into an equity interest in Thoroughbred Resources, LP (see “ - Merger of Related Parties”).
Western Diamond and Western Land Coal Reserves Sale Agreement
On October 11, 2011, two of our subsidiaries, Western Diamond and Western Land (together, the Sellers), entered into an agreement with Western Mineral, a subsidiary of Armstrong Resource Partners, pursuant to which the Sellers agreed to sell an additional partial undivided interest in substantially all of the coal reserves and real property owned by the Sellers previously subject to the options exercised by Armstrong Resource Partners on February 9, 2011 (see “ - Sale of Coal Reserves”), other than any of Sellers’ real property and related mining rights associated with the Parkway mine.
Thoroughbred Resources, LLC
On June 28, 2013, Thoroughbred, an entity wholly owned by Yorktown, acquired approximately 175 million tons of fee-owned coal reserves and 23 million tons of leased coal reserves from Peabody. The acquired coal reserves are located in Muhlenberg and McLean Counties of Kentucky, contiguous to Armstrong Energy’s reserves. In February 2014, we entered into a lease for these reserves in exchange for a production royalty.
In connection with Thoroughbred’s acquisition of these reserves, we loaned Thoroughbred $17.5 million, which was repaid in July 2013. The proceeds of the loan, which was evidenced by a promissory note, were used to make a portion of the down payment to Peabody for the reserves.
On February 1, 2014, Armstrong Resource Partners merged with and into Thoroughbred, with Armstrong Resource Partners as the surviving entity. Effective with the merger, Armstrong Resource Partners changed its name to Thoroughbred Resources, L.P. (see “ - Merger of Related Parties”).
Madisonville Office Lease
Beginning in 2008, pursuant to an oral agreement, Armstrong Coal leased from a then executive officer, and his spouse, certain property to be used by Armstrong Coal as its office space in Madisonville, Kentucky. Armstrong Coal agreed to pay $4,700 per month in exchange for the leased property, equipment, furniture, supplies and use of employees. On August 1, 2009, Armstrong Coal entered into a written lease agreement regarding the subject matter of the oral agreement. The terms of the written lease were the same as the terms of the prior oral agreement. The lease term ends on July 31, 2014, but automatically renews for additional 12-month periods unless either party gives written notice of termination no later than 30 days prior to the end of the term or a renewal term. Rent of $56,000, $61,000, and $56,000 were paid during the years ended December 31, 2013, 2012, and 2011, respectively.
Overriding Royalty Agreement
In 2006 and 2007, Armstrong Energy entered into overriding royalty agreements with a current and former executive employee to compensate them $0.05/ton of coal mined and sold from properties owned by certain subsidiaries of Armstrong Energy. 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. We account for these royalty arrangements as expense in the period in which the coal is sold. Expense recorded in the years ended December 31, 2013, 2012, and 2011, was $0.8 million, $0.7 million, and $0.7 million, respectively.
Agreement to Enter into Voting and Stockholders’ Agreement
On October 1, 2011, we entered into an agreement to enter into a voting and stockholders’ agreement with all of our stockholders. Pursuant to the terms of this agreement, as amended, we and our stockholders agreed to enter into a voting and stockholders’ agreement in the event that an underwritten offering to the public pursuant to which equity securities of the Company shall be authorized and approved for listing on NASDAQ is not completed on or before January 1, 2014; provided, however, that the deadline may be extended to a date mutually agreed upon by Yorktown and us, which in no event shall be later than July 1, 2014.
Merger of Related Parties
On February 1, 2014, Armstrong Resource Partners merged with and into Thoroughbred, with Armstrong Resource Partners as the surviving entity (the Merger). Effective with the Merger, Armstrong Resource Partners changed its name to Thoroughbred Resources, L.P. Our wholly-owned subsidiary, Elk Creek GP, 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, Elk Creek GP’s equity interest in the combined company was reduced to 0.2%.
Subsequent to the Merger, but also on February 1, 2014, Terminal Holdings, LLC, a holding company which is the sole member of both Ram and MG Midstreaming, LLC, merged with and into a merger subsidiary of Thoroughbred Resources, LP 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 interest in Ram, and by virtue of the merger, our equity interest in Ram (consisting of 24,700 membership units), was converted into an equal number of common units representing limited partnership interests in Thoroughbred Resources, LP. Because of our ownership of Thoroughbred Resources, LP through Elk Creek GP, the newly converted interest will be accounted for under the equity method.
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. During 2013, the conflicts committee reviewed and approved the sale of coal reserves to Armstrong Resource Partners in April 2013, the administrative services agreement in place for 2013, and the loan to Thoroughbred in July 2013. See Item 10 - “Directors, Executive Officers and Corporate Governance-Board of Directors and Brand Committees-Conflicts Committee” for a discussion of the responsibilities of the conflicts committee.
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 committee members satisfies NASDAQ’s additional conditions for independence for audit committee members.
Item 14.
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, 2013 and December 31, 2012 (in thousands):
(1) Includes fees associated with the annual audit of our consolidated financial statements, including quarterly review procedures, the issuance of their consent to include their audit opinion in registration statements filed with the SEC in 2013, and the deliverance of comfort letters in connection with the issuance of senior secured notes in December 2012.
(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.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this 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 through 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.
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 25, 2014.
ARMSTRONG ENERGY, INC.
By:
/s/ J. Richard Gist
J. Richard Gist
Senior Vice President, Finance and Administration and Chief Financial Officer
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints J. Hord Armstrong, III and Martin D. Wilson, and each of them, as his or her true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming that each of said attorneys-in-fact and agents or their substitutes or substitute, may lawfully do or cause to be done by virtue hereof.
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 25, 2014.
Signature
Title
/s/ J. Hord Armstrong, III
J. Hord Armstrong, III
Chairman and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin D. Wilson
Martin D. Wilson
President and Director
/s/ J. Richard Gist
J. Richard Gist
Senior Vice President, Finance and Administration and Chief Financial Officer
(Principal Financial and Accounting Officer)
/s/ Anson M. Beard, Jr.
Anson M. Beard, Jr.
Director
/s/ James C. Crain
James C. Crain
Director
/s/ Richard F. Ford
Richard F. Ford
Director
/s/ Bryan H. Lawrence
Bryan H. Lawrence
Director
/s/ Greg A. Walker
Greg A. Walker
Director
INDEX TO EXHIBITS
 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.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Armstrong Energy, Inc. and Subsidiaries (formerly
Armstrong Land Company, LLC and Subsidiaries)
We have audited the accompanying consolidated balance sheets of Armstrong Energy, Inc. and Subsidiaries (formerly Armstrong Land Company, LLC and Subsidiaries) (the Company) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
St. Louis, Missouri
March 25, 2014
Armstrong Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
Armstrong Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
Armstrong Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
Armstrong Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Amounts in thousands)
See accompanying notes to consolidated financial statements.
Armstrong Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
See accompanying notes to consolidated financial statements.
Armstrong Energy, Inc. and Subsidiaries
(formerly Armstrong Land Company, LLC and Subsidiaries)
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share amounts)
1. DESCRIPTION OF BUSINESS AND ENTITY STRUCTURE
Armstrong Energy, Inc. (formerly Armstrong Land Company, LLC) (AE) and subsidiaries (collectively, the Company) commenced business on September 19, 2006 (inception), for the purpose of owning and operating coal reserves (also referred to as mineral rights) and production assets. As of December 31, 2013, all subsidiaries are majority owned. The Company is a diversified producer of low chlorine, high sulfur thermal coal from the Illinois Basin, operating both surface and underground mines. The Company is majority owned by investment funds managed by Yorktown Partners LLC (Yorktown). AE, which is headquartered in St. Louis, Missouri, markets its coal primarily to electric utility companies as fuel for their steam-powered generators. As of December 31, 2013, the Company had approximately 1,046 employees, none of whom are under a collective bargain arrangement.
In August 2011, Armstrong Resources Holdings, LLC merged with and into Armstrong Energy, Inc., which subsequently changed its name to Armstrong Energy Holdings, Inc., a wholly owned subsidiary of Armstrong Land Company, LLC (ALC). Subsequently, ALC adopted a Plan of Conversion (the Plan), which resulted in ALC being converted to a C-corporation named Armstrong Land Company, Inc. (ALCI) effective October 1, 2011. Also, effective October 1, 2011, the Plan authorized the conversion of each issued and outstanding membership unit of ALC into 9.25 shares of common stock of AE. Concurrent with the effectiveness of the Plan, ALCI changed its name to Armstrong Energy, Inc. (collectively, the Reorganization).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Factors Affecting Comparability
Certain prior year amounts have been reclassified to conform to current year presentation, with no effect on the previously reported results of operations. In addition, the reclassifications were not material to the accompanying footnotes to the prior year consolidated financial statements.
Principles of Consolidation
The consolidated financial statements include the accounts of AE and its wholly and majority-owned subsidiaries. All significant intercompany balances and transactions were eliminated.
Prior to September 30, 2011, the Company consolidated the results of Armstrong Resource Partners, L.P. and its subsidiaries (ARP), which were not majority owned, in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810-20, Consolidation-Control of Partnerships and Similar Entities. As of December 31, 2013, the Company’s wholly-owned subsidiary, Elk Creek General Partner (ECGP), has an approximate 0.4% ownership in ARP. Beginning in the fourth quarter of 2011, the Company concluded it no longer has control of ARP. Accordingly, it ceased consolidating the results of operations and financial position of ARP and started accounting for its investment in ARP under the equity method of accounting (See Note 3). Therefore, the users of the Company’s consolidated financial statements should consider the effect of deconsolidation when comparing 2013 and 2012 to prior periods.
Newly Adopted Accounting Standards
In February 2013, the FASB issued an amendment to the accounting guidance for the reporting of amounts reclassified out of accumulated other comprehensive income (AOCI). The amendment expands the existing
disclosure by requiring entities to present information about significant items reclassified out of AOCI by component. In addition, an entity is required to provide information about the effects on net income (loss) of significant amounts reclassified out of each component of AOCI to net income (loss) either on the face of the statement where net income (loss) is presented or as a separate disclosure in the notes of the financial statements. The amendment is effective prospectively for annual or interim reporting periods beginning after December 15, 2012. The adoption of this accounting pronouncement did not have a material impact on our financial statement disclosures. See Note 21 for additional information regarding AOCI.
Use of Estimates
The preparation of consolidated financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of income and loss during the reporting periods. Actual results could differ from those estimates.
Revenue
Coal sales are recognized as revenue when title and risk of loss passes to the customer. Coal sales are made to customers under the terms of supply agreements, most of which are long-term (greater than one year). Under the terms of the Company’s coal supply agreements, title and risk of loss typically transfer to the customer at the mine where coal is loaded on the truck, rail, or barge. Coal sales include the freight charged to the customer on destination contracts.
Other Income (Expense), net
Other income includes farm income, timber income, and other income from the lease of surface property. For the year ended December 31, 2012, other income (expense), net also includes charges of $1,409 for a loss on the settlement of the interest rate swap (see Note 16) and $1,130 for a loss on the deferment of an equity offering. The Company had deferred costs related to amounts incurred on a proposed equity offering. As the offering was delayed for an extended period of time, a charge was recognized in the fourth quarter of 2012 to write-off all deferred amounts associated with the equity offering.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. The Company considers all cash and temporary investments having an original maturity of less than three months to be cash equivalents.
Accounts and Other Receivables
Accounts receivable are recorded at the invoiced amount and do not bear interest. The Company evaluates the need for an allowance for doubtful accounts based on anticipated recovery and industry data. As of December 31, 2013 and 2012, the Company had not established an allowance for accounts receivable.
Inventories
Inventories consist of coal, as well as materials and supplies that are valued at the lower of cost or market. Raw coal stockpiles may be sold in their current condition or processed further prior to shipment. Cost is determined using the first-in, first-out method for materials and supplies. Coal inventory costs include labor, supplies, equipment cost, royalties, taxes, other related costs, and, where applicable, preparation plant costs. Stripping costs incurred during the production phase of the mine are considered variable production costs and are included in the cost of coal during the period the stripping costs are incurred.
Property, Plant, Equipment, and Mine Development
Property, plant, and equipment are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2013, 2012, and 2011 was $1,641, $1,179, and $1,545, respectively.
Expenditures that extend the useful lives of existing plant and equipment assets are capitalized, while normal repairs and maintenance that do not extend the useful life or increase the productivity of the asset are expensed as incurred. Plant and equipment are depreciated using the straight-line method over the useful lives of the assets, which are detailed below.
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 2013, 2012, or 2011. 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 18 for further details of royalty agreements.
Also included within other non-current assets are deferred financing costs, which are subject to amortization over the term of the associated debt obligation using the effective interest method.
Investments
Investments and ownership interests are accounted for under the equity method of accounting if the Company has the ability to exercise significant influence, but not control, over the entity. If the Company does not have control and cannot exercise significant influence, the investment is accounted for using the cost method.
Long-Lived Assets
If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates the carrying value of the asset will not be recovered, as determined based on projected undiscounted cash flows related to the asset over its remaining life, the carrying value of the asset is reduced to its estimated fair value through an impairment loss. No impairment losses were recognized during the years ended December 31, 2013, 2012, or 2011.
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 historically has used derivatives only to hedge the variable cash flows of future interest payments on long-term debt. To the extent a derivative qualifies as a cash flow hedge, the gain or loss associated with the effective portion is recorded as a component of Accumulated Other Comprehensive Income (Loss). Changes in the fair value of derivatives that do not meet the criteria for hedge accounting would be recognized in the consolidated statements of operations. When an interest rate swap agreement terminates, any resulting gain or loss is recognized over the shorter of the remaining original term of the hedging instrument or the remaining life of the underlying debt obligation.
Income Taxes
The Company is subject to taxation. Deferred income taxes are recorded by applying statutory tax rates in effect at the date of the balance sheet to differences between the income tax bases of assets and liabilities and
their carrying amounts for financial reporting purposes. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining whether a valuation allowance is appropriate, projected realization of tax benefits is considered based on expected levels of future taxable income, available tax planning strategies, and the overall deferred tax position. If actual results differ from the assumptions made in the evaluation of the amount of the valuation allowance, the Company records a change in the valuation allowance through income tax expense in the period such determination is made. Certain subsidiaries are disregarded for income tax purposes and are included in each respective parent entity’s tax returns.
The calculations of the Company’s tax liabilities involve dealing with uncertainties in the application of complex tax regulations. The Company recognizes liabilities for uncertain tax positions based on the two-step process prescribed in ASC 740, Income Taxes. The first step is to evaluate the tax position for recognition by determining whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The second step requires the Company to estimate and measure the tax benefit as the largest amount that is more than 50% likely to be realized upon settlement. The Company re-evaluates these uncertain tax positions annually. This evaluation is based on factors including, but not limited to, changes in facts or circumstances, changes in tax law, effectively settled issues under audit, or new audit activity. Such a change in recognition or measurement results in the recognition of a tax benefit or an additional charge to the tax provision.
Long-Term Obligation to Related Party
The Company has entered into certain transactions with its affiliate, ARP, 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 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 ARP.
Benefit Plans
Effective January 1, 2013, the Company began providing certain health care benefits, including the reimbursement of a portion of out-of-pocket costs associated with insurance coverage, to qualifying salaried and hourly retirees and their dependents. The cost of providing these benefits is determined on an actuarial basis and accrued over the employee’s period of active service.
The Company recognizes the underfunded status of this plan, as determined on an actuarial basis, on the balance sheet and the changes in the funded status are recognized in other comprehensive (loss) income. See Note 22 for additional disclosures relating to these obligations.
Workers’ Compensation and Black Lung
The Company has no liabilities under state statutes or the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees, former employees and their dependents. Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must pay federal black lung benefits to claimants who are current and former employees and also make payments to a trust fund for the payment of benefits and medical expenses to eligible claimants who last worked in the coal industry prior to January 1, 1970. The trust fund is funded by an excise tax on production. For the years ended December 31, 2013, 2012, and 2011, the Company recorded $7,277, $6,411, and $4,945, respectively, of expense related to this excise tax.
With regard to workers’ compensation, the Company provides benefits to its employees by being insured through an insurance carrier. Premium expense for workers’ compensation benefits is recognized in the period in which the related insurance coverage is provided.
Investment Credits
For establishing operations in Ohio County, Kentucky, the Company qualified for investment credits totaling $16,000 recoverable from the State of Kentucky to be applied against certain state income and employee payroll taxes paid. Investment credits, which expire in 2021, are accounted for using the deferral method. During the years ended December 31, 2013 and 2012, the Company recognized $2,174 and $2,417, respectively, in investment credits, which were applied against certain employee payroll taxes in the statement of operations. As of December 31, 2013 and 2012, the Company had $9,386 and $13,583, respectively, in investment credit carryforwards available.
Equity Awards
The Company accounts for common stock (and previously, members’ equity units) paid with a note and issued to employees as compensation expense. Amounts are recorded at fair market value. The Company used the Black-Scholes option model in estimating the fair value of awards. Compensation expense is measured on the grant date and recognized over the implied vesting period.
The Company accounts for share-based compensation at the grant date fair value of awards and recognizes the related expense over the vesting period of the award.
3. DECONSOLIDATION OF ARMSTRONG RESOURCE PARTNERS
Through September 30, 2011, the Company consolidated the results of ARP in accordance with ASC 810-20, as ECGP was presumed to control the partnership. On October 1, 2011, the partners of ARP entered into the Amended and Restated Agreement of Limited Partnership of Armstrong Resource Partners, L.P. (the ARP LPA). Pursuant to the ARP LPA, effective October 1, 2011, Yorktown, ARP’s largest unit holder, unilaterally may remove the Company’s subsidiary, ECGP, as general partner of ARP or otherwise cause a change of control of ARP without the Company’s consent or the consent of the holders of ARP’s equity units. As a result of the loss of control of ARP by ECGP, the Company no longer consolidates the results of operations of ARP effective October 1, 2011 and accounts for its ownership in ARP under the equity method of accounting. Under the deconsolidation accounting guidelines, the investor’s opening investment was recorded at fair value as of the date of deconsolidation. The difference between this initial fair value of the investment and the net carrying value was recognized as a gain or loss in earnings.
In order to determine the fair value of its initial investment in ARP, the Company completed a valuation analysis based on the income approach using the discounted cash flow method. The discount rate, long-term growth rate, and profitability assumptions are material inputs utilized in the discounted cash flow model. Based on the results of this valuation, the deconsolidation date fair value of the Company’s investment in ARP was determined to be $716. The Company recognized a non-cash gain included as a component of other income (expense), net of approximately $311 in the year ended December 31, 2011 related to the deconsolidation of ARP.
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 10 years, provided mining of the reserve commenced within the first 10 years of the agreement.
On December 29, 2011, the Company entered into a transaction in which it acquired additional property and mineral interests contiguous to its existing and planned mines. The rights and interests in certain owned and leased coal reserves located in Muhlenberg County, Kentucky, were acquired in exchange for: (i) a cash payment by the Company of approximately $8,871, (ii) a promissory note due June 30, 2012 in the aggregate principal amount of approximately $4,435, and (iii) an overriding royalty to the seller to the extent the Company mines in excess of certain tonnages from the property, as set forth in the purchase agreement. The Company also acquired certain reserves and entered into a lease allowing it the right to mine certain additional reserves in Union County, Kentucky. In consideration of the sale and lease of real property, the Company agreed to deliver (i) approximately $6,007 in cash, (ii) a promissory note due June 30, 2012 in the aggregate principal amount of approximately $3,004, and (iii) an overriding royalty of 2% of the gross selling price on each ton of coal produced and sold from the coal reserves that were purchased (thus excluding the leased coal). The cash utilized for the acquisition was obtained from ARP in exchange for an additional undivided interest in certain land and mineral reserves of the Company (see Note 13). Both promissory notes were repaid during 2012 on their maturity dates.
5. INVENTORIES
Inventories consist of the following amounts as of December 31, 2013 and 2012:
6. PROPERTY, PLANT, EQUIPMENT, AND MINE DEVELOPMENT
Property, plant, equipment, and mine development consist of the following as of December 31, 2013 and 2012:
Depreciation expense, including amounts from capitalized leases, for the years ended December 31, 2013, 2012, and 2011, was $26,426, $22,936, and $17,345, respectively. For the years ended December 31, 2013, 2012, and 2011, depletion expense related to mineral rights amounted to $7,290, $7,133, and $6,343, respectively; amortization expense related to mine development costs amounted to $4,075, $2,265, and $3,241, respectively; and depreciation expense related to the ARO assets amounted to $596, $2,304, and $2,157, 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 15), as well as under certain capital lease obligations.
The Company had outstanding construction commitments as of December 31, 2013, of approximately $707. All construction commitments are expected to be completed within the next fiscal year.
7. INTANGIBLE ASSETS
Intangible assets consist of mine plans and permits acquired in certain property acquisitions, as well as a non-compete agreement entered into in conjunction with the acquisition of a minority stockholder’s interest and settlement of litigation. Mine plans and permits are being amortized over five years beginning in the year that mining operations commence on the associated area. The non-compete agreement is being amortized, using the straight-line method, over the five-year term of the agreement. Intangible assets consist of the following as of December 31, 2013 and 2012:
Amortization expense related to intangible assets amounted to $428, $732, and $732 for the years ended December 31, 2013, 2012, and 2011, respectively. The weighted average remaining period over which intangible assets are being amortized is 5.7 years. The estimated future amortization expense is as follows:
8. INVESTMENTS
RAM Terminals, LLC
On June 1, 2011, the Company entered into an agreement to acquire an equity interest in Ram Terminals, LLC (RAM) for $2,470. RAM, whose controlling unitholder is Yorktown, owns approximately 600 acres of Mississippi River front property south of New Orleans and intends to permit, design and construct a seaborne coal export terminal with an annual through-put capacity of up to 10 million tons. The Company has the option to make additional contributions to RAM, but it is expected all future expenditures will be funded by Yorktown and its affiliates and therefore the Company’s equity interest will be significantly reduced in the future. As of December 31, 2013, the Company had an equity interest in RAM of approximately 5.0%. Effective January 1, 2012, the Company and RAM entered into a services agreement, whereby the Company will provide administrative and management services to RAM. In consideration for the services provided, RAM paid the Company $131 and $252 for the years ended December 31, 2013 and 2012, respectively. Because of the Company’s limited influence over the investment and future dilution of ownership interest, the cost method is used to account for this investment. It is not practicable to estimate the fair value of this investment. In addition, the Company did not evaluate the investment for impairment as no factors indicating impairment existed during the year. On February 1, 2014, RAM became an indirect subsidiary of Thoroughbred Resources, LP through its parent company, Terminal Holdings, LLC and the Company’s ownership interest in RAM was converted into an equity interest in Thoroughbred Resources, LP (see Note 13).
9. OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following as of December 31, 2013 and 2012:
10. ACCRUED AND OTHER LIABILITIES
Accrued and other liabilities consist of the following amounts as of December 31, 2013 and 2012:
11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company measures the fair value of assets and liabilities using a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: Level 1-observable inputs such as quoted prices in active markets; Level 2-inputs, other than quoted market prices in active markets, which are observable, either directly or indirectly; and Level 3-valuations derived from valuation techniques in which one or more significant inputs are unobservable. In addition, the Company may use various valuation techniques including the market approach, using comparable market prices; the income approach, using present value of future income or cash flow; and the cost approach, using the replacement cost of assets.
The Company’s financial instruments consist of cash equivalents, accounts receivable, long-term debt, and other long-term obligations. For cash equivalents, accounts receivable and other long-term obligations, the carrying amounts approximate fair value due to the short maturity and financial nature of the balances. The estimated fair market values of the Company’s Notes, which was determined using level 2 inputs, and long-term obligation to related party, which was determined using level 3 inputs, are as follows:
(1) The carrying value of the Notes is net of the unamortized original issue discount as of December 31, 2013 and 2012.
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.
12. RISKS AND CONCENTRATIONS
Geographical Concentration
The Company’s operations are concentrated in western Kentucky, and a disruption within that geographic region could adversely affect the Company’s performance.
Customer Concentration
The Company has multi-year coal supply agreements with multiple customers. The top two customers accounted for approximately 42% and 34%, respectively, of net sales for the year ended December 31, 2013. 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.
13. RELATED-PARTY TRANSACTIONS
Sale of Coal Reserves
Between 2009 and 2010, AE entered into a series of promissory notes with ARP (ARP promissory notes) whereby ARP loaned $44,100 to AE for the sole purpose of making the scheduled payments under the secured debt agreements outstanding with various third parties existing at December 31, 2010 (secured promissory notes). The ARP promissory notes contained an option, whereby, ARP, in lieu of payment of the outstanding amounts of principal and interest, could obtain an interest in the mineral reserves of the Company equal to the percentage of the aggregate amount of principal loaned and related accrued interest to the amount paid by the Company to repay or repurchase and retire the ARP promissory notes. This option could only be exercised if all secured promissory notes are repaid in full.
The secured promissory notes were repaid in full on February 9, 2011, which resulted in ARP exercising its option to convert the ARP promissory notes to a 39.45% undivided interest in its land and mineral reserves, excluding the reserves in Union and Webster Counties. Outstanding principal and interest of the ARP promissory notes totaled $46,620 as of February 9, 2011. As additional consideration for the land and mineral reserves transferred, ARP paid $5,000 cash and certain amounts due ARP totaling $17,871 were forgiven, resulting in aggregate consideration of $69,491. Simultaneous with this transaction, the Company entered into a lease agreement with a subsidiary of ARP, under mutually agreeable terms and conditions, to mine the acquired mineral reserves. The lease is for a term of 10 years and can be extended for additional periods until all the respective merchantable and mineable coal is removed. Due to the Company’s continuing involvement in the land and mineral reserves transferred, this transaction has been accounted for as a financing arrangement. A long-term obligation has been established that will be amortized over a 20 year period, or the estimated life of the mineral reserves, at an annual rate of 7% of the estimated gross revenue generated from the sale of the coal originating from the leased mineral reserves. Based on the Company’s estimates, the effective interest rate of the obligation was 12.5% at the time of the transaction, which is adjusted prospectively based on changes to the mine plan. As the financial results of ARP had been consolidated in accordance with ASC 810-20 prior to the deconsolidation, which was effective October 1, 2011, this transaction did not have an impact on the consolidated results of operations or financial condition of the Company for the nine months ended September 30, 2011. Subsequent to the deconsolidation, the long-term obligation to ARP and associated interest expense are reflected in the accompanying consolidated financial statements of the Company.
On February 9, 2011, the Company entered into a series of lease agreement with certain subsidiaries of ARP, pursuant to which ARP granted the Company a lease to its 39.45% undivided interest in certain mining properties, as well as certain wholly-owned reserves (Elk Creek Reserves), and licenses to mine coal on those properties. The initial term of the agreements is ten years, and they renew for subsequent one-year terms until all mineable and merchantable coal has been mined from the properties, unless either party elects not to renew or it
is terminated upon proper notice. The Company must pay ARP a production royalty equal to 7% of the sales price of the coal it mines from the properties. The Company paid $12,000 of advance royalties under the lease of the Elk Creek Reserves, which are recoupable against production royalties. Mining of the Elk Creek Reserves began in 2011. As of December 31, 2013, the advance royalty has been fully recouped against production royalties, while the advance royalty to be recouped totaled $5,683 as of December 31, 2012.
Effective February 9, 2011, the Company entered into a Royalty Deferment and Option Agreement with certain subsidiaries of ARP, pursuant to which ARP agreed to grant the Company the option to defer payment of their pro rata share of the 7% production royalty described above. In consideration for the granting of the option to defer these payments, the Company granted to ARP the option to acquire an additional undivided interest in certain of its coal reserves in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which the Company would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves at fair market value for such reserves determined at the time of the exercise of such options.
On October 11, 2011, the Company and its wholly owned subsidiaries, Western Diamond and Western Land, entered into a Royalty Deferment and Option Agreement with certain wholly owned subsidiaries of ARP, Western Mineral Holdings, LLC (WMD) and Ceralvo Holdings, LLC (CVH). Pursuant to this agreement, WMD and CVH agreed to grant the Company and its affiliates the option to defer payment of their pro rata share of the 7% production royalty earned on the 39.45% undivided interest in mineral reserves acquired. In consideration for the granting of the option to defer these payments, the Company and its affiliates granted to WMD the option to acquire an additional partial undivided interest in certain of the mineral reserves held by the Company in Muhlenberg and Ohio Counties by engaging in a financing arrangement, under which it would satisfy payment of any deferred fees by selling part of their interest in the aforementioned coal reserves. The Royalty Deferment and Option Agreement was effective as of February 9, 2011.
On December 29, 2011, the Company entered into a Membership Interest Purchase Agreement with ARP pursuant to which the Company agreed to sell to ARP, indirectly through contribution of a partial undivided interest in certain land and mineral reserves to a limited liability company and transfer of the Company’s membership interests in such limited liability company, an additional partial undivided interest in reserves controlled by the Company. In exchange for the Company’s agreement to sell a partial undivided interest in those reserves, ARP paid the Company $20,000. In addition to the cash paid, certain amounts due ARP totaling $5,700 were forgiven, which resulted in aggregate consideration of $25,700. This transaction closed on March 30, 2012, whereby the Company transferred an 11.36% undivided interest in certain of its land and mineral reserves to ARP. The newly transferred mineral reserves were leased back to the Company under the agreement entered into in February 2011 at the same terms. In addition, production royalties earned by ARP from the newly transferred mineral reserves are being deferred under the Royalty Deferment and Option Agreement. Due to the Company’s continuing involvement in the mineral reserves, this transaction is accounted for as an additional financing arrangement and an additional long-term obligation to ARP of $25,700 was recognized in the first quarter of 2012. The effective interest rate of the obligation, adjusted for the additional transfer of land and mineral reserves and updated for the current mine plan, is 10.67%. The cash proceeds from ARP were used to acquire additional land and mineral reserves from a third party in December 2011, as well as for other working capital needs.
On March 21, 2013, the Company agreed to sell an additional 2.59% undivided interest in certain land and mineral reserves to ARP. The percentage interest in the land and mineral reserves sold was based on a fair value determined by a third-party specialist. In exchange for the undivided interest in the land and mineral reserves, ARP forgave amounts owed by the Company totaling $4,886. This transaction closed on April 1, 2013 whereby ARP’s undivided interest in certain of the Company’s land and mineral reserves in Muhlenberg and Ohio Counties increased to 53.4%. In addition, the transferred mineral reserves were leased back to the Company on terms similar to those applicable to the previous transfers. As the Company will have a continuing involvement in the reserves, the transaction is accounted for as a financing arrangement and an additional long-term obligation to ARP of $4,886 was recognized in the second quarter of 2013. As a result of the additional asset transfer, the
effective interest rate on the long-term obligation to related party was adjusted to 10.65%. As of December 31, 2013 and 2012, the outstanding long-term obligation to related party totaled $106,283 and $98,388, respectively. Interest expense recognized for the years ended December 31, 2013, 2012, and 2011 associated with the long-term obligation to related party was $11,029, $9,257, and $2,495, respectively. Based on the current mine plan, the effective interest rate of the obligation was adjusted to 7.0% as of December 31, 2013.
Based on the current mine plan and estimated selling prices of the coal, estimated payments under the obligation are as follows:
Administrative Services Agreement
Effective as of January 1, 2011, the Company entered into an Administrative Services Agreement with ARP and its general partner, ECGP, pursuant to which the Company agreed to provide ARP with general administrative and management services, including, but not limited to, human resources, information technology, financial and accounting services and legal services. As consideration for the use of the Company’s employees and services, and for certain shared fixed costs, ARP paid the Company $775, $750, and $720 for the years ended December 31, 2013, 2012, and 2011, respectively.
Credit Support Fee
ARP was a co-borrower under the Company’s former 2011 Credit Facility-Term Loan and guarantor on both the 2011 Credit Facility-Revolving Credit Facility and the 2011 Credit Facility-Term Loan, and substantially all of its assets were pledged as collateral. ARP received, as compensation for these restrictions, a fee of 1% of the weighted-average outstanding balance under the 2011 Credit Facility, which totaled $1,183, and $1,150 for the years ended December 31, 2012 and 2011, respectively. This arrangement ended in December 2012 upon the termination of the 2011 Credit Facility (see Note 15).
Short-term Note Receivable
On June 28, 2013, Thoroughbred Resources, LLC (Thoroughbred), an entity wholly-owned by investment funds managed by Yorktown, acquired approximately 175 million tons of fee-owned coal reserves and approximately 23 million tons of leased coal reserves from Peabody. The acquired coal reserves are located in Muhlenberg and McLean Counties of Kentucky, contiguous to the Company’s reserves. In February 2014, the Company entered into a lease of these reserves in exchange for a production royalty.
In connection with Thoroughbred’s acquisition of these coal reserves, the Company loaned Thoroughbred $17,500, which was repaid in July 2013. The proceeds of the loan, which was evidenced by a promissory note, were used by Thoroughbred to make a portion of the down payment to Peabody for the purchase of the coal reserves.
Merger of Related Parties
On February 1, 2014, Armstrong Resource Partners merged with and into Thoroughbred, with Armstrong Resource Partners as the surviving entity (the Merger). Effective with the Merger, Armstrong Resource Partners
changed its name to Thoroughbred Resources, L.P. The Company’s wholly-owned subsidiary, Elk Creek GP, LLC, 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, Elk Creek GP’s equity interest in the combined company was reduced to 0.2%.
Subsequent to the Merger, but also on February 1, 2014, Terminal Holdings, LLC, a holding company which is the sole member of both Ram and MG Midstreaming, LLC, merged with and into a merger subsidiary of Thoroughbred Resources, LP 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 our prior interest in Ram, and by virtue of the merger, the Company’s equity interest in Ram (consisting of 24,700 membership units), was converted into an equal number of common units representing limited partnership interests in Thoroughbred Resources, LP. Because of the Company’s ownership of Thoroughbred Resources, LP through Elk Creek GP, the newly converted interest will be accounted for under the equity method (see Note 8).
Other
The Company rented office space from a former key executive employee of the Company. Expenses of $56, $61, and $56 were paid during the years ended December 31, 2013, 2012, and 2011, respectively.
In 2006 and 2007, the Company entered into overriding royalty agreements with a current and a former executive employee to compensate them $0.05/ton of coal mined and sold from properties owned by certain subsidiaries of the Company. The agreements remain in effect for the later of 20 years from the date of the agreement or until all salable coal has been extracted. Both royalty agreements transfer with the property regardless of ownership or lease status. The royalties are payable the month following the sale of coal mined from the specified properties. The Company accounts for these royalty arrangements as expense in the period in which the coal is sold. Expense recorded in the years ended December 31, 2013, 2012, and 2011, was $811, $748, and $684, respectively.
14. ACQUISITION OF NON-CONTROLLING INTEREST
Prior to the Reorganization in August 2011, the Company acquired all of the outstanding common stock held by certain third parties in the former Armstrong Energy, Inc. and Armstrong Resources Holdings, LLC. A portion of the outstanding shares were acquired in exchange for membership interests in ALC, which totaled 7,957.5 units of membership interest (73,606 shares of common stock of AE). In addition, the Company had outstanding non-recourse promissory notes with these third parties related to a portion of their original purchase of shares in the former Armstrong Energy, Inc. in December 2006 and March 2007. The non-recourse notes, including all accrued and unpaid interest, were repaid in full through the payment of cash of $125 and the sale of their remaining shares in the former Armstrong Energy, Inc. to the Company. Simultaneous with the above, the Company sold 4,520 units of membership interest in ALC (41,810 shares of common stock of AE) to these third party investors financed with new non-recourse promissory notes due 2015 totaling $452, which are not recorded within the consolidated balance sheet as these notes are non-recourse. Each of the promissory notes carries a stated interest rate of 6% per annum and are collateralized by the unpaid ownership interest. No portions of the promissory notes are subject to release until full payment has been tendered on the applicable note. In the event of default, the notes shall bear interest at 12% per annum.
The units purchased with non-recourse notes are accounted for as options. As the options were fully vested at the date of issuance, the Company recognized a non-cash charge included as a component of other income (expense), net within the results of operations for the year ended December 31, 2011 of $217, which represents
the total fair value of the options awarded. The assumptions used in determining the grant date fair value of $5.19 per share, using a Black-Scholes option pricing model, were as follows:
15. LONG-TERM DEBT
The Company’s total indebtedness as of December 31, 2013 and 2012 consisted of the following:
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, 2013 and 2012, the unamortized OID was $6,183 and $6,848, 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 twelve months commencing on December 15, 2016 at 105.875% of the principal amount redeemed, at any time during the twelve months commencing December 15, 2017 at 102.938% of the principal amount redeemed, and at any time after December 15, 2018 at 100.000% of the principal amount redeemed, in each case plus accrued and unpaid interest to the applicable redemption date. In addition, at any time prior to December 15, 2015, the Company may redeem Notes with the net cash proceeds received from one or more Equity Offerings (as defined in the indenture governing the Notes) at a redemption price equal to 111.75% of the principal amount redeemed plus accrued and unpaid interest to the applicable redemption date, in an aggregate principal amount for all such redemptions not to exceed 35% of the original aggregate principal amount of the Notes.
Upon the occurrence of an event of a Change in Control (as defined in the indenture governing the Notes), unless the Company has exercised its right to redeem the Notes, the Company will be required to make an offer to purchase the Notes at a redemption price of 101.000%, plus accrued and unpaid interest to the date of repurchase.
Subject to certain customary release provisions, the Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by the Company and substantially all of its current and future domestic restricted subsidiaries (as defined). They are also secured, subject to certain exceptions and permitted liens, on a first-priority basis by substantially all of the assets of the Company and the guarantors’ that do not secure the 2012 Credit Facility (see below) on a first-priority basis. Subject to certain exceptions and permitted liens, the Notes are also secured on a second-priority basis by a lien on the assets securing the Company’s obligations under the 2012 Credit Facility on a first-priority basis.
The indenture governing the Notes contains restrictive covenants which, among other things, limit the ability (subject to exceptions) of the Company and its restricted subsidiaries (as defined) to: (a) incur additional indebtedness or issue preferred equity; (b) pay dividends or distributions on or purchase the Company’s stock or the Company’s restricted subsidiaries’ stock; (c) make certain investments; (d) use assets as security in other transactions; (e) create guarantees of indebtedness by restricted subsidiaries; (f) enter into agreements that restrict dividends, distributions, or other payment by restricted subsidiaries; (g) sell certain assets or merge with or into other companies; and (h) enter into transactions with affiliates.
The Company and the guarantor subsidiaries entered into a registration rights agreement (the Registration Rights Agreement) in connection with the issuance and sale of the Notes. Pursuant to the Registration Rights Agreement, the Company and the guarantor subsidiaries agreed to file a registration statement with the Securities and Exchange Commission to register an exchange offer pursuant to which the Company will offer to exchange a like aggregate principal amount of senior notes identical in all material respects to the Notes, except for terms relating to transfer restrictions, for any or all of the outstanding Notes. The exchange offer was completed in November 2013.
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, 2013 and 2012, there were no borrowings outstanding under the 2012 Credit Facility and the Company had $19,258 and $20,000, 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 2012 Credit Facility also contains customary affirmative covenants and events of default. If an event of default occurs, the lenders under the 2012 Credit Facility will be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.
Prepayments and Commitment Reductions
Voluntary prepayments and commitment reductions will be permitted, in whole or in part, in minimum amounts without premium or penalty, other than customary breakage costs with respect to LIBOR loans.
2011 Credit Facility
On February 9, 2011, the Company entered into a senior secured credit facility (the 2011 Credit Facility), which was comprised of a $100,000 term loan (2011 Credit Facility-Term Loan) and a $50,000 revolving credit facility (2011 Credit Facility-Revolving Credit Facility). The 2011 Credit Facility-Term Loan was a five-year term loan that required principal payments in the amount of $5,000 on the first day of each quarter commencing on January 1, 2012 through January 1, 2016, with the remaining outstanding principal and interest balance due upon maturity on February 9, 2016. On December 21, 2012, in connection with the Notes offering, the Company voluntarily prepaid and terminated the 2011 Credit Facility, and repaid all outstanding amounts under the agreement. As a result of the prepayment and termination of the 2011 Credit Facility, the Company recognized a loss on extinguishment of debt of $3,953 in connection with the write-off of related unamortized deferred financing costs.
Proceeds from the 2011 Credit Facility-Term Loan and borrowings under the 2011 Credit Facility-Revolving Credit Facility were used to repay the principal and interest balance of certain outstanding secured promissory notes during 2011. As a result of the repayment of these obligations, the Company recognized a gain on extinguishment of debt of $6,954 during the year ended December 31, 2011.
Maturities of Long-Term Debt
The aggregate amounts of long-term debt maturities subsequent to December 31, 2013 were as follows:
16. DERIVATIVES
In February 2011, in order to manage the risk associated with changes in interest rates related to the 2011 Credit Facility-Term Loan, the Company entered into an interest rate swap agreement that effectively converted a portion of its floating-rate debt to a fixed-rate basis, thereby reducing the impact of interest rate changes on future cash interest payments beginning January 1, 2012. The swap was designated as a cash flow hedge of expected future interest payments and measured at fair value on a recurring basis. In connection with the
prepayment and termination of the 2011 Credit Facility, the Company terminated the outstanding interest rate swap in December 2012. Accordingly, the Company reclassified $1,409, net of tax of zero, from accumulated other comprehensive income (loss) and recognized a loss on settlement of the swap, which was included as a component of other income (expense), net in the consolidated statement of operations for the year ended December 31, 2012.
The Company utilizes the best available information in measuring fair value. The interest rate swap was historically valued based on quoted data from the counterparty, corroborated with indirectly observable market data, which, combined, were deemed to be a Level 2 input in the fair value hierarchy. No ineffectiveness was recorded in the consolidated statement of operations during the years ended December 31, 2012 and 2011, respectively. In addition, during the years ended December 31, 2012 and 2011, $811 and zero, respectively, were reclassified from accumulated other comprehensive income (loss) to interest expense related to the effective portion of the interest rate swap.
17. LEASE OBLIGATIONS
The Company leases equipment and facilities directly under various non-cancelable lease agreements. Certain leases contain renewal or purchase terms in the contract. Rental expense under operating leases was $20,362, $17,671, and $16,243 for the years ended December 31, 2013, 2012, and 2011, 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, 2013, are:
The net amount of leased assets capitalized on the balance sheet as of December 31, 2013 and 2012 is as follows:
18. ROYALTIES
Royalty expense, inclusive of royalties owed to a related party, for the years ended December 31, 2013, 2012, and 2011 were $12,212, $9,446, and $7,409, respectively. For the years ended December 31, 2013 and 2012, the Company recorded $372 and $223, respectively, of advance royalty payments. These payments are recoupable against royalties generated from future mining activity. As of December 31, 2013 and 2012, advance royalties totaled $3,509 and $7,684, respectively. Included in this amount is $2,235 and $1,149 as of December 31, 2013 and 2012, 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.
As of December 31, 2012, the Company had a remaining advance royalty to ARP of $5,683, which was fully recouped against production royalties earned in 2013 on certain wholly-owned reserves of ARP (see Note 13).
Anticipated future minimum advance royalties as of December 31, 2013, are payable as follows:
In addition to the above advanced royalties, production royalties are payable based on the quantity of coal mined in future years.
Various royalties and commissions have been negotiated with certain key executives of management, a former minority unitholder, and sales brokers. See Note 13 for the terms of royalties to employees.
19. ASSET RETIREMENT OBLIGATIONS AND RECLAMATION
Asset retirement obligation and reclamation balances consist of the following as of December 31, 2013 and 2012:
The credit-adjusted, risk-free rates used to discount the estimated liability were 10.8% and 9.7% in 2013 and 2012, respectively.
For the years ended December 31, 2013 and 2012, 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, partially offset by new mine development, specifically the Lewis Creek underground mine in 2012.
20. INCOME TAXES
The income (loss) before income taxes and non-controlling interest was ($25,072), ($18,039), and $4,328, for the years ended December 31, 2013, 2012, and 2011, respectively.
The components of the income tax provision are as follows:
The income tax rate differed from the U.S. federal statutory rate as follows:
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consist of the following:
Changes to the valuation allowance during the years ended December 31, 2013 and 2012, were as follows:
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, 2013 and 2012. Based on the anticipated reversals of the Company’s deferred tax assets and deferred tax liabilities, a valuation allowance of $24,371 and $14,818 at December 31, 2013 and 2012, 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 $168,024 and $134,134, respectively, as of December 31, 2013 and $142,567 and $104,738, respectively, as of December 31, 2012. The NOLs begin to expire in 2026. The Company’s net deferred taxes also include $407 of AMT credits as of December 31, 2013 and 2012. 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 2013 and 2012 the Company made an immaterial amount of federal, state, and local income tax payments. In 2011, the Company paid federal income taxes of $387 and state and local income taxes of $643.
There were no uncertain tax positions as of December 31, 2013 or 2012, and the Company has not currently accrued interest or penalties. If the accrual of interest or penalties becomes appropriate, the Company will record an accrual as part of its income tax provision.
21. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2013 and 2012 consisted of the following:
The following is a summary of reclassifications out of accumulated other comprehensive income (loss) for the years ended December 31, 2013, 2012 and 2011:
(a) This component of accumulated other comprehensive income (loss) is included in the computation of net period postretirement cost. See Note 22.
22. 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 $2,670, $2,720, and $1,933, for the years ended December 31, 2013, 2012, and 2011, respectively.
Postretirement Medical Cost Reimbursement Plan
Effective January 1, 2013, the Company began providing certain health care benefits, including the reimbursement of a portion of out-of-pocket costs associated with insurance coverage, to qualifying salaried and hourly retirees and their dependents. Plan coverage for reimbursements will be provided to future hourly and salaried retirees in accordance with the plan document. As of the effective date, the Company recognized a liability totaling $907 associated with the benefits earned by qualified employees prior to January 1, 2013. The Company’s funding policy with respect to the plan is to fund the cost of all postretirement benefits as they are paid.
Net periodic postretirement benefit cost included the following components:
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive income is as follows:
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 ended December 31, 2014 are zero and $0.1 million, respectively.
The following table sets forth changes in benefit obligation and plan assets for the year ended December 31, 2013 and the funded status of the plan reconciled with the amounts reported in our consolidated financial statements at December 31, 2013:
Estimated future benefit payments, which reflect expected future service, as of December 31, 2013 are as follows:
The health care cost trend rate assumed for 2014 is 7.30% and is expected to reach an ultimate trend rate of 4.50% by 2027. A one-percentage point change in the assumed health care cost trend would have an immaterial impact on the benefit obligation.
23. EQUITY AWARDS
Redemption of Non-Recourse Promissory Notes
In previous years, the Chief Executive Officer, the President, and a former board member have purchased common stock in the Company, which have been paid with cash and non-recourse promissory notes. On September 30, 2011, the non-recourse promissory notes outstanding from the Chief Executive Officer and the President were repaid in full through the sale of 148,652 shares of common stock back to the Company by the borrowers. The common stock was repurchased at $18.27 per share, which is a premium from the estimated fair value on the date of acquisition of $12.00 per share. Because the Company’s common stock is not publicly traded, the fair market value was estimated based on multiple valuation methodologies utilizing both quantitative and qualitative factors. A market approach using the comparable company method and an income approach using the discounted cash flow method were used to determine a fair value per common share. As a result of the premium paid on the redemption of the shares, a non-cash charge of $933 was recognized in the results of operations as a component of general and administrative expenses for year ended December 31, 2011 for the difference between the acquisition date fair value and the fair value at the time of redemption.
The outstanding principal and interest associated with the non-recourse promissory note from the former board member was settled in full on November 1, 2011 with the payment of cash to the Company of $1,083. As of December 31, 2013, no executives or directors of the Company have non-recourse promissory notes outstanding.
Restricted Stock Awards
The primary stock-based compensation tool used by the Company for its employee base is through awards of restricted stock. The majority of restricted stock awards generally cliff vest after two to three years of service. 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, 2013:
Unearned compensation of $92 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 0.2 years. The Company recognized expense of $418, $697, and $450 related to restricted shares for the years ended December 31, 2013, 2012, and 2011, respectively.
24. PREFERRED STOCK
On January 13, 2012, the Company sold 300,000 shares of newly-created Series A Convertible preferred stock to certain investment funds managed by Yorktown pursuant to a certificate of designation for net cash consideration totaling $30,000. The proceeds of the sale were used to repay a portion of the outstanding borrowings under the 2011 Credit Facility and for general corporate purposes. The preferred stockholders were not entitled to dividends and the shares of preferred stock would convert into common stock of the Company at the consummation of an initial public offering (IPO). In December 2012, the Company entered into a Share Conversion Agreement with Yorktown, whereby all of the outstanding shares of Series A Convertible preferred stock converted into an aggregate of 2,775,000 shares of common stock of the Company. The fair value of the Company’s common stock on the date of conversion, based on a third-party valuation, was $12.11 per share.
25. COMMITMENTS AND CONTINGENCIES
The Company is subject to various market, operational, financial, regulatory, and legislative risks. Numerous federal, state, and local governmental permits and approvals are required for mining operations. Federal and state regulations require regular monitoring of mines and other facilities to document compliance. Monetary penalties of $1,064 and $976 related to Mine Safety and Health Administration (MSHA) fines were accrued in the results of operations for the years ended December 31, 2013 and 2012, respectively.
On October 28, 2011, a portion of the highwall at the Company’s Equality Boot mine collapsed, fatally injuring two employees of a local blasting company. Following the accident, pursuant to Section 103(k) of the Mine Act, MSHA issued an order prohibiting all activity at the Equality Boot mine until it was determined to be safe to resume normal mining operations. MSHA approved resuming mining of the uppermost coal seam on November 2, 2011. An addendum to the ground control plan was submitted to MSHA and approved on November 8, 2011, which allowed for mining of the lower seams to resume.
On February 7, 2012, the Kentucky Office of Mine Safety and Licensing issued its Fatal Accident Report. The Commonwealth of Kentucky concluded that the failure of the highwall occurred where the rock strata transitioned from wide bands of shale to smaller bands on laminated rock, thus creating a slicken slide fault in the area where the rock fell. The Kentucky Office of Mine Safety and Licensing did not find any causes or circumstances which contributed to the accident other than the aforementioned naturally occurring geological condition.
Finally, on May 7, 2012, MSHA issued its final Investigation Report concerning the accident. Similar to the findings of the Kentucky Office of Mine Safety and Licensing, MSHA concluded that the accident occurred because of a geologic anomaly located in the portion of the highwall below the #14 coal seam and above the #13 coal seam where there were two intersecting or nearly intersecting discontinuities in the rock formation. Although MSHA concluded that personnel at the Equality Boot mine had failed to recognize the anomaly and issued five Section 104(a) citations in connection with the accident, MSHA did not issue any citations finding high negligence or reckless disregard on the part of the Company or its employees. The Company does not believe the impact of this accident will have a material adverse effect on its consolidated cash flows, results of operations or financial condition.
Periodically, there may be various claims and legal proceedings against the Company arising from the normal course of business. 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 six years. The Company, via contractual agreements, has committed volumes of sales in 2014 and 2015 of 9.6 million tons and 7.8 million tons, respectively.
Coal Transportation Agreements
In December 2007, the Company entered into a lease services agreement with a third party commencing January 2008 and expiring December 2015. The third party will provide all barge switching, coal loading, tug, hauling, and similar services necessary for the Company’s operations. During the term of the agreement, the Company will pay a monthly amount based on the annual volume of tons of coal loaded at the dock facility. The Company commenced activity under the lease in January 2009 and incurred $3,596, $3,474, and $2,583 of expense during the years ended December 31, 2013, 2012, and 2011, respectively.
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.
26. 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.
Supplemental Condensed Consolidating Balance Sheets
Supplemental Condensed Consolidated Statements of Operations
Supplemental Condensed Consolidating Statements of Comprehensive Income (Loss)
Supplemental Condensed Consolidating Statements of Cash Flows
27. SUMMARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
A summary of the unaudited quarterly results of operations for the years ended December 31, 2013 and 2012 is presented below.
(1) Included within the fourth quarter of 2012 is a loss on extinguishment of debt of $3,953, a loss on settlement of the interest rate swap of $1,409, and a loss on deferment of an equity offering of $1,130.