UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K/A

 

CURRENT REPORT

 

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported): March 17, 2016

 

ROYAL ENERGY RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

Delaware		000-52547		11-3480036
(State or other jurisdiction of incorporation)		(Commission file number)		(I.R.S. Employer Identification Number)

 

56 Broad Street, Suite 2, Charleston, SC 29401

(Address of principal executive offices) (Zip Code)

 

(843) 900-7693

(Registrant’s telephone number, including area code)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

[  ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

[  ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

[  ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

[  ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4c))

 

 

 

Section 8 – Other Events

 

Item 8.01 Other Events.

 

Attached hereto as Exhibit A are updated risk factors relating to the Registrant’s investment in Rhino Resource Partners, LP.

 

Section 9 – Financial Statements and Exhibits

 

Item 9.01 Financial Statements and Exhibits.

 

	(a)	In accordance with Rule 8-04(b) of Regulation S-X, attached hereto as Exhibit B are audited financial statements for Rhino Resource Partners, LP (“Rhino”) for the fiscal years ended December 31, 2014 and 2015. Attached hereto as Exhibit C are selected financial data for Rhino showing pro forma adjustments to certain earnings per unit data as a result of a 1-for-10 reverse split of Rhino’s common and subordinated units effected on April 18, 2016.
	(b)	In accordance with Rule 8-05 of Regulation Sd-X, attached hereto as Exhibit D are pro forma statements of income reflecting the combined operations of the Registrant and Rhino for the fiscal year ended December 31, 2015 and a pro forma balance sheet of the Registrant as of December 31, 2015.
	(c)	Not applicable.
	(d)	Exhibits.

 

Exhibit No.		Description
10.1*		Securities Purchase Agreement between Royal Energy Resources, Inc. and Rhino Resource Partners, LP
23.1		Consent of Ernst & Young LLP
99.1*		Press Release dated March 18, 2016.
99.2*		Press Release dated March 23, 2016

 

* Originally filed with as exhibits to Form 8-K filed March 23, 2016.

 

 

SIGNATURES

 

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

	ROYAL ENERGY RESOURCES, INC.
Date: August 8, 2016		/s/ William L. Tuorto
	By:	William L. Tuorto, Chief Executive Officer

 

 

EXHIBIT A

 

The Company’s investment in Rhino is subject to all of the risks to which Rhino’s underlying business is subject. Set forth below are risk factors that Rhino discloses about its business, which is derived from the risk factors disclosed by Rhino in its Form 10-K for the year ended December 31, 2015, and subsequent reports filed on Forms 10-Q and 8-K.

 

Risks Related to Rhino

 

Prior to the amendment of our amended and restated credit agreement in May 2016 to extend its expiration date to July 31, 2017, we were unable to demonstrate that we had sufficient liquidity to operate our business over the next twelve months and thus substantial doubt was raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2015.

 

Prior to the amendment of our amended and restated credit agreement in May 2016 to extend its expiration date to July 31, 2017, we were unable to demonstrate that we had sufficient liquidity to operate our business over the next twelve months and thus substantial doubt was raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2015. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

 

There are other uncertainties as to our ability to access funding under our amended and restated credit agreement. In order to borrow under our amended and restated credit facility, we must make certain representations and warranties to our lenders at the time of each borrowing. If we are unable to make these representations and warranties, we would be unable to borrow under our amended and restated credit facility, absent a waiver. Furthermore, if we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. Given the continued weak demand and low prices for met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement.

 

Our principal liquidity requirements are to finance current operations, fund capital expenditures and service our debt. Our principal sources of liquidity are cash generated by our operations and borrowings under our credit facility. If we are unable to extend the expiration date of our amended and restated credit facility or secure a replacement facility or borrow under our existing credit facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including amounts that may become due under our credit facility. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern.

 

 

Our common units are currently traded on the OTCQB as a result of the NYSE’s delisting of our common units from the NYSE, which could adversely affect the market liquidity of our common units and harm our business.

 

On December 17, 2015, the NYSE notified us that it had determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for its common units. The NYSE also suspended the trading of the common units at the close of trading on December 17, 2015. Following the suspension, our common units began trading on the OTCQB under the symbol “RHNO” on December 18, 2015. The NYSE informed us that it will apply to the Securities and Exchange Commission to delist our common units upon completion of all applicable procedures, including any appeal by us of the NYSE’s decision. On January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our common units. The NYSE held a hearing regarding our appeal on April 20, 2016 and affirmed its prior decision to delist our common units.

 

On April 27, 2016, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on May 9, 2016. The Partnership’s common units continued to trade on the OTCQB Marketplace under the ticker symbol “RHNOD” until May 16, 2016, at which time the OTCQB ticker symbol reverted to “RHNO.”

 

The delisting of our common units from the NYSE could negatively impact us by, among other things, reducing the liquidity and market price of our common units; reducing the number of investors willing to hold or acquire our common units; and limiting our ability to issue additional securities or obtain additional financing. Further, since our common units were delisted from the NYSE, we are no longer subject to the NYSE rules including rules requiring us to meet certain corporate governance standards. Without required compliance of these corporate governance standards, investor interest in our common units may decrease.

 

Trading on the OTCQB or one of the other over-the-counter markets may result in a reduction in some or all of the following, each of which could have a material adverse effect on our unitholders:

 

	●	the liquidity of our common units;
	●	the market price of our common units;
	●	our ability to issue additional securities or obtain financing;
	●	the number of institutional and other investors that will consider investing in our common units;
	●	the number of market makers in our common units;
	●	the availability of information concerning the trading prices and volume of our common units; and
	●	the number of broker-dealers willing to execute trades in our common units.

 

We may not have sufficient cash to enable us to pay the minimum quarterly distribution on our common units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner.

 

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.445 per unit, or $1.78 per unit per year, which will require us to have available cash of approximately $13.3 million per quarter, or $53.2 million per year, based on the number of common and subordinated units outstanding as of December 31, 2015 and the general partner interest. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

	●	the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;
	●	the price at which we are able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

 

 

	●	the level of our operating costs, including reimbursement of expenses to our general partner and its affiliates. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed;
	●	the proximity to and capacity of transportation facilities;
	●	the price and availability of alternative fuels;
	●	the impact of future environmental and climate change regulations, including those impacting coal-fired power plants;
	●	the level of worldwide energy and steel consumption;
	●	prevailing economic and market conditions;
	●	difficulties in collecting our receivables because of credit or financial problems of customers;
	●	the effects of new or expanded health and safety regulations;
	●	domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry, the electric utility industry or the steel industry;
	●	changes in tax laws;
	●	weather conditions; and
	●	force majeure.

 

We may reduce or eliminate distributions at any time we determine that our cash reserves are insufficient or are otherwise required to fund current or anticipated future operations, capital expenditures, acquisitions, growth or expansion projects, debt repayment or other business needs. Beginning with the quarter ended September 30, 2014, distributions on our common units were below the minimum level and, beginning with the quarter ended June 30, 2015, we suspended the quarterly distribution on our common units altogether. Pursuant to our partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum quarterly distribution level and our subordinated units do not accrue such arrearages. In the future, if and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders. Any additional distribution amounts paid at that time are then paid to common unitholders until previously unpaid accumulated arrearage amounts have been paid in full. Thus, we have arrearages accumulating on our common units since the distribution level has been below our minimum quarterly level of $0.445 per unit. In addition, we have not paid any distributions on our subordinated units for any quarter after the quarter ended March 31, 2012. We may not have sufficient cash available for distributions on our common or subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay any quarterly distribution on our common units. Moreover, we may not be able to increase distributions on our common units if we are unable to pay the accumulated arrearages on our common units as well as the full minimum quarterly distribution on our subordinated units.

 

A decline in coal prices could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal as well as our ability to improve productivity and control costs. Prices for coal tend to be cyclical; however, prices have become more volatile and depressed as a result of oversupply in the marketplace. The prices we receive for coal depend upon factors beyond our control, including:

 

	●	the supply of domestic and foreign coal;.
	●	the demand for domestic and foreign coal, which is significantly affected by the level of consumption of steam coal by electric utilities and the level of consumption of metallurgical coal by steel producers;
	●	the price and availability of alternative fuels for electricity generation;

 

  

	●	the proximity to, and capacity of, transportation facilities;
	●	domestic and foreign governmental regulations, particularly those relating to the environment, climate change, health and safety;
	●	the level of domestic and foreign taxes;
	●	weather conditions;
	●	terrorist attacks and the global and domestic repercussions from terrorist activities; and
	●	prevailing economic conditions.

 

Any adverse change in these factors could result in weaker demand and lower prices for our products. In addition, the recent global economic downturn, coupled with the global financial and credit market disruptions, has had an impact on the coal industry generally and may continue to do so. The demand for electricity and steel may remain at low levels or further decline if economic conditions remain weak. If these trends continue, we may not be able to sell all of the coal we are capable of producing or sell our coal at prices comparable to recent years.

 

In addition to competing with other coal producers, we compete generally with producers of other fuels, such as natural gas. A decline in the price of natural gas has made natural gas more competitive against coal and resulted in utilities switching from coal to natural gas. Sustained low natural gas prices may also cause utilities to phase out or close existing coal-fired power plants or reduce or eliminate construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal. A substantial or extended decline in the prices we receive for our coal supply contracts could materially and adversely affect our results of operations.

 

As the prolonged weakness in the U.S. coal markets continued during 2015, we performed a comprehensive review during the fourth quarter of 2015 of our current coal mining operations as well as potential future development projects to ascertain any potential impairment losses. We identified various properties, projects and operations that were potentially impaired based upon changes in its strategic plans, market conditions or other factors, specifically in Northern Appalachia where market conditions related to our operations deteriorated in the fourth quarter of 2015. We believe that an oversupply of coal being produced in Northern Appalachia has contributed to depressed coal prices from this region. We believe the oversupply of coal has been created due to historically low natural gas prices in this region, which competes with coal as a source of electricity generation. Utilities have chosen cheap natural gas for electricity generation over coal and, additionally, we believe the amount that the utilities’ power plants have been dispatched for electricity generation has fallen due to low electricity demand. The production of natural gas from the Utica Shale and Marcellus Shale regions that are located within the Northern Appalachian region have kept natural gas prices low and larger coal producers have low-cost long-wall mines in Northern Appalachia that can compete to sell lower priced coal to utilities that still require coal supplies in this region. We believe this combination of factors have decreased coal prices in Northern Appalachia to levels where certain current operations as well as future plans for the development of the Leesville Field will be unprofitable in the near term. In addition to impairment charges related to certain Northern Appalachia operations, we also recorded asset impairment and related charges for the sale of the Deane mining complex, the sale of our Cana Woodford oil and natural gas investment and an impairment charge for intangible assets. We recorded approximately $31.6 million of total asset impairment and related charges for the year ended December 31, 2015.

 

In addition, the prices of oil and natural gas may fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control.

 

We could be negatively impacted by the competitiveness of the global markets in which we compete and declines in the market demand for coal.

 

We compete with coal producers in various regions of the United States and overseas for domestic and international sales. The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry and the domestic steel industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric and wind power and other renewable energy sources. Consumption by the domestic steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and automobiles. The competitive environment for coal is impacted by a number of the largest markets in the world, including the United States, China, Japan and India, where demand for both electricity and steel has supported prices for steam and metallurgical coal. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. The cost of ocean transportation and the value of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of our coal as we compete on price with foreign coal producing sources. During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely impacting our results of operations and cash available for distribution.

 

 

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on prevailing market conditions. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, potentially reducing the price we could obtain for this coal and adversely impacting our cash flows, results of operations and cash available for distribution.

 

Any change in consumption patterns by utilities away from the use of coal, such as resulting from current low natural gas prices, could affect our ability to sell the coal we produce, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Steam coal accounted for approximately 95% of our coal sales volume for the year ended December 31, 2015. The majority of our sales of steam coal during this period were to electric utilities for use primarily as fuel for domestic electricity consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and oil as well as alternative sources of energy. We compete generally with producers of other fuels, such as natural gas and oil. A decline in price for these fuels could cause demand for coal to decrease and adversely affect the price of our coal. For example, sustained low natural gas prices have led, in some instances, to decreased coal consumption by electricity-generating utilities. If alternative energy sources, such as nuclear, hydroelectric, wind or solar, become more cost-competitive on an overall basis, demand for coal could decrease and the price of coal could be materially and adversely affected. Further, legislation requiring, subsidizing or providing tax benefit for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could materially adversely affect our results of operations and cash available for distribution to our unitholders.

 

Our mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.

 

The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant and time-consuming and may delay commencement or continuation of our operations. Moreover, the possibility exists that new laws or regulations (or new judicial interpretations or enforcement policies of existing laws and regulations) could materially affect our mining operations, results of operations and cash available for distribution to our unitholders, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers’ use of coal. Violations of applicable laws and regulations would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. The enforcement of laws and regulations governing the coal mining industry has increased substantially. As a result, the consequences for any noncompliance may become more significant in the future.

 

 

Our operations use petroleum products, coal processing chemicals and other materials that may be considered “hazardous materials” under applicable environmental laws and have the potential to generate other materials, all of which may affect runoff or drainage water. In the event of environmental contamination or a release of these materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and cleanup of soil, surface water, groundwater, and other media, as well as abandoned and closed mines located on property we operate. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire.

 

The government extensively regulates mining operations, especially with respect to mine safety and health, which imposes significant actual and potential costs on us, and future regulation could increase those costs or limit our ability to produce coal.

 

Coal mining is subject to inherent risks to safety and health. As a result, the coal mining industry is subject to stringent safety and health standards. Fatal mining accidents in the United States in recent years have received national attention and have led to responses at the state and federal levels that have resulted in increased regulatory scrutiny of coal mining operations, particularly underground mining operations. More stringent state and federal mine safety laws and regulations have included increased sanctions for non-compliance. Moreover, future workplace accidents are likely to result in more stringent enforcement and possibly the passage of new laws and regulations.

 

Within the last few years, the industry has seen enactment of the Federal Mine Improvement and New Emergency Response Act of 2006 (the “MINER Act”), subsequent additional legislation and regulation imposing significant new safety initiatives and the Dodd-Frank Act, which, among other things, imposes new mine safety information reporting requirements. The MINER Act significantly amended the Federal Mine Safety and Health Act of 1977 (the “Mine Act”), imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, the U.S. Mine Safety and Health Administration (“MSHA”) issued new or more stringent rules and policies on a variety of topics, including:

 

	●	sealing off abandoned areas of underground coal mines;
	●	mine safety equipment, training and emergency reporting requirements;
	●	substantially increased civil penalties for regulatory violations;
	●	training and availability of mine rescue teams;
	●	underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
	●	flame-resistant conveyor belt, fire prevention and detection, and use of air from the belt entry; and
	●	post-accident two-way communications and electronic tracking systems.

 

For example, in 2014, MSHA adopted a final rule that reduces the permissible concentration of respirable dust in underground coal mines from the current standard of 2.0 milligrams per cubic meter of air to 1.5 milligram per cubic meter. The rule has a phased implementation schedule, the final phase required to be implemented by August 2016. Under the phased approach, operators will be required to adopt new measures and procedures for dust sampling, record keeping, and medical surveillance. More recently, in September 2015, MSHA issued a proposed rule requiring the installation of proximity detection systems on underground coal hauling systems used on the mining section. Proximity detection is a technology that uses electronic sensors to detect motion and the distance between a miner and a machine. These systems provide audible and visual warnings, and automatically stop moving machines when miners are in the machines’ path. These and other new safety rules could result in increased compliance costs on our operations. Subsequent to passage of the MINER Act, various coal producing states, including West Virginia, Ohio and Kentucky, 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. Additional federal and state legislation that would further increase mine safety regulation, inspection and enforcement, particularly with respect to underground mining operations, has also been considered.

 

Although we are unable to quantify the full impact, implementing and complying with these new laws and regulations could have an adverse impact on our results of operations and cash available for distribution to our unitholders and could result in harsher sanctions in the event of any violations.

 

 

Penalties, fines or sanctions levied by MSHA could have a material adverse effect on our business, results of operations and cash available for distribution.

 

Surface and underground mines like ours and those of our competitors are continuously inspected by MSHA, which often leads to notices of violation. Recently, MSHA has been conducting more frequent and more comprehensive inspections. In addition, in July 2014, MSHA proposed a rule that revises its civil penalty assessment provisions and how regulators should approach calculating penalties, which, in some instances, could resulted in increased civil penalty assessments for medium and larger mine operators and contractors by 300 to 1,000 percent. MSHA issued a revised proposed rule in February 2015, but, to date, has not taken any further action. However, increased scrutiny by MSHA and enforcement against mining operations are likely to continue.

 

On June 24, 2011, our subsidiary, CAM Mining LLC received notice that on June 23, 2011, MSHA commenced an action in the U.S. District Court of the Eastern District of Kentucky seeking injunctive relief as a result of alleged violations of Sections 103, 104, and 108 of the Mine Act occurring at Mine 28 in connection with an inspection on June 17, 2011 by MSHA inspectors. The complaint alleged that when MSHA inspectors arrived at Mine 28 to inspect the mine with respect to the allegations that employees had been smoking underground, CAM Mining LLC employees gave advance notice of the inspection to miners working underground and that this advance notice hindered, interfered with and delayed the inspection by MSHA. The complaint asserts that the MSHA inspectors did not find any evidence of smoking paraphernalia during the inspection, which was allegedly the result of this advance notice. On June 30, 2011, MSHA obtained a temporary restraining order prohibiting any advance notice of inspections in the future. That became a Permanent Injunction on July 14, 2011. The Permanent Injunction is for three years and expired on July 14, 2014. On June 17, 2011, MSHA also issued a 104(a) citation in this matter to the Mine for allegedly giving advance notice of the inspection. The citation was assessed at $10,000 and was settled for $8,000 in 2014 upon approval by the administrative law judge.

 

As a result of these and future inspections and alleged violations and potential violations, we could be subject to material fines, penalties or sanctions. Any of our mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our business, results of operations and cash available for distribution.

 

We may be unable to obtain and/or renew permits necessary for our operations, which could prevent us from mining certain reserves.

 

Numerous governmental permits and approvals are required for mining operations, and we can face delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits and approvals, including environmental permits. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations. In addition, the public has certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. Over the past few years, the length of time needed to bring a new surface mine into production has increased because of the increased time required to obtain necessary permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in the future.

 

Section 402 National Pollutant Discharge Elimination System permits and Section 404 CWA permits are required to discharge wastewater and discharge dredged or fill material into waters of the United States. Expansion of EPA jurisdiction over these areas has the potential to adversely impact our operations. For example, the EPA released a final rule in May 2015 that attempted to clarify federal jurisdiction under the CWA over waters of the United States, but a number of legal challenges to this rule are pending, and implementation of the rule has been stayed nationwide. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Our surface coal mining operations typically require such permits to authorize such activities as the creation of slurry ponds, stream impoundments, and valley fills. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authorities more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

 

 

Our mining operations are subject to operating risks that could adversely affect production levels and operating costs.

 

Our mining operations are subject to conditions and events beyond our control that could disrupt operations, resulting in decreased production levels and increased costs.

 

These risks include:

 

	●	unfavorable geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;
	●	inability to acquire or maintain necessary permits or mining or surface rights;
	●	changes in governmental regulation of the mining industry or the electric utility industry;
	●	adverse weather conditions and natural disasters;
	●	accidental mine water flooding;
	●	labor-related interruptions;
	●	transportation delays;
	●	mining and processing equipment unavailability and failures and unexpected maintenance problems; and
	●	accidents, including fire and explosions from methane.

 

Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

 

In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workmen’s compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shut-down could give rise to liabilities for failure to meet the requirements of coal supply agreements especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, including business interruption insurance, but those policies are subject to various exclusions and limitations and we cannot assure you that we will receive coverage under those policies for any personal injury, property damage or business interruption claims that may arise out of such an accident. Moreover, certain potential liabilities such as fines and penalties are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our results of operations and cash available for distribution.

.

Fluctuations in transportation costs or disruptions in transportation services could increase competition or impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive energy source or could make our coal production less competitive than coal produced from other sources.

 

 

Significant decreases in transportation costs could result in increased competition from coal producers in other regions. For instance, coordination of the many eastern U.S. coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing regions limited the use of western coal in certain eastern markets. The increased competition could have an adverse effect on our results of operations and cash available for distribution to our unitholders.

 

We depend primarily upon railroads, barges and trucks to deliver coal to our customers. Disruption of any of these services due to weather-related problems, strikes, lockouts, accidents, mechanical difficulties and other events could temporarily impair our ability to supply coal to our customers, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

In recent years, the states of Kentucky and West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that other states may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect our results of operations and cash available for distribution.

 

A shortage of skilled labor in the mining industry could reduce productivity and increase operating costs, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Efficient coal mining using modern techniques and equipment requires skilled laborers. During periods of high demand for coal, the coal industry has experienced a shortage of skilled labor as well as rising labor and benefit costs, due in large part to demographic changes as existing miners retire at a faster rate than new miners are entering the workforce. If a shortage of experienced labor should occur or coal producers are unable to train enough skilled laborers, there could be an adverse impact on labor productivity, an increase in our costs and our ability to expand production may be limited. If coal prices decrease or our labor prices increase, our results of operations and cash available for distribution to our unitholders could be adversely affected.

 

Unexpected increases in raw material costs, such as steel, diesel fuel and explosives could adversely affect our results of operations.

 

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, diesel fuel, explosives and other raw materials in our mining operations, and volatility in the prices for these raw materials could have a material adverse effect on our operations. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly. Additionally, a limited number of suppliers exist for explosives, and any of these suppliers may divert their products to other industries. Shortages in raw materials used in the manufacturing of explosives, which, in some cases, do not have ready substitutes, or the cancellation of supply contracts under which these raw materials are obtained, could increase the prices and limit the ability of us or our contractors to obtain these supplies. Future volatility in the price of steel, diesel fuel, explosives or other raw materials will impact our operating expenses and could adversely affect our results of operations and cash available for distribution.

 

If we are not able to acquire replacement coal reserves that are economically recoverable, our results of operations and cash available for distribution to our unitholders could be adversely affected.

 

Our results of operations and cash available for distribution to our unitholders depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our results of operations and cash available for distribution to our unitholders. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

 

 

Inaccuracies in our estimates of coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs.

 

We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff, which is periodically audited by independent engineering firms. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, recently acquired coal reserves and estimated costs of production and sales prices. There are numerous factors and assumptions inherent in estimating quantities and qualities of coal reserves and non-reserve coal deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results. These factors and assumptions relate to:

 

	●	quality of coal;
	●	geological and mining conditions and/or effects from prior mining that may not be fully identified by available exploration data or which may differ from our experience in areas where we currently mine;
	●	the percentage of coal in the ground 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;
	●	historical production from the area compared with production from other similar producing areas;
	●	the timing for the development of reserves; and
	●	assumptions concerning equipment and productivity, future coal prices, operating costs, capital expenditures and development and reclamation costs.

 

For these reasons, estimates of the quantities and qualities of the economically recoverable coal attributable to any particular group of properties, classifications of coal reserves and non-reserve coal deposits based on risk of recovery, estimated cost of production and estimates of net cash flows expected from particular reserves 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 from identified coal reserve and non-reserve coal deposit areas or properties and revenues and expenditures associated with our mining operations may vary materially from estimates. Accordingly, these estimates may not reflect our actual coal reserves or non-reserve coal deposits. Any inaccuracy in our estimates related to our coal reserves and non-reserve coal deposits could result in lower than expected revenues and higher than expected costs, which could have a material adverse effect on our ability to make cash distributions.

 

We invest in non-coal natural resource assets, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

 

Part of our business strategy is to expand our operations through strategic acquisitions, which includes investing in non-coal natural resources assets. Our executive officers do not have experience investing in or operating non-coal natural resources assets and we may be unable to hire additional management with relevant expertise in operating such assets. Acquisitions of non-coal natural resource assets could expose us to new and additional operating and regulatory risks, including commodity price risk, which could result in a material adverse effect on our results of operations and cash available for distribution to our unitholders.

 

 

The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

 

Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment. Our annual estimated maintenance capital expenditures for purposes of calculating operating surplus is based on our estimates of the amounts of expenditures we will be required to make in the future to maintain our long-term operating capacity. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. The amount of our estimated maintenance capital expenditures may be more than our actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders.

 

Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce the demand for our coal. A reduction in demand for our coal could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other consumers of our coal. These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal.

 

Federal and state laws restricting the emissions of greenhouse gases in areas where we conduct our business or sell our coal could adversely affect our operations and demand for our coal.

 

One by-product of burning coal is carbon dioxide, which EPA considers a GHG, and a major source of concern with respect to climate change and global warming.

 

Future regulation of GHG in the United States could occur pursuant to future U.S. treaty commitments, new domestic legislation that may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. For example, on the international level, the United States is one of almost 200 nations that agreed on December 12, 2015 to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets; however, the agreement does not set binding GHG emission reduction targets.

 

In August 2015, the EPA issued its final Clean Power Plan (the “CPP”), rules that establish carbon pollution standards for power plants, called CO₂ emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO₂. The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA. Judicial challenges have been filed. On February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP before the United States Court of Appeals for the District of Columbia (“Circuit Court”) even issued a decision. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted. The stay suspends the rule, including the requirement that states submit their initial plans by September 2016. The Supreme Court’s stay applies only to EPA’s regulations for CO₂ emissions from existing power plants and will not affect EPA’s standards for new power plants. It is not yet clear how the either the Circuit Court or the Supreme Court will rule on the legality of the CPP. If the rules were upheld at the conclusion of this appellate process and were implemented in their current form, demand for coal will likely be further decreased. The EPA also issued a final rule for new coal-fired power plants in August 2015, which essentially set performance standards for coal-fired power plants that requires partial carbon capture and sequestration. Additional legal challenges have been filed against the EPA’s rules for new power plants. The EPA’s GHG rules for new and existing power plants, taken together, have the potential to severely reduce demand for coal. In addition, passage of any comprehensive federal climate change and energy legislation could impact the demand for coal. Any reduction in the amount of coal consumed by North American 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.

 

 

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, including coal-fired electric generating facilities. For example, in 2005, ten northeastern states entered into the Regional Greenhouse Gas Initiative agreement (the “RGGI”), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statute and/or regulation a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional northeastern states and Canadian provinces have joined as participants or observers.

 

Following the RGGI model, five western states launched the Western Regional Climate Action Initiative to identify, evaluate and implement collective and cooperative methods of reducing greenhouse gases in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 12, 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.

 

Many coal-fired plants have already closed or announced plans to close and proposed new construction projects have also come under additional scrutiny with respect to GHG emissions. There have been an increasing number of protests and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to greenhouse gas emissions. Other state regulatory authorities have also rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fired power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, 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. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers; they may reduce the demand for coal-fired power, and may affect long-term demand for our coal.

 

If mandatory restrictions on carbon dioxide emissions are imposed, the ability to capture and store large volumes of carbon dioxide emissions from coal-fired power plants may be a key mitigation technology to achieve emissions reductions while meeting projected energy demands. A number of recent legislative and regulatory initiatives to encourage the development and use of carbon capture and storage technology have been proposed or enacted. On February 3, 2010, President Obama sent a memorandum to the heads of fourteen Executive Departments and Federal Agencies establishing an Interagency Task Force on Carbon Capture and Storage (“CCS”). The goal was to develop a comprehensive and coordinated Federal strategy to speed the commercial development and deployment of clean coal technologies. On August 12, 2010, the Task Force delivered a series of recommendations on overcoming the barriers to the widespread, cost-effective deployment of CCS within ten years. The report concludes that CCS can play an important role in domestic GHG emissions reductions while preserving the option of using abundant domestic fossil energy resources. The EPA also recently finalized new source performance standards for GHG for new coal and oil-fired power plants, which requires partial carbon capture and sequestration to comply. However, widespread cost-effective deployment of CCS will occur only if the technology is commercially available at economically competitive prices and supportive national policy frameworks are in place.

 

 

In the meantime, the EPA and other regulators are using existing laws, including the federal Clean Air Act, to limit emissions of carbon dioxide and other GHGs from major sources, including coal-fired power plants that may require the use of “best available control technology” or “BACT.” As state permitting authorities continue to consider GHG control requirements as part of major source permitting BACT requirements, costs associated with new facility permitting and use of coal could increase substantially. A growing concern is the possibility that BACT will be determined to be the use of an alternative fuel to coal.

 

As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less GHG emissions, possibly further reducing demand for our coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Federal and state laws require bonds to secure our obligations to reclaim mined property. Our inability to acquire or failure to maintain, obtain or renew these surety bonds could have an adverse effect on our ability to produce coal, which could adversely affect our results of operations and cash available for distribution to our unitholders.

 

We are required under federal and state laws to place and maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as “reclamation”) and to satisfy other miscellaneous obligations. Federal and state governments could increase bonding requirements in the future. Certain business transactions, such as coal leases and other obligations, may also require bonding. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including supporting letters of credit or posting cash collateral or other terms less favorable to us upon those renewals. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject us to fines and penalties as well as the loss of our mining permits. Such failure could result from a variety of factors, including:

 

	●	the lack of availability, higher expense or unreasonable terms of new surety bonds;
	●	the ability of current and future surety bond issuers to increase required collateral; and
	●	the exercise by third-party surety bond holders of their right to refuse to renew the surety bonds.

 

We maintain surety bonds with third parties for reclamation expenses and other miscellaneous obligations. It is possible that we may in the future have difficulty maintaining our surety bonds for mine reclamation. Due to adverse economic conditions and the volatility of the financial markets, surety bond providers may be less willing to provide us with surety bonds or maintain existing surety bonds or may demand terms that are less favorable to us than the terms we currently receive. We may have greater difficulty satisfying the liquidity requirements under our existing surety bond contracts. As of December 31, 2015, we had $58.5 million in reclamation surety bonds, secured by $22.4 million in letters of credit outstanding under our credit agreement. Based on the May 2016 amendment, our credit agreement provides for a $75 million working capital revolving credit facility, of which up to $30.0 million may be used for letters of credit. If we do not maintain sufficient borrowing capacity under our revolving credit facility for additional letters of credit, we may be unable to obtain or renew surety bonds required for our mining operations. If we do not maintain sufficient borrowing capacity or have other resources to satisfy our surety and bonding requirements, our operations and cash available for distribution to our unitholders could be adversely affected.

 

We depend on a few customers for a significant portion of our revenues. If a substantial portion of our supply contracts terminate or if any of these customers were to significantly reduce their purchases of coal from us, and we are unable to successfully renegotiate or replace these contracts on comparable terms, then our results of operations and cash available for distribution to our unitholders could be adversely affected.

 

We sell a material portion of our coal under supply contracts. As of December 31, 2015, we had sales commitments for approximately 92% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2016. When our current contracts with customers expire, our customers may decide not to extend or enter into new contracts. Of our total future committed tons, under the terms of the supply contracts, we will ship 60% in 2016, 35% in 2017, and 5% in 2018. We derived approximately 83.9% of our total coal revenues from coal sales to our ten largest customers for the year ended December 31, 2015, with affiliates of our top three customers accounting for approximately 45.2% of our coal revenues during that period.

 

 

In the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful, and those customers may not continue to purchase coal from us under long-term coal supply contracts 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 available for distribution. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Our mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

 

Certain provisions in our long-term coal supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

 

Price adjustment, “price re-opener” and other similar provisions in our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our results of operations and cash available for distribution to our unitholders.

 

Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our coal supply contracts permit the customer to terminate the agreement in the event of changes in regulations affecting our industry that increase the price of coal beyond a specified limit.

 

Our coal lessees’ mining operations and their financial condition and results of operations are subject to some of the same risks and uncertainties that we face as a mine operator.

 

The mining operations and financial condition and results of operations of our coal lessees are subject to the same risks and uncertainties that we face as a mine operator. If any such risks were to occur, the business, financial condition and results of operations of the lessees could be adversely affected and as a result our coal royalty revenues and cash available for distribution could be adversely affected.

 

If our coal lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.

 

We depend on our coal lessees to effectively manage their operations on the leased properties. The lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

 

	●	marketing of the coal mined;
	●	mine plans, including the amount to be mined and the method of mining;
	●	processing and blending coal;
	●	expansion plans and capital expenditures;
	●	credit risk of their customers;
	●	permitting;
	●	insurance and surety bonding;

 

 

	●	acquisition of surface rights and other coal estates;
	●	employee wages;
	●	transportation arrangements;
	●	compliance with applicable laws, including environmental laws; and
	●	mine closure and reclamation.

 

A failure on the part of one of the coal lessees to make royalty payments could give us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we might not be able to find a replacement lessee or enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase productivity.

 

Coal lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of minimum royalty payments.

 

Coal supply contracts often require operators to satisfy their obligations to their customers with resources mined from specific reserves or may provide the operator flexibility to source the coal from various reserves. Several factors may influence a coal lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the coal lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. If a coal lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production on our properties will decrease, and we will receive lower royalty revenues.

 

A coal lessee may incorrectly report royalty revenues, which might not be identified by our lessee audit process or our mine inspection process or, if identified, might be identified in a subsequent period.

 

We depend on our lessees to correctly report production and royalty revenues on a monthly basis. Our regular lessee audits and mine inspections may not discover any irregularities in these reports or, if we do discover errors, we might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with the coal lessees, or internal control deficiencies.

 

Defects in title in the coal properties that we own or loss of any leasehold interests could limit our ability to mine these properties or result in significant unanticipated costs.

 

We conduct a significant part of our mining operations on leased properties. A title defect or the loss of any lease could adversely affect our ability to mine the associated coal reserves. Title to most of our owned and leased properties and the associated mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our grantors or lessors, as the case may be. Our right to mine some coal reserves would be adversely affected by defects in title or boundaries or if a lease expires. Any challenge to our title or leasehold interest could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property. Mining operations from time to time may rely on a lease that we are unable to renew on terms at least as favorable, if at all. In such event, we may have to close down or significantly alter the sequence of mining operations or incur additional costs to obtain or renew such leases, which could adversely affect our future coal production. If we mine on property that we do not control, we could incur liability for such mining.

 

 

Our work force could become unionized in the future, which could adversely affect our production and labor costs and increase the risk of work stoppages.

 

Currently, none of our employees are represented under collective bargaining agreements. However, all of our work force may not remain union-free in the future. If some or all of our work force were to become unionized, it could adversely affect our productivity and labor costs and increase the risk of work stoppages.

 

We depend on key personnel for the success of our business.

 

We depend on the services of our senior management team and other key personnel, including senior management of our general partner. The loss of the services of any member of senior management or key employee could have an adverse effect on our business and reduce our ability to make distributions to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available.

 

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

 

The Federal Surface Mining Control and Reclamation Act of 1977 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. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed both periodically by our management and annually by independent third-party engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly.

 

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

 

Our level of indebtedness could have important consequences to us, including the following:

 

	●	our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;
	●	covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
	●	we will need a portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, distributions to unitholders and future business opportunities;
	●	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
	●	our flexibility in responding to changing business and economic conditions may be limited.

 

Increases in our total indebtedness would increase our total interest expense, which would in turn reduce our forecasted cash available for distribution. As of December 31, 2015 our current portion of long-term debt that will be funded from cash flows from operating activities during 2016 was approximately $41.5 million. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

 

 

Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities and limit our ability to pay distributions upon the occurrence of certain events.

 

The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our credit agreement restricts our ability to:

 

	●	incur additional indebtedness or guarantee other indebtedness;
	●	grant liens;
	●	make certain loans or investments;
	●	dispose of assets outside the ordinary course of business, including the issuance and sale of capital stock of our subsidiaries;
	●	change the line of business conducted by us or our subsidiaries;
	●	enter into a merger, consolidation or make acquisitions; or
	●	make distributions if an event of default occurs.

 

In addition, our payment of principal and interest on our debt will reduce cash available for distribution on our units. Our credit agreement limits our ability to pay distributions upon the occurrence of the following events, among others, which would apply to us and our subsidiaries:

 

	●	failure to pay principal, interest or any other amount when due;
	●	breach of the representations or warranties in the credit agreement;
	●	failure to comply with the covenants in the credit agreement;
	●	cross-default to other indebtedness;
	●	bankruptcy or insolvency;
	●	failure to have adequate resources to maintain, and obtain, operating permits as necessary to conduct our operations substantially as contemplated by the mining plans used in preparing the financial projections; and
	●	a change of control.

 

Any subsequent refinancing of our current debt or any new debt could have similar restrictions. Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders could seek to foreclose on such assets.

 

 

EXHIBIT B

 

INDEX TO FINANCIAL STATEMENTS

RHINO RESOURCE PARTNERS LP
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Statements of Financial Position as of December 31, 2015 and 2014	F-3
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015 and 2014	F-4
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2015 and 2014	F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015 and 2014	F-7
Notes to Consolidated Financial Statements	F-8

 

 

Table of Contents

 

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of

the Managing General Partner

and the Partners of

Rhino Resource Partners LP

Lexington, Kentucky

 

We have audited the accompanying consolidated statements of financial position of Rhino Resource Partners LP and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations and comprehensive income, partners’ capital and cash flows for each of the two years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’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 Rhino Resource Partners LP and subsidiaries at December 31, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

 

The accompanying consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the classification of the Partnership’s credit facility balance as a current liability and resulting working capital deficit raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ ERNST & YOUNG, LLP

 

Louisville, Kentucky

March 25, 2016

 

 

Table of Contents

 

RHINO RESOURCE PARTNERS LP

 

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

(In thousands)

 

		As of December 31,
		2015				2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	78			$	626
Accounts receivable, net of allowance for doubtful accounts ($166 as of December 31, 2015 and $724 as of December 31, 2014)			14,569				22,467
Inventories			8,570				13,030
Advance royalties, current portion			753				1,032
Prepaid expenses and other			5,474				3,974
Total current assets			29,444				41,129
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs			604,514				663,662
Less accumulated depreciation, depletion and amortization			(271,007	)			(280,225	)
Net property, plant and equipment			333,507				383,437
Advance royalties, net of current portion			7,326				1,363
Investment in unconsolidated affiliates			7,578				20,653
Intangible assets, net			505				1,067
Other non-current assets			26,307				16,410
Non-current assets held for sale			—				9,279
TOTAL		$	404,667			$	473,338
​			​  ​  ​				​  ​  ​
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	9,336			$	10,924
Accrued expenses and other			14,102				17,334
Current portion of long-term debt			41,479				210
Current portion of asset retirement obligations			767				1,431
Current portion of postretirement benefits			45				425
Total current liabilities			65,729				30,324
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion			2,595				57,222
Asset retirement obligations, net of current portion			22,980				28,452
Other non-current liabilities			45,435				27,942
Postretirement benefits, net of current portion			—				6,223
Non-current liabilities held for sale			—				2,250
Total non-current liabilities			71,010				122,089
Total liabilities			136,739				152,413
COMMITMENTS AND CONTINGENCIES (NOTE 15)
PARTNERS’ CAPITAL:
Limited partners			253,312				308,586
General partner			9,821				10,966
Accumulated other comprehensive income			4,795				1,373
Total partners’ capital			267,928				320,925
TOTAL		$	404,667			$	473,338

 

See notes to consolidated financial statements.

 

 

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RHINO RESOURCE PARTNERS LP

 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

 

(In thousands, except per unit data)

 

		Year Ended December 31,
		2015				2014
REVENUES:
Coal sales		$	171,074			$	202,881
Freight and handling revenues			2,790				2,020
Other revenues			32,882				34,156
Total revenues			206,746				239,057
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			175,499				200,141
Freight and handling costs			2,693				1,877
Depreciation, depletion and amortization			33,181				37,233
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)			15,446				19,226
Asset impairment and related charges			31,564				45,296
(Gain) on sale/disposal of assets, net			(292	)			(569	)
Total costs and expenses			258,091				303,204
(LOSS) FROM OPERATIONS			(51,345	)			(64,147	)
INTEREST AND OTHER (EXPENSE)/INCOME:
Interest expense and other			(5,001	)			(5,708	)
Interest income and other			38				274
Equity in net income/(loss) of unconsolidated affiliates			342				(11,712	)
Total interest and other (expense)			(4,621	)			(17,146	)
(LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS			(55,966	)			(81,293	)
INCOME TAXES			—				—
NET (LOSS) FROM CONTINUING OPERATIONS			(55,966	)			(81,293	)
DISCONTINUED OPERATIONS
Income from discontinued operations			722				130,342
NET (LOSS)/INCOME			(55,244	)			49,049
Other comprehensive income:
Change in actuarial gain under ASC Topic 815			3,422				(858	)
COMPREHENSIVE (LOSS)/INCOME		$	(51,822	)		$	48,191
​			​ ​ ​				​ ​ ​
General partner’s interest in net (loss)/income:
Net (loss) from continuing operations		$	(1,119	)		$	(1,626	)
Net income from discontinued operations			14				2,607
General partner’s interest in net (loss)/income		$	(1,105	)		$	981

 

See notes to consolidated financial statements.

 

 

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RHINO RESOURCE PARTNERS LP

 

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Continued)

 

(In thousands, except per unit data)

 

		Year Ended December 31,
		2015				2014
Common unitholders’ interest in net (loss)/income:
Net (loss)/income from continuing operations		$	(31,491	)		$	(45,705	)
Net income from discontinued operations			406				73,271
Common unitholders’ interest in net (loss)/income		$	(31,085	)		$	27,566
Subordinated unitholders’ interest in net (loss)/income:
Net (loss)/income from continuing operations		$	(23,356	)		$	(33,962	)
Net income from discontinued operations			302				54,464
Subordinated unitholders’ interest in net (loss)/income		$	(23,054	)		$	20,502
Net (loss)/income per limited partner unit, basic:
Common units:
Net (loss) per unit from continuing operations		$	(1.87	)		$	(2.32	)
Net income per unit from discontinued operations			0.02				4.39
Net (loss)/income per common unit, basic		$	(1.85	)		$	2.07
Subordinated units
Net (loss) per unit from continuing operations		$	(1.89	)		$	(3.31	)
Net income per unit from discontinued operations			0.02				4.39
Net (loss)/income per subordinated unit, basic		$	(1.87	)		$	1.08
Net (loss)/income per limited partner unit, diluted:
Common units
Net (loss) per unit from continuing operations		$	(1.87	)		$	(2.32	)
Net income per unit from discontinued operations			0.02				4.39
Net (loss)/income per common unit, diluted		$	(1.85	)		$	2.07
Subordinated units
Net (loss)/income per unit from continuing operations		$	(1.89	)		$	(3.31	)
Net income per unit from discontinued operations			0.02				4.39
Net (loss)/income per subordinated unit, diluted		$	(1.87	)		$	1.08
Distributions paid per limited partner unit(1)		$	0.07			$	1.385
Weighted average number of limited partner units outstanding, basic:
Common units			16,714				16,678
Subordinated units			12,396				12,397
Weighted average number of limited partner units outstanding, diluted:
Common units			16,714				16,685
Subordinated units			12,396				12,397

 

(1)	No distributions were paid on the subordinated units during 2015 and 2014.

 

See notes to consolidated financial statements.

 

 

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RHINO RESOURCE PARTNERS LP

 

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

(In thousands)

 

		Limited Partner																				Accumulated
		Common								Subordinated								General				Other				Total
		Units				Capital				Units				Capital				Partner Capital				Comprehensive Income/(Loss)				Partners’ Capital
BALANCE—December 31, 2013			16,660			$	180,702				12,397			$	102,637			$	10,801			$	2,231			$	296,371
Net income			—				27,566				—				20,502				981				—				49,049
Distributions to unitholders and general partner			—				(23,140	)			—				—				(822	)			—				(23,962	)
General partners’ contributions			—				—				—				—				6				—				6
Offering costs			—				(2	)			—				—				—				—				(2	)
Issuance of units under LTIP			25				321				—				—				—				—				321
Change in actuarial gain under ASC Topic 815			—				—				—				—				—				(858	)			(858	)
BALANCE—December 31, 2014			16,685			$	185,447				12,397			$	123,139			$	10,966			$	1,373			$	320,925
Net income			—				(31,085	)			—				(23,054	)			(1,105	)			—				(55,244	)
Distributions to unitholders and general partner			—				(1,225	)			—				—				(42	)			—				(1,267	)
General partners’ contributions			—				—				—				—				2				—				2
Surrender of subordinated units by unitholder			—				—				(42	)			—				—				—				—
Issuance of units under LTIP			74				90				—				—				—				—				90
Change in actuarial gain under ASC Topic 815			—				—				—				—				—				3,422				3,422
BALANCE—December 31, 2015			16,759			$	153,227				12,355			$	100,085			$	9,821			$	4,795			$	267,928

 

See notes to consolidated financial statements.

 

 

Table of Contents

 

RHINO RESOURCE PARTNERS LP

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(In thousands)

 

		Year Ended December 31,
		2015				2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)/income		$	(55,244	)		$	49,049
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			33,181				37,233
Accretion on asset retirement obligations			2,082				2,281
Accretion on interest-free debt			48				—
Amortization of deferred revenue			(3,766	)			(1,731	)
Amortization of advance royalties			764				440
Amortization of debt issuance costs			1,419				2,127
Amortization of actuarial gain			(782	)			(368	)
Provision for doubtful accounts			528				724
Equity in net (income)/loss of unconsolidated affiliates			(342	)			11,712
Distributions from unconsolidated affiliate			232				—
Loss on retirement of advance royalties			151				244
(Gain) on sale/disposal of assets—net			(1,014	)			(130,621	)
Loss on impairment of assets			31,564				45,296
Equity-based compensation			15				255
Changes in assets and liabilities:
Accounts receivable			7,148				634
Inventories			4,460				5,550
Advance royalties			(1,518	)			(1,453	)
Prepaid expenses and other assets			656				485
Accounts payable			(2,274	)			(1,731	)
Accrued expenses and other liabilities			(1,026	)			2,841
Asset retirement obligations			321				(1,824	)
Postretirement benefits			(2,398	)			38
Net cash provided by operating activities			14,205				21,181
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment			(13,168	)			(62,986	)
Proceeds from sales of property, plant, and equipment			15,114				189,618
Return of capital from unconsolidated affiliate			35				—
Principal payments received on notes receivable			—				205
Investment in unconsolidated affiliates			—				(10,096	)
Net cash provided by investing activities			1,981				116,741
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit			94,400				170,040
Repayments on line of credit			(107,650	)			(282,630	)
Repayments on long-term debt			(157	)			(1,024	)
Payments on debt issuance costs			(2,062	)			(103	)
Payment of offering costs			—				(2	)
Net settlement of withholding taxes on employee unit awards vesting			—				(44	)
General partner’s contributions			2				6
Distributions to unitholders			(1,267	)			(23,962	)
Net cash (used in) financing activities			(16,734	)			(137,719	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS			(548	)			203
CASH AND CASH EQUIVALENTS—Beginning of period			626				423
CASH AND CASH EQUIVALENTS—End of period		$	78			$	626

 

See notes to consolidated financial statements.

 

 

Table of Contents

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

1. ORGANIZATION AND BASIS OF PRESENTATION

 

Organization—Rhino Resource Partners LP and subsidiaries (the “Partnership”) is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor” or the “Operating Company”). The Partnership had no operations during the period from April 19, 2010 (date of inception) to October 5, 2010 (the consummation of the initial public offering (“IPO”) date of the Partnership). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Kentucky, Ohio, West Virginia and Utah. The majority of the Partnership’s sales are made to electric utilities and other coal-related organizations in the United States. In addition to operating coal properties, the Partnership manages and leases coal properties and collects royalties from such management and leasing activities. In addition to the Partnership’s coal operations, the Partnership has invested in oil and natural gas mineral rights and operations that have provided revenues to the Partnership.

 

Initial Public Offering

 

On October 5, 2010, Rhino Resource Partners LP completed its IPO of 3,244,000 common units, representing limited partner interests in the Partnership, at a price of $20.50 per common unit. Net proceeds from the offering were approximately $58.3 million, after deducting underwriting discounts and offering expenses of $8.2 million. The Partnership used the net proceeds from this offering, and a related capital contribution by Rhino GP LLC, the Partnership’s general partner (the “General Partner”) of approximately $10.4 million, to repay approximately $69.4 million of outstanding indebtedness under the Operating Company’s credit facility. These net proceeds do not include $9.3 million that was used to reimburse affiliates of the Partnership’s sponsor, Wexford Capital LP (“Wexford Capital”), for capital expenditures incurred with respect to the assets contributed to the Partnership in connection with the offering. In connection with the closing of the IPO, the owners of the Operating Company contributed their membership interests in the Operating Company to the Partnership, and the Partnership issued 12,397,000 subordinated units representing limited partner interests in the Partnership and 9,153,000 common units to Rhino Energy Holdings LLC, an affiliate of Wexford Capital, and issued incentive distribution rights to the General Partner. Upon the closing of the IPO, and as required by the Operating Company’s credit agreement by and among the Operating Company, as borrower, and its subsidiaries as guarantors, and PNC Bank, National Association, as agent, and the other lenders thereto (as amended from time to time, the “Credit Agreement”), the Partnership pledged 100% of the membership interests in the Operating Company to the agent on behalf of itself and the other lenders to secure the Operating Company’s obligations under the Credit Agreement.

 

Follow-on Offerings

 

On July 18, 2011, the Partnership completed a public offering of 2,875,000 common units, representing limited partner interests in the Partnership, at a price of $24.50 per common unit. Of the common units issued, 375,000 units were issued in connection with the exercise of the underwriters’ option to purchase additional units. Net proceeds from the offering were approximately $66.4 million, after deducting underwriting discounts and offering expenses of approximately $4.1 million. The Partnership used the net proceeds from this offering, and a related capital contribution by the General Partner of approximately $1.4 million, to repay approximately $67.8 million of outstanding indebtedness under the Partnership’s credit facility.

 

 

Table of Contents

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

1. ORGANIZATION AND BASIS OF PRESENTATION (Continued)

 

On September 13, 2013, the Partnership completed a public offering of 1,265,000 common units, representing limited partner interests in the Partnership, at a price of $12.30 per common unit. Of the common units issued, 165,000 units were issued in connection with the exercise of the underwriter’s option to purchase additional units. Net proceeds from the offering were approximately $14.6 million, after deducting underwriting discounts and offering expenses of approximately $1.0 million. The Partnership used the net proceeds from this offering, and a related capital contribution by the General Partner of approximately $0.3 million, to repay approximately $14.9 million of outstanding indebtedness under the Partnership’s credit facility.

 

Basis of Presentation and Principles of Consolidation—The accompanying consolidated financial statements include the accounts of Rhino Resource Partners LP and its subsidiaries. Intercompany transactions and balances have been eliminated in consolidation.

 

Debt Classification—The Partnership evaluated its amended and restated senior secured credit facility at December 31, 2015 to determine whether this debt liability should be classified as a long-term or current liability on the Partnership’s consolidated statements of financial position. In April 2015, the Partnership entered into a third amendment to its amended and restated senior secured credit facility (see Note 10 for further details of the third amendment). The third amendment extended the expiration date of the amended and restated credit agreement to July 2017. The extension was contingent upon (i) the Partnership’s leverage ratio being less than or equal to 2.75 to 1.0 and (ii) the Partnership having liquidity greater than or equal to $15 million, in each case for either the quarter ending December 31, 2015 or March 31, 2016. If both of these conditions were not satisfied for one of such quarters, the expiration date of the amended and restated credit agreement would revert to July 2016. As of December 31, 2015, the conditions for the extension of the credit facility were not met as the Partnership’s leverage ratio was 3.2 to 1.0 and liquidity was approximately $1.1 million. In March 2016, the Partnership amended its amended and restated senior secured credit facility where the expiration date was set to July 2016. The Partnership is working with its lenders to extend the amended and restated credit agreement to December 2017. Since the credit facility has an expiration date of July 2016, the Partnership determined that its credit facility debt liability of $41.2 million at December 31, 2015 should be classified as a current liability on its consolidated statements of financial position, which results in a working capital deficiency of $36.3 million. The classification of the Partnership’s credit facility balance as a current liability raises substantial doubt of the Partnership’s ability to continue as a going concern for the next twelve months. The Partnership is also considering alternative financing options that could result in a new long-term credit facility. Since the credit facility has an expiration date of July 2016, the Partnership will have to secure alternative financing to replace its credit facility by the expiration date of July 2016 in order to continue its normal business operations and meet its obligations as they come due. The financial statements do not include any adjustments relating to the recoverability and classification of assets carrying amounts or the amount of and classification of liabilities that may result should the Partnership be unable to continue as a going concern.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

 

Company Environment and Risk Factors. The Partnership, in the course of its business activities, is exposed to a number of risks including: fluctuating market conditions of coal, truck and rail transportation, fuel costs, changing government regulations, unexpected maintenance and equipment failure, employee benefits cost control, changes in estimates of proven and probable coal reserves, as well as the ability of the Partnership to maintain adequate financing, necessary mining permits and control of sufficient recoverable coal properties. In addition, adverse weather and geological conditions may increase mining costs, sometimes substantially.

 

 

Table of Contents

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

  

Trade Receivables and Concentrations of Credit Risk. See Note 17 for discussion of major customers. The Partnership does not require collateral or other security on accounts receivable. The credit risk is controlled through credit approvals and monitoring procedures.

 

During 2015 and 2014, the Partnership recorded accounts receivable allowances of approximately $0.5 million and $0.7 million, respectively, in relation to customers that had entered bankruptcy proceedings. The Partnership recorded these allowances based upon its best estimates of the ultimate collectability of the accounts receivable balances through the bankruptcy proceedings of these customers. As of December 31, 2015, the Partnership had accounts receivable allowances of approximately $0.2 million outstanding for remaining accounts that were estimated to be uncollectable.

 

Cash and Cash Equivalents. The Partnership considers all highly liquid investments purchased with original maturities of three months or less to be cash equivalents.

 

Inventories. Inventories are stated at the lower of cost, based on a three month rolling average, or market. Inventories primarily consist of coal contained in stockpiles.

 

Advance Royalties. The Partnership is required, under certain royalty lease agreements, to make minimum royalty payments whether or not mining activity is being performed on the leased property. These minimum payments may be recoupable once mining begins on the leased property. The Partnership capitalizes the recoupable minimum royalty payments and amortizes the deferred costs once mining activities begin on the units-of-production method or expenses the deferred costs when the Partnership has ceased mining or has made a decision not to mine on such property.

 

Notes Receivable. In December 2015, the Partnership completed the sale of the Deane mining complex located in Central Appalachia (see Note 6 for further details on the Deane mining complex sale). The Partnership received $2.0 million for the Deane mining complex sale in the form of a note receivable from the third-party purchaser. The note receivable bears interest at an annual rate of 6% and has a maturity date of December 31, 2017. The note receivable was recorded in the Other non-current assets line of the Partnership’s consolidated statements of financial positon.

 

In August 2011, the Partnership closed on an agreement to sell and assign certain non-core mining assets and related liabilities located in the Phelps, KY area to a third party. The mining assets included leasehold interests and permits to surface and mineral interests that included steam coal reserves and non-reserve coal deposits. Additionally, the sales agreement included the potential for additional payments of approximately $8.75 million dependent upon certain future contingencies. Rhino recorded the sale of the assets and transfer of liabilities in the third quarter of 2011, but did not record any of the potential $8.75 million consideration since this amount relied on future contingent conditions to be met before it could be recognized. In 2014, the third party entered negotiations with the Partnership regarding the payment of the $8.75 million consideration as the third party anticipated the contingencies would be met in the near future. The third party negotiated with the Partnership to accept a note receivable in lieu of immediate payment since the third party did not have the available funds to pay the $8.75 million consideration. The Partnership believes the collection of the $8.75 million is in doubt due to the necessity of the third party to request a note receivable and the belief that the third party will not be able to economically mine this property for an extended period due to the lack of certain mining permits. Based on the uncertainty of collection of the note receivable, the Partnership recorded a note receivable balance along with a corresponding allowance against the entire $8.75 million note receivable balance. During 2015 and 2014, the Partnership received approximately $0.6 million and $0.3 million, respectively, in payments related to this note receivable and the balance at December 31, 2015 was $7.9 million, which remained fully reserved based on the factors discussed above.

 

 

Table of Contents

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

Property, Plant and Equipment. Property, plant, and equipment, including coal properties, oil and natural gas properties, mine development costs and construction costs, are recorded at cost, which includes construction overhead and interest, where applicable. Expenditures for major renewals and betterments are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Mining and other equipment and related facilities are depreciated using the straight-line method based upon the shorter of estimated useful lives of the assets or the estimated life of each mine. Coal properties are depleted using the units-of-production method, based on estimated proven and probable reserves. Mine development costs are amortized using the units-of-production method, based on estimated proven and probable reserves. The Partnership assumes zero salvage values for its property, plant and equipment when depreciation and amortization are calculated. Gains or losses arising from sales or retirements are included in current operations.

 

Stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal that will be extracted are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. The Partnership defines a surface mine as a location where the Partnership utilizes operating assets necessary to extract coal, with the geographic boundary determined by property control, permit boundaries, and/or economic threshold limits. Multiple pits that share common infrastructure and processing equipment may be located within a single surface mine boundary, which can cover separate coal seams that typically are recovered incrementally as the overburden depth increases. In accordance with the accounting guidance for extractive mining activities, the Partnership defines a mine in production as one from which saleable minerals have begun to be extracted (produced) from an ore body, regardless of the level of production; however, the production phase does not commence with the removal of de minimis saleable mineral material that occurs in conjunction with the removal of overburden or waste material for the purpose of obtaining access to an ore body. The Partnership capitalizes only the development cost of the first pit at a mine site that may include multiple pits.

 

 

Table of Contents

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

Asset Impairments for Coal Properties, Mine Development Costs and Other Coal Mining Equipment and Related Facilities. The Partnership follows the accounting guidance in Accounting Standards Codification (“ASC”) 360, Property, Plant and Equipment, on the impairment or disposal of property, plant and equipment for its coal mining assets, which requires that projected future cash flows from use and disposition of assets be compared with the carrying amounts of those assets when potential impairment is indicated. When the sum of projected undiscounted cash flows is less than the carrying amount, impairment losses are recognized. In determining such impairment losses, the Partnership must determine the fair value for the coal mining assets in question in accordance with the applicable fair value accounting guidance. Once the fair value is determined, the appropriate impairment loss must be recorded as the difference between the carrying amount of the coal mining assets and their respective fair values. Also, in certain situations, expected mine lives are shortened because of changes to planned operations or changes in coal reserve estimates. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closing obligations are accelerated and the mine closing accrual is increased accordingly. To the extent it is determined that coal asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized. During 2015 and 2014, the Partnership recorded $31.1 million and $45.3 million, respectively, of asset impairment losses and related charges associated with multiple coal properties that are further described in Note 6. The Partnership also recorded an impairment charge of $0.5 million during 2015 related to intangible assets that are discussed further in Note 7. The asset impairment losses and related charges are recorded on the Asset impairment and related charges line of the Partnership’s consolidated statements of operations and comprehensive income. The Partnership also recorded an impairment charge of $5.9 million during 2014 related to the Partnership’s equity investment in the Rhino Eastern joint venture that is discussed further in Note 3. The impairment charge for the Rhino Eastern joint venture is recorded on the Equity in net (loss)/income of unconsolidated affiliates line of the Partnership’s consolidated statements of operations and comprehensive income.

 

Debt Issuance Costs. Debt issuance costs reflect fees incurred to obtain financing and are amortized (included in interest expense) using the effective interest method over the life of the related debt. Debt issuance costs are included in Prepaid expenses and other current assets as of December 31, 2015 since the Partnership classified its credit facility balance as a current liability (see Note 1). As of December 31, 2014, debt issuance costs were included in other non-current assets. In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility that reduced the borrowing capacity to $200 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, which was recorded as an addition to Debt issuance costs. In addition, the Partnership wrote-off approximately $1.1 million of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility. In April 2015, the Partnership entered into a third amendment of its amended and restated senior secured credit facility that further reduced the borrowing commitment to $100 million. As part of executing the third amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $2.1 million to the lenders in April 2015, which was recorded as an addition to Debt issuance costs. The Partnership wrote-off approximately $0.2 million of its remaining unamortized debt issuance costs since the third amendment further reduced the borrowing commitment under the amended and restated senior secured credit facility. See Note 10 for further information on the amendment to the amended and restated senior secured credit facility.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

Asset Retirement Obligations. The accounting guidance for asset retirement obligations addresses asset retirement obligations that result from the acquisition, construction or normal operation of long-lived assets. This guidance requires companies to recognize asset retirement obligations at fair value when the liability is incurred or acquired. Upon initial recognition of a liability, an amount equal to the liability is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The Partnership has recorded the asset retirement costs for its mining operations in coal properties.

 

The Partnership estimates its future cost requirements for reclamation of land where it has conducted surface and underground mining operations, based on its interpretation of the technical standards of regulations enacted by the U.S. Office of Surface Mining, as well as state regulations. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at underground mines. Other reclamation costs are related to refuse and slurry ponds, as well as holding and related termination/exit costs.

 

The Partnership expenses contemporaneous reclamation which is performed prior to final mine closure. The establishment of the end of mine reclamation and closure liability is based upon permit requirements and requires significant estimates and assumptions, principally associated with regulatory requirements, costs and recoverable coal reserves. Annually, the Partnership reviews its end of mine reclamation and closure liability and makes necessary adjustments, including mine plan and permit changes and revisions to cost and production levels to optimize mining and reclamation efficiency. When a mine life is shortened due to a change in the mine plan, mine closing obligations are accelerated, the related accrual is increased and the related asset is reviewed for impairment, accordingly.

 

The adjustments to the liability from annual recosting reflect changes in expected timing, cash flow and the discount rate used in the present value calculation of the liability. Each respective year includes a range of discount rates that are dependent upon the timing of the cash flows of the specific obligations. Changes in the asset retirement obligations for the year ended December 31, 2015 were calculated with discount rates that ranged from 2.9% to 5.9%. Changes in the asset retirement obligations for the year ended December 31, 2014 were calculated with discount rates that ranged from 1.6% to 5.3%. The discount rates changed in each respective year due to changes in applicable market indicators that are used to arrive at an appropriate discount rate. Other recosting adjustments to the liability are made annually based on inflationary cost increases or decreases and changes in the expected operating periods of the mines. The related inflation rate utilized in the recosting adjustments was 2.3% for 2015 and 2014.

 

Workers’ Compensation Benefits. Certain of the Partnership’s subsidiaries are liable under federal and state laws to pay workers’ compensation and coal workers’ pneumoconiosis (“black lung”) benefits to eligible employees, former employees and their dependents. The Partnership currently utilizes an insurance program and state workers’ compensation fund participation to secure its on-going obligations depending on the location of the operation. Premium expense for workers’ compensation benefits is recognized in the period in which the related insurance coverage is provided.

 

The Partnership’s black lung benefit liability is calculated using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation. The actuarial calculations using the service cost method for the Partnership’s black lung benefit liability are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

In addition, the Partnership’s liability for traumatic workers’ compensation injury claims is the estimated present value of current workers’ compensation benefits, based on actuarial estimates. The actuarial estimates for the Partnership’s workers’ compensation liability are based on numerous assumptions including claim development patterns, mortality, medical costs and interest rates.

 

See Note 12 for more information on the Partnership’s workers’ compensation and black lung liabilities and expense.

 

Revenue Recognition. Most of the Partnership’s revenues are generated under long-term coal sales contracts with electric utilities, industrial companies or other coal-related organizations, primarily in the eastern United States. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales agreement. Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation source that delivers coal to its destination. Advance payments received are deferred and recognized in revenue as coal is shipped and title has passed.

 

Coal sales revenues also result from the sale of brokered coal produced by others. The revenues related to brokered coal sales are included in coal sales revenues on a gross basis and the corresponding cost of the coal from the supplier is recorded in cost of coal sales in accordance with the revenue recognition accounting guidance on principal agent considerations.

 

Freight and handling costs paid directly to third-party carriers and invoiced to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively.

 

Other revenues generally consist of coal royalty revenues, limestone sales, coal handling and processing, oil and natural gas royalty revenues, rebates and rental income. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership’s lessees and the corresponding gross revenues from those sales. The leases are based on (1) minimum monthly or annual payments, (2) a minimum dollar royalty per ton and/or a percentage of the gross sales price, or (3) a combination of both. Coal royalty revenues are recorded from royalty reports submitted by the lessee, which are reconciled and subject to audit by the Partnership. Most of the Partnership’s lessees are required to make minimum monthly or annual royalty payments that are recoupable over certain time periods, generally two years. If tonnage royalty revenues do not meet the required minimum amount, the difference is paid as a deficiency. These deficiency payments received are recognized as an unearned revenue liability because they are generally recoupable over certain time periods. When a lessee recoups a deficiency payment through production, the recouped amount is deducted from the unearned revenue liability and added to revenue attributable to the coal royalty revenue in the current period. If a lessee does not recoup a deficiency paid during the allocated time period, the recoupment right lost becomes revenue in the current period and is deducted from the liability.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

With respect to other revenues recognized in situations unrelated to the shipment of coal or coal royalties, the Partnership carefully reviews the facts and circumstances of each transaction and does not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the seller’s price to the buyer is fixed or determinable and collectibility is reasonably assured. Advance payments received are deferred and recognized in revenue when earned.

 

Equity-Based Compensation. The Partnership applies the provisions of ASC Topic 718 to account for any unit awards granted to employees or directors. This guidance requires that all share-based payments to employees or directors, including grants of stock options, be recognized in the financial statements based on their fair value. The General Partner has currently granted restricted units and phantom units to directors and certain employees of the General Partner and Partnership that contain only a service condition. The fair value of each restricted unit and phantom unit award was calculated using the closing price of the Partnership’s common units on the date of grant.

 

The Compensation Committee of the board of directors of the General Partner has historically elected to pay some of the awards in cash or a combination of cash and common units. This policy has resulted in all employee awards being classified as liabilities and, thus, the employee awards are required to be marked-to-market each reporting period until they are vested. Restricted unit awards granted to directors of the General Partner are considered nonemployee equity-based awards since the directors are not elected by unitholders. Thus, these director awards are also required to be marked-to-market each reporting period until they are vested. Expense related to unit awards is recorded in the selling, general and administrative line of the Partnership’s consolidated statements of operations and comprehensive income.

 

Derivative Financial Instruments. On occasion, the Partnership has used diesel fuel contracts to manage the risk of fluctuations in the cost of diesel fuel. The Partnership’s diesel fuel contracts have met the requirements for the normal purchase normal sale (“NPNS”) exception prescribed by the accounting guidance on derivatives and hedging, based on management’s intent and ability to take physical delivery of the diesel fuel. The Partnership did not have any diesel fuel contracts as of December 31, 2015.

 

Investments in Joint Ventures. Investments in joint ventures are accounted for using the equity method or cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Partnership is determined to be the primary beneficiary of a variable interest entity. Equity investments are recorded at original cost and adjusted periodically to recognize the Partnership’s proportionate share of the investees’ net income or losses after the date of investment. Any losses from the Partnership’s equity method investment are absorbed by the Partnership based upon its proportionate ownership percentage. If losses are incurred that exceed the Partnership’s investment in the equity method entity, then the Partnership must continue to record its proportionate share of losses in excess of its investment. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.

  

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

In May 2008, the Operating Company entered into a joint venture, Rhino Eastern, with an affiliate of Patriot to acquire the Eagle mining complex. To initially capitalize the Rhino Eastern joint venture, the Operating Company contributed approximately $16.1 million for a 51% ownership interest in the joint venture and accounted for the investment in Rhino Eastern and its results of operations under the equity method. The Partnership considered the operations of this entity to comprise a reporting segment (“Eastern Met”) and has provided additional detail related to this operation in Note 21, “Segment Information.”

 

On December 31, 2014, the Partnership entered into an agreement with a wholly owned subsidiary of Patriot that effectively terminated the Rhino Eastern joint venture. This agreement officially closed in January 2015 and is described further in Note 3.

 

The Partnership determined it was not the primary beneficiary of the variable interest entity for the year ended December 31, 2014 by performing a qualitative and quantitative analysis based on the controlling economic interests of the Rhino Eastern joint venture. This included an analysis of the expected economic contributions of the joint venture. The Partnership concluded that it was not the primary beneficiary of Rhino Eastern primarily because of certain contractual arrangements by the joint venture with Patriot and the fact that the Rhino Eastern joint venture was managed by a committee of an equal number of representatives from Patriot and us.

 

As of December 31, 2014, the Partnership recorded its equity method investment of $13.2 million in the Rhino Eastern joint venture as a long-term asset. See Note 3 for a discussion of the impairment charge incurred on the Partnership’s equity method investment as of December 31, 2014. During 2014, the Partnership contributed additional capital based upon its ownership share to the Rhino Eastern joint venture in the amount of $4.8 million.

 

In December 2012, the Partnership made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States. During 2014, the Partnership contributed additional capital based upon its ownership share to the Muskie joint venture in the amount of $0.2 million. As disclosed in Note 19 “Related Party and Affiliate Transactions”, during 2013 the Partnership provided a loan to Muskie totaling approximately $0.2 million which was fully repaid in November 2014 in conjunction with the Partnership’s contribution of its interest in Muskie to Mammoth Energy Partners LP (“Mammoth”), which is discussed below.

 

In November 2014, the Partnership contributed its investment interest in Muskie to Mammoth in return for a limited partner interest in Mammoth. Mammoth was formed to own various companies that provide services to companies who engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth’s companies provide services that include completion and production services, contract land and directional drilling services and remote accommodation services. The non-cash transaction was a contribution of the Partnership’s investment interest in the Muskie entity for an investment interest in Mammoth. Thus, the Partnership determined that the non-cash exchange of the Partnership’s ownership interest in Muskie did not result in any gain or loss. Prior to the Partnership’s contribution of Muskie to Mammoth, the Partnership recorded its proportionate portion of Muskie’s operating loss for 2014 of approximately $0.1 million. As of December 31, 2015 and 2014, the Partnership has recorded its investment in Mammoth of $1.9 million as a long-term asset, which the Partnership has accounted for as a cost method investment based upon its ownership percentage. The Partnership has included its investment in Mammoth and its prior investment in Muskie in its Other category for segment reporting purposes. See Note 21 for information on the Partnership’s reportable segments.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

In September 2014, the Partnership made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC (“Sturgeon”), with affiliates of Wexford Capital and Gulfport. Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. The Partnership accounts for the investment in this joint venture and results of operations under the equity method based upon its ownership percentage. The Partnership recorded its proportionate portion of the operating income for this investment during 2015 and 2014 of approximately $0.3 million and $0.4 million, respectively. The Partnership has recorded its investment in Sturgeon on the Investment in unconsolidated affiliates line of the Partnership’s consolidated statements of financial position. The Partnership has included its investment in Sturgeon in its Other category for segment reporting purposes.

 

Income Taxes. The Partnership is considered a partnership for income tax purposes. Accordingly, the partners report the Partnership’s taxable income or loss on their individual tax returns.

 

Loss Contingencies. In accordance with the guidance on accounting for contingencies, the Partnership records loss contingencies at such time that an unfavorable outcome becomes probable and the amount can be reasonably estimated. When the reasonable estimate is a range, the recorded loss is the best estimate within the range. If no amount in the range is a better estimate than any other amount, the minimum amount of the range is recorded. The Partnership discloses information concerning loss contingencies for which an unfavorable outcome is probable. See Note 15, “Commitments and Contingencies,” for a discussion of such matters.

 

Management’s Use of Estimates. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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 as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

Recently Issued Accounting Standards. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). ASU 2014-09 clarifies the principles for recognizing revenue and establishes a common revenue standard for U.S. financial reporting purposes. The guidance in ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). ASU 2014-09 supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific accounting guidance. Additionally, ASU 2014-09 supersedes some cost guidance included in ASC 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of ASC 360, Property, Plant, and Equipment, and intangible assets within the scope of ASC 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in ASU 2014-09. In July 2015, the FASB approved to defer the effective date of ASU 2014-09 by one year. Accordingly, ASU 2014-09 will be effective for public entities for annual reporting periods beginning after December 15, 2017 and interim periods therein. The Partnership is currently evaluating the requirements of this new accounting guidance.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL (Continued)

 

In January 2015, the FASB issued ASU 2015-01, “Income Statement-Extraordinary and Unusual Items”. ASC 225-20, Income Statement—Extraordinary and Unusual Items, required that an entity separately classify, present, and disclose extraordinary events and transactions. ASU 2015-01 eliminates the concept of extraordinary items. The amendments in ASU 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity also may apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The effective date is the same for both public business entities and all other entities. The adoption of ASU 2015-01 on January 1, 2016 is not expected to have a material impact on the Partnership’s financial statements.

 

In February 2015, the FASB issued ASU 2015-02, “Consolidation”. ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, the amendments of ASU 2015-02: a) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, b) eliminate the presumption that a general partner should consolidate a limited partnership, c) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and d) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. ASU 2015-02 is effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. A reporting entity may apply the amendments in this Update using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. A reporting entity also may apply the amendments retrospectively. The adoption of ASU 2015-02 on January 1, 2016 is not expected to have a material impact on the Partnership’s financial statements.

 

In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30)-Simplifying the Presentation of Debt Issuance Costs”. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to ASU 2015-03, debt issuance costs have been presented in the balance sheet as a deferred charge, or asset. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. For public business entities, ASU 2015-03 is effective for financial statements issued for fiscal years

  

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

3. SUBSEQUENT EVENTS

 

For the quarter ended December 31, 2015, the Partnership continued the suspension of the cash distribution for its common units, which was initially suspended for the quarter ended June 30, 2015. No distribution will be paid for common or subordinated units for the quarter ended December 31, 2015. Pursuant to the Partnership’s partnership agreement, the Partnership’s common units accrue arrearages every quarter when the distribution level is below the minimum level of $0.445 per unit. The Partnership initially lowered its quarterly common unit distribution below the minimum level of $0.445 per unit with the quarter ended September 30, 2014. Thus, the Partnership’s distributions for each of the quarters ended September 30, 2014 through the current quarter ended December 31, 2015 were below the minimum level and the current amount of accumulated arrearages as of December 31, 2015 related to the common unit distribution is approximately $44.3 million.

 

On January 21, 2016, a definitive agreement (“Definitive Agreement”) was completed between Royal Energy Resources, Inc. (“Royal”) and Wexford where Royal acquired 6,769,112 issued and outstanding common units of the Partnership previously owned by Wexford for $3.5 million. The Definitive Agreement also included the committed acquisition by Royal within sixty days from the date of the Definitive Agreement of all of the issued and outstanding membership interests of Rhino GP LLC, the general partner of the Partnership, as well as 9,455,252 issued and outstanding subordinated units of the Partnership currently owned by Wexford for $1.0 million.

 

On March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of Rhino GP LLC as well as the 9,455,252 issued and outstanding subordinated units from Wexford. Royal obtained control of, and a majority limited partner interest, in the Partnership with the completion of this transaction.

 

On March 21, 2016, the Partnership and Royal entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant to which the Partnership issued 60,000,000 common units in the Partnership to Royal in a private placement at $0.15 per common unit for an aggregate purchase price of $9.0 million. Royal paid the Partnership $2.0 million in cash and delivered a promissory note payable to the Partnership in the amount of $7.0 million. The promissory note is payable in three installments: (i) $3.0 million on July 31, 2016; (ii) $2.0 million on or before September 30, 2016 and (iii) $2.0 million on or before December 31, 2016. In the event the disinterested members of the board of directors of the General Partner determine that the Partnership does not need the capital that would be provided by either or both installments set forth in (ii) and (iii) above, in each case, the Partnership has the option to rescind Royal’s purchase of 13,333,333 common units and the applicable installment will not be payable (each, a “Rescission Right”). If the Partnership fails to exercise a Rescission Right, in each case, the Partnership has the option to repurchase 13,333,333 common units at $0.30 per common unit from Royal (each, a “Repurchase Option”). The Repurchase Options terminate on December 31, 2017. Royal’s obligation to pay any installment of the promissory note is subject to certain conditions, including that the Operating Company has entered into an agreement to extend the Amended and Restated Credit Agreement, as amended, to a date no sooner than December 31, 2017. In the event such conditions are not satisfied as of the date each installment is due, Royal has the right to cancel the remaining unpaid balance of the promissory note in exchange for the surrender of such number of common units equal to the principal balance of the promissory note divided by $0.15.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

3. SUBSEQUENT EVENTS (Continued)

 

On March 17, 2016, the Operating Company, as borrower, and the Partnership and certain of its subsidiaries, as guarantors, entered into an amendment (the “Fourth Amendment”) of its amended and restated credit agreement, dated July 29, 2011, as amended by the first, second and third amendments thereto, with PNC Bank, National Association, as Administrative Agent, PNC Capital Markets and Union Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners, Union Bank, N.A., as Syndication Agent, Raymond James Bank, FSB, Wells Fargo Bank, National Association and the Huntington National Bank, as Co-Documentation Agents and the lenders party thereto. The Fourth Amendment amends the definition of change of control in the amended and restated credit agreement to permit Royal to purchase the membership interests of the General Partner and sets the expiration date of the facility at July 2016. The Fourth Amendment reduces the borrowing capacity under the credit facility to a maximum of $80 million and reduces the amount available for letters of credit to $30 million. The Fourth Amendment eliminates the option to borrow funds utilizing the LIBOR rate plus an applicable margin and establishes the borrowing rate for all borrowings under the facility to be based upon the current PRIME rate plus an applicable margin of 3.50%. The Fourth Amendment eliminates the capability to make Swing Loans under the facility and eliminates the ability of the Partnership to pay distributions to its common or subordinated unitholders. The Fourth Amendment alters the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve month basis, to 6.75 to 1.00. The leverage ratio shall be reduced by 0.50 to 1.00 for every $10 million of net cash proceeds, in the aggregate, received by the Partnership after the date of the Fourth Amendment from a liquidity event; provided, however, that in no event shall the maximum permitted leverage ratio be reduced below 3.00 to 1.00. A liquidity event is defined in the Fourth Amendment as the issuance of any equity by the Partnership on or after the Fourth Amendment effective date (other than the Royal equity contribution discussed above), or the disposition of any assets by the Partnership. The Fourth Amendment requires the Partnership to maintain minimum liquidity of $5 million and minimum EBITDA, calculated as of the end of the most recent month, on a trailing twelve month basis, of $8 million. The Fourth Amendment limits the amount of the Partnership’s capital expenditures to $15 million, calculated as of end of the most recent month, on a trailing twelve month basis. The Fourth Amendment requires the Partnership to provide monthly financial statements and a weekly rolling thirteen week cash flow forecast to the administrative agent.

 

4. DISCONTINUED OPERATIONS

 

Divestiture of Utica Shale Oil and Natural Gas Assets

 

Beginning in 2011, the Partnership and an affiliate of Wexford Capital participated with Gulfport to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. As of December 31, 2013, the Partnership had invested approximately $31.1 million for its pro rata interest in the Utica Shale portfolio of oil and natural gas leases, which consisted of a 5% interest in a total of approximately 152,300 gross acres, or approximately 7,615 net acres. In addition, per the joint operating agreement among the Partnership, Gulfport and an affiliate of Wexford Capital, the Partnership had funded its proportionate share of drilling costs to Gulfport for wells being drilled on the Partnership’s acreage. As of December 31, 2013, the Partnership had funded approximately $23.3 million of drilling costs.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

4. DISCONTINUED OPERATIONS (Continued)

 

In March 2014, the Partnership completed a purchase and sale agreement (the “Purchase Agreement”) with Gulfport to sell the Partnership’s oil and natural gas properties in the Utica Shale region for approximately $184.0 million (the “Purchase Price”). The Purchase Agreement was effective as of January 1, 2014 and the Purchase Price was adjusted for any unsettled expenditures made and/or proceeds received from the Partnership’s portion of its Utica Shale properties prior to the effective date. At the closing of the Purchase Agreement, the Partnership was immediately due approximately $179.0 million, net of any adjustments described above, and the remaining approximately $5.0 million was scheduled to be paid within approximately 90 days of March 20, 2014, subject to ongoing legal title work related to specific properties. In December 2014, the Partnership settled the remaining $5.0 million due from Gulfport based upon net amounts payable from the Partnership to Gulfport prior to the effective date of the Purchase Agreement as well as amounts due the Partnership related to legal reviews of the properties subject to the Purchase Agreement and other unsettled items due to the Partnership prior to the effective date of the Purchase Agreement. The net effect of this settlement resulted in the Partnership paying Gulfport approximately $46,000 in December 2014. The Partnership recorded a gain of approximately $121.7 million during the year ended December 31, 2014 related to this sale, which is recorded in Income from discontinued operations in the consolidated statements of operations and comprehensive income. The gain from the Utica Shale transaction is included in the (Gain) on sale/disposal of assets—net line in the operating activities section of the Partnership’s consolidated statements of cash flows. The proceeds from the Utica Shale transaction are included in the Proceeds from sales of property, plant, and equipment line in the investing activities section of the Partnership’s consolidated statements of cash flows.

 

Other Oil and Natural Gas Activities

 

In January 2014, the Partnership received approximately $8.4 million of net proceeds from the sale by Blackhawk Midstream LLC (“Blackhawk”) of its equity interest in two entities, Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, to Summit Midstream Partners, LLC. As part of the joint operating agreement for the Utica Shale investment discussed above, the Partnership had the right to approximately 5% of the proceeds of the sale by Blackhawk. In February 2015, the Partnership received approximately $0.7 million in additional proceeds from the sale by Blackhawk that had been held in escrow. For the years ended December 31, 2015 and 2014, the Partnership recorded the $0.7 million and $8.4 million, respectively, in Income from discontinued operations in the consolidated statements of operations and comprehensive income. The gain from the Blackhawk transaction is included in the (Gain) on sale/disposal of assets—net line in the operating activities section of the Partnership’s consolidated statements of cash flows. The proceeds from the Blackhawk transaction are included in the Proceeds from sales of property, plant, and equipment line in the investing activities section of the Partnership’s consolidated statements of cash flows.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

5. PREPAID EXPENSES AND OTHER CURRENT ASSETS

 

Prepaid expenses and other current assets as of December 31, 2015 and 2014 consisted of the following:

 

		December 31,
		2015				2014
		(in thousands)
Other prepaid expenses		$	682			$	827
Debt issuance costs—net			2,155				—
Prepaid insurance			1,492				2,063
Prepaid leases			80				87
Supply inventory			901				827
Deposits			164				170
Total		$	5,474			$	3,974

 

Debt issuance costs are included in Prepaid expenses and other current assets as of December 31, 2015 since the Partnership classified its credit facility balance as a current liability (see Note 1). As of December 31, 2014, debt issuance costs were included in other non-current assets (see Note8). Debt issuance costs were $11.6 million and $9.1 million as of December 31, 2015 and 2014, respectively. Accumulated amortization of debt issuance costs were $9.4 million and $7.6 million as of December 31, 2015 and 2014, respectively. In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility that reduced the borrowing capacity to $200 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, which was recorded as an addition to Debt issuance costs. In addition, the Partnership wrote-off approximately $1.1 million of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility.

 

In April 2015, the Partnership entered into a third amendment of its amended and restated senior secured credit facility that further reduced the borrowing commitment to $100 million. As part of executing the third amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $2.1 million to the lenders in April 2015, which was recorded as an addition to Debt issuance costs. The Partnership wrote-off approximately $0.2 million of its remaining unamortized debt issuance costs since the third amendment further reduced the borrowing commitment under the amended and restated senior secured credit facility. See Note 10 for further information on the amendments to the amended and restated senior secured credit facility.

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, including coal properties and mine development and construction costs, as of December 31, 2015 and 2014 are summarized by major classification as follows:

 

				December 31,
		Useful Lives		2015				2014
				(in thousands)
Land and land improvements				$	24,157			$	18,845
Mining and other equipment and related facilities		2 - 20 Years			306,609				336,951
Mine development costs		1 - 15 Years			67,277				79,536
Coal properties		1 - 15 Years			203,791				215,325
Oil and natural gas properties					—				8,093
Construction work in process					2,680				4,912
Total					604,514				663,662
Less accumulated depreciation, depletion and amortization					(271,007	)			(280,225	)
Net				$	333,507			$	383,437

 

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal and oil and natural gas properties, amortization expense for mine development costs, amortization expense for intangible assets and amortization expense for asset retirement costs for the years ended December 31, 2015 and 2014 was as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Depreciation expense-mining and other equipment and related facilities		$	28,740		$	30,529
Depletion expense for coal properties			2,871			4,633
Depletion expense for oil and natural gas properties			9			60
Amortization expense for mine development costs			1,935			1,737
Amortization expense for intangible assets			76			80
Amortization expense for asset retirement costs			(450	)		194
Total		$	33,181		$	37,233

 

Taylorville Land Sale

 

On December 30, 2015, the Partnership completed the sale of its land surface rights for the Taylorville property in central Illinois for approximately $7.2 million in net proceeds. The sale agreement allows the Partnership to retain the mining permit and control of the proven and probable coal reserves at the Taylorville property as the Partnership has the option to repurchase the rights to the land within seven years from the date of the sale agreement. In accordance with ASC 360-20-40-38, Real Estate Sales—Derecognition, since the Partnership has the option to repurchase the rights to the land, the transaction has been accounted for as a financing arrangement rather than a sale. The Taylorville property is recorded in the consolidated statements of financial position within the net property, plant and equipment caption and the related liability is recorded in the consolidated statements of financial position within the other noncurrent liability caption.

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

Asset Impairments-2015

 

As the prolonged weakness in the United States coal markets continued during 2015, the Partnership performed a comprehensive review of its current coal mining operations as well as potential future development projects to ascertain any potential impairment losses. The Partnership identified various properties, projects and operations that were potentially impaired based upon changes in its strategic plans, market conditions or other factors, specifically in Northern Appalachia where market conditions related to the Partnership’s operations deteriorated in the fourth quarter of 2015. The Partnership believes that an oversupply of coal being produced in Northern Appalachia has contributed to depressed coal prices from this region. The Partnership believes the oversupply of coal has been created due to historically low natural gas prices in this region, which competes with coal as a source of electricity generation. Utilities have chosen cheap natural gas for electricity generation over coal and, additionally, the Partnership believes the amount that the utilities’ power plants have been dispatched for electricity generation has fallen due to low electricity demand. The production of natural gas from the Utica Shale and Marcellus Shale regions that are located within the Northern Appalachian region have kept natural gas prices low and larger coal producers have low-cost long-wall mines in Northern Appalachia that can compete to sell lower priced coal to utilities that still require coal supplies in this region. The Partnership believes this combination of factors have decreased coal prices in Northern Appalachia to levels where certain current operations as well as future plans for the development of the Leesville Field will be unprofitable in the near term. In addition to impairment charges related to certain Northern Appalachia operations, the Partnership also recorded asset impairment and related charges for the sale of the Deane mining complex and the Cana Woodford oil and natural gas investment that are discussed further below. The Partnership recorded approximately $31.1 million of total asset impairment and related charges related to property, plant and equipment for the year ended December 31, 2015, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

Hopedale Mining Complex

 

The Partnership owns the Hopedale mining complex located in Northern Appalachia that includes an underground mine, preparation plant and full-service rail loadout facility. Hopedale had long-term coal sales contracts with two utility customers that officially expired at the end of 2015, but had carry-over provisions for contracted coal shipments that were not delivered in 2015 that are to be shipped in 2016. These carry-over tons under these sales contracts have prices well above current market levels for coal being sold in this region, but do not constitute annual coal sales volumes that Hopedale has historically been able to sell. The Partnership has been unsuccessful in securing any contracted sales business at profitable prices for Hopedale coal to replace these expiring sales contracts due to the depressed Northern Appalachia coal market conditions discussed above. Based upon these factors, the Partnership performed a detailed analysis of potential impairment for the Hopedale mining complex as of December 31, 2015. The Partnership’s projection of future undiscounted net cash flows to be generated from the Hopedale mining complex indicated that a potential impairment existed since the carrying amount of the long-lived asset group at the Hopedale mining complex exceeded the sum of the projected undiscounted net cash flows. Thus, the Partnership performed a further analysis to determine what, if any, impairment existed for the Hopedale mining complex asset group. The Partnership utilized a discounted cash flow method (i.e. income approach) to estimate the fair value of the Hopedale mining complex. Based on this analysis, the Partnership recorded total asset impairment and related charges of $19.0 million for the Hopedale mining complex for the year ended December 31, 2015.

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

Sands Hill Mining Complex

 

The Partnership owns the Sands Hill mining complex in Northern Appalachia that includes two surface coal mines located near Hamden, Ohio. The infrastructure at Sands Hill includes a coal preparation plant along with a river front barge and dock facility on the Ohio River. Coal produced at Sands Hill is primarily trucked to local industrial customers in the southeastern region of Ohio. In addition to coal production, limestone aggregate is also produced at Sands Hill as the process of removing overburden to access the coal seams includes the removal of high quality limestone. The Sands Hill complex includes limestone processing facilities that crush and size the limestone for sale to local customers. Sands Hill has contracted coal sales through the end of 2016 from its surface coal mine operations, but no contracted coal sales beyond this date. Limestone is sold on a non-contracted basis from Sands Hill’s operation.

 

During 2015, the Partnership contracted with a third party engineering firm to perform an audit of the Partnership’s coal mineral. As part of the third party expert’s audit, they performed an independent pro forma economic analysis using industry-accepted guidelines and these were used, in part, to classify coal mineral as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions. In the depressed Northern Appalachia coal market environment described above, a majority of the Sands Hill coal mineral that had previously been classified as proven and probable coal reserves was re-classified as non-reserve coal deposits as of December 31, 2015 due to unfavorable projected economic performance. The Partnership’s long-term plan had previously included the eventual development of underground coal reserves at Sands Hill, which were reclassified to non-reserve coal deposits as of December 31, 2015 per the discussion above. However, due to the lack of contracted sales beyond year-end 2016 and the depressed Northern Appalachia coal market discussed above, the Partnership decided as of December 31, 2015 to no longer pursue the development of the underground coal deposits at Sands Hill. Thus, the Partnership will cease surface coal mining at the end of 2016 when its Sands Hill contracted coal sales are fulfilled. The Partnership currently plans to continue limestone sales into 2017 since adequate limestone inventory will remain once coal mining has ceased. Based upon the factors that led to the Partnership’s decision to discontinue coal mining at Sands Hill as of year-end 2016, the Partnership performed a detailed analysis of potential impairment for the Sands Hill mining complex.

 

The Partnership’s projection of future undiscounted net cash flows to be generated from the Sands Hill mining complex indicated that a potential impairment existed since the carrying amount of the long-lived asset group at the Sands Hill mining complex exceeded the sum of the projected undiscounted net cash flows. Thus, the Partnership performed a further analysis to determine what, if any, impairment existed for the Sands Hill mining complex asset group. The Partnership utilized a discounted cash flow method (i.e. income approach) to estimate the fair value of the Sands Hill mining complex. Based on this analysis, the Partnership recorded total asset impairment and related charges of $5.7 million for the Sands Hill mining complex for the year ended December 31, 2015.

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

Leesville Field

 

The Partnership owns the Leesville field that is located in the Northern Appalachia coal region in eastern Ohio and is approximately 20 miles north of the Partnership’s Hopedale mining complex. The Leesville field is an undeveloped property that contains approximately 27.9 million tons of coal mineral that was classified as non-reserve coal deposits as of December 31, 2015. Prior to 2015, the Leesville field coal mineral had been classified as proven and probable coal reserves. The Leesville field coal mineral that had previously been classified as proven and probable coal reserves was re-classified as non-reserve coal deposits due to unfavorable projected economic performance based upon the third party engineering firm’s audit of the Partnership’s coal mineral that was discussed above. The Partnership’s long-term plan had included the eventual development of Leesville field to supplement the production from the Partnership’s nearby Hopedale mining complex because the coal qualities at Leesville closely matched the coal qualities at Hopedale. However, due to the recent downturn in the coal markets in Northern Appalachia discussed above, the reclassification of the Leesville field coal mineral to non-reserve coal deposits and the difficult economic conditions being experienced at Hopedale discussed above, the Partnership decided to reevaluate its plans for the Leesville field and examine this undeveloped property for potential impairment.

 

The Partnership believes that the Leesville field mineral would be uneconomic to produce in current market conditions, which are not expected to improve in the near future, and would not produce positive undiscounted net cash flows. Thus, this fact pattern indicated that a potential impairment existed since the carrying amount of the long-lived asset group at Leesville exceeded the sum of any projected undiscounted net cash flows. The Partnership analyzed the Leesville asset group and determined the fair value of the Leesville asset group should be based on any compensation that could be received by the Partnership by selling the assets to a third party in the current marketplace since it would be uneconomic to develop this project in the current market environment. Based on the current depressed state of the Northern Appalachia coal markets, the Partnership determined the Leesville field asset group had zero value as of December 31, 2015. The Partnership recorded total asset impairment and related charges of $3.5 million for the Leesville field for the year ended December 31, 2015.

 

Deane Mining Complex

 

On October 30, 2015, the Partnership executed a binding letter of intent with a third party for the purchase of the Partnership’s Deane mining complex. The sale of the Deane mining complex was completed on December 30, 2015. The Deane mining complex is located in eastern Kentucky and includes one underground mine that was idle during 2015. The infrastructure at the Deane mining complex consists of a preparation plant and a unit train loadout facility. The sale of the Deane complex transferred the underground mine, related equipment, the preparation plant and loadout facility in exchange for $2.0 million in the form of a promissory note receivable from the third party, while the Partnership also retained the mineral rights for the proven and probable steam coal reserves at this complex. The Deane mining complex sale also included a royalty agreement with the third party pursuant to which the Partnership will collect future royalties for coal mined and sold from the Deane complex. The sale of the Deane mining complex also relieved the Partnership of significant reclamation liabilities and bonding requirements. For third quarter 2015 financial reporting purposes, the Partnership evaluated the appropriate held for sale accounting criteria to determine if the Deane mining complex should be classified as held for sale as of September 30, 2015. Based on this evaluation, the Partnership determined the Deane mining complex met the held for sale criteria at September 30, 2015 and, accordingly, the Deane mining complex asset group was written down to its estimated fair value of $2.0 million. Due to the determination that the Deane mining complex met the held for sale criteria, the Partnership recorded an impairment charge of approximately $2.3 million for the third quarter ended September 30, 2015 and the Partnership ceased depreciation of this asset group at this time. Upon the completion of the sales agreement for the Deane mining complex, the Partnership removed the assets and liabilities related to this mining complex, which resulted in a gain of $0.4 million that was record in the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income. The net $1.9 million asset impairment charge/loss for the Deane mining complex is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

Cana Woodford Oil and Natural Gas Investment

 

In August 2015, the Partnership completed the sale of its oil and natural gas investment of approximately 1,900 net mineral acres in the Cana Woodford region of western Oklahoma. The Partnership received a total of approximately $5.7 million in proceeds from the sale of the Cana Woodford oil and natural gas mineral rights. In the second quarter of 2015, the Partnership evaluated the appropriate held for sale accounting criteria to determine if the Cana Woodford mineral rights should be classified as held for sale. Based on this evaluation, the Partnership determined these mineral rights met the held for sale criteria at June 30, 2015 and, accordingly, these mineral rights were written down to their estimated fair value of $5.8 million. Due to the determination that the mineral rights met the held for sale criteria, the Partnership recorded an impairment charge of approximately $2.2 million for the Cana Woodford mineral rights during the second quarter of 2015. The impairment charge for the Cana Woodford mineral rights is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

Bevins Branch Operation

 

As discussed further below, the Partnership had a steam coal surface mine operation in eastern Kentucky (referred to as “Bevins Branch”) in its Central Appalachia segment that was idled during mid-2014 as that location’s contract with its single customer expired at that time. In May 2015, the Partnership finalized a contractual agreement with a third party to assume the Bevins Branch operation. As of December 31, 2015, the Partnership removed the assets and liabilities related to this mining complex, which resulted in a gain of $1.2 million that was record in the asset impairment and related charges line of the consolidated statements of operations and comprehensive income. In addition, as of December 31, 2015, the Partnership removed the approximately $2.3 million of remaining assets and any related liabilities that had been previously classified as held for sale on its consolidated statements of financial position.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

Asset Impairments-2014

 

Due to the prolonged weakness in the U.S. coal markets and the dim prospects for an upturn in the coal markets in the near term, in the fourth quarter of 2014, the Partnership performed a comprehensive review of its current coal mining operations as well as potential future development projects to ascertain any potential impairment losses. The Partnership’s appointment of new executive management in the fourth quarter of 2014 and the Partnership’s annual budgeting process in the fourth quarter of 2014 led to some changes in the Partnership’s strategic views. The Partnership identified various properties, projects and operations that were potentially impaired based upon changes in its strategic plans, market conditions or other factors. The Partnership recorded approximately $45.3 million of asset impairment and related charges for the year ended December 31, 2014, which is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income. As discussed in Note 3, the Partnership also recorded an impairment charge of $5.9 million related to the Rhino Eastern joint venture that is recorded on the Equity in net (loss)/income of unconsolidated affiliates line of the consolidated statements of operations and comprehensive income. The major components that comprise this total asset impairment and related charges are described below.

 

Red Cliff Project

 

The Partnership controls certain mineral rights and related surface land located eleven miles north of Loma, Colorado (referred to as the “Red Cliff” property). The Partnership had been working with the U.S. Bureau of Land Management (“BLM”) agency since 2005 on an environmental impact statement report (“EIS report”) that was required to be completed before the Partnership could move forward with the development and permitting of a mining project on the Red Cliff property. The Partnership capitalized the cost associated with the ongoing EIS report process as mine development costs, which had accumulated to approximately $11.2 million at December 31, 2014. In addition, the Partnership invested approximately $11.0 million to acquire land for the purpose of building a rail spur to the property and also purchased certain land tracts at a cost of approximately $5.0 million for the purpose of constructing a rail load-out facility. At December 31, 2014, the Partnership had a carrying amount of approximately $16.2 million for the purchased land and approximately $2.0 million for mineral rights associated with a lease of coal reserves with the BLM. These amounts are in addition to the $11.2 million of mine development cost discussed above. Additionally, the Partnership had $0.3 million of accrued liabilities in BLM refunds related to the Red Cliff EIS report. In summary, the Partnership had total carrying costs of approximately $29.1 million for the Red Cliff property at December 31, 2014 that was included in the Partnership’s Rhino Western segment. In early 2010, the Partnership had a detailed mine development study performed for the Red Cliff property by an independent third party, which estimated the total cost to build out the project would be approximately $420 million once the EIS report was finalized.

 

The EIS report outlines the environmental effects a potential project would have on the affected area. An initial EIS report was issued for public comment and review in 2009, which received over 20,000 comments in the 90-day comment period. Based on the volume of comments received on the initial report, the BLM decided that the EIS report process needed to be restarted. The Partnership agreed to restart the EIS report and the first two chapters of the EIS report were completed and work on chapters three and four was ready to begin in November 2014. Chapters three and four of the EIS report involve the costlier portion of report project since this includes detailed studies of the impacts to air quality, wildlife, etc. Up to the fourth quarter of 2014, the Partnership had decided to continue with the EIS report despite the prolonged weakness in the coal markets. However, the decision was made by the Partnership’s executive management to limit capital spending on all projects due to the weak coal market conditions that had adversely affected the Partnership’s financial results during 2014. Thus, due to the lack of progress in getting the EIS report finalized, the amount of money spent on the project to date, the impending higher costs to be incurred on the next phase of the EIS report and the desire to limit capital spending on certain projects due to the ongoing weakness in the coal markets, the Partnership decided to suspend the EIS report process in November 2014. Based on the fact pattern described above, the Partnership determined at December 31, 2014 that it would not pursue the development of the Red Cliff property and the related assets would be abandoned or sold for current market value.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

Since the Partnership reached a decision to abandon the potential development of the Red Cliff asset group at December 31, 2014, the Partnership evaluated the assets for impairment in accordance with applicable accounting guidelines. The Partnership determined that the mine development costs and mineral rights could not be sold to a third party, so the Partnership recorded an asset impairment loss of $13.2 million for the year ended December 31, 2014 for these assets, which represented the write down of the previous carrying value of these assets to zero. The land related to the Red Cliff project was recorded at fair value (based on a third party appraisal) less costs to sell for a total net fair value of approximately $6.9 million since the Partnership had committed to a plan to sell these assets, which resulted in an additional asset impairment charge of $9.3 million. In total, after netting the $0.3 million of BLM refunds that will not be repaid due to abandoning the EIS report process, the Partnership recorded asset impairment and related charges of $22.2 million related to its Red Cliff assets at December 31, 2014. The $6.9 million of land is recorded on the Non-current assets held for sale line of the Partnership’s consolidated statements of financial position.

 

Rich Mountain Property

 

In June 2011, the Partnership acquired coal mineral rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million (referred to as the “Rich Mountain” property). These development stage properties were unpermitted and contained no infrastructure. The Partnership conducted a core drilling program on the Rich Mountain property after it was purchased and determined the property contained an estimated 8.2 million tons of proven and probable underground metallurgical coal reserves. The Partnership capitalized the cost associated with its core drilling as mine development costs and the total value in property, plant and equipment for the Rich Mountain property was $8.3 million at December 31, 2014. The Partnership included this property in its Other category for segment reporting purposes since it was undeveloped.

 

The ongoing deterioration in the metallurgical coal markets has resulted in weak demand and historically low prices for this quality of coal. In the fourth quarter of 2014, the Partnership reassessed its strategy for these mineral rights and determined that it was not economical to develop this small coal reserve given the cost of building the required infrastructure. Although the Partnership did not have an active marketing strategy for the Rich Mountain property, the Partnership contacted a third party coal company with current operations in the general area of the Rich Mountain property to determine if there would be any interest in acquiring these mineral rights. Repeated attempts to obtain a non-binding price quote for the Rich Mountain mineral rights from this or other third parties resulted in no indicative bids being offered. Based on the factors discussed above, the Partnership determined at December 31, 2014 that it would not pursue the development of the Rich Mountain property and the related assets would be abandoned.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

In accordance with applicable accounting guidelines, the Partnership reviewed its Rich Mountain assets as of December 31, 2014 for any impairment indicators that may have been present for this long-lived asset group. Since the Partnership reached a decision to abandon the potential development of this asset group, the Partnership recorded an asset impairment loss of $8.3 million for the year ended December 31, 2014, which represented the write down of the previous carrying value of this asset group to zero. The Partnership determined the Rich Mountain assets had zero value since the Partnership could not solicit any financial bid for the Rich Mountain assets and the Partnership does see any alternative uses of the mineral right assets in their current state to generate value.

 

Bevins Branch Operation

 

The Partnership had a steam coal surface mine operation in eastern Kentucky, referred to as Bevins Branch, in its Central Appalachia segment that was idled during mid-2014 as that location’s contract with its single customer expired at that time. The Partnership actively attempted to market the coal from this operation to potential new customers and had maintained the mine so that production could resume in a relatively short time period whenever new customers could be secured. The Partnership had unsuccessfully been able to market the coal from this operation as the coal markets had been especially weak for coal from Central Appalachia and the lower quality of coal from the Bevins Branch operation proved especially difficult to market. As the Partnership found it difficult to market the quality of coal found at this mine in the current market place, the Partnership initiated negotiations in October 2014 with a third party for the potential sale of the Bevins Branch operation. At December 31, 2014, the Partnership received a letter of intent from the third party interested in the Bevins Branch operation to accept ownership of this operation, including its related reclamation obligations. In May 2015, the Partnership finalized a contractual agreement with the third party to assume the Bevins Branch operation. The contractual agreement had the third party assume the Bevins Branch operation where the only financial compensation the Partnership received is a future override royalty and the assumption of the reclamation obligations by the buyer. The closing of the transaction also allowed the Partnership to avoid the ongoing maintenance costs of this operation.

 

The Partnership reviewed the Bevins Branch operation as of December 31, 2014 in accordance with the accounting guidance for long-lived asset impairment. Since the Partnership received a letter of intent at December 31, 2014 to transfer this operation to a third party, the Partnership determined this asset group should be written down to an estimated fair value of approximately $2.4 million, which equates to the estimated fair value of the future royalty of approximately $0.2 million and the benefit to be recognized of transferring the reclamation obligations of approximately $2.2 million. Based on this analysis, the Partnership recorded total asset impairment and related charges of $8.3 million for the Bevins Branch operation for the year ended December 31, 2014. The total asset impairment and related charges include approximately $1.7 million for the write-off of advanced royalty balances related to the Bevins Branch operation that the Partnership does not expect to recover in the future. The Partnership also recorded an $6.6 million write-down of mineral value and mine development costs to the estimated fair value of $2.4 million of the royalty asset and benefit from transferring the reclamation obligations.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

6. PROPERTY, PLANT AND EQUIPMENT (Continued)

 

Other Asset Impairments

 

As of December 31, 2014, the Partnership also performed a comprehensive review of its other mining operations, primarily in Central Appalachia since this region had experienced the most extensive downturn in the coal markets, to determine if any other assets might be potentially impaired. The Partnership’s review resulted in an additional $6.5 million of asset impairment and related charges, with $3.2 million related to mineral rights, $1.8 million of mine development costs and $1.5 million of advanced royalties that the Partnership did not expect to recover. The majority of these additional charges, approximately $4.9 million, related to low quality steam coal operations in Central Appalachia that the Partnership determined were uneconomical to mine due to the ongoing downturn in the markets for this quality of coal. The remaining $1.5 million primarily related to advanced royalties that the Partnership did not expect to recover at its Central Appalachia operations, which were determined as part of the Partnership’s strategic reviews that were conducted in the fourth quarter of 2014.

 

7. GOODWILL AND INTANGIBLE ASSETS

 

ASC Topic 350 addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under the provisions of ASC Topic 350, goodwill and other intangible assets with indefinite useful lives are not amortized but instead tested for impairment at least annually. The Partnership reviews finite-lived intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable.

 

Intangible assets of the Partnership as of December 31, 2015 consisted of the following:

 

Intangible Asset		Gross Carrying Amount				Accumulated Amortization				Net Carrying Amount
						(in thousands)
Patent		$	—			$	—			$	—
Developed Technology			—				—				—
Trade Name			184				42				142
Customer List			470				107				363
Total		$	654			$	149			$	505

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

7. GOODWILL AND INTANGIBLE ASSETS (Continued)

 

Intangible assets of the Partnership as of December 31, 2014 consisted of the following:

 

Intangible Asset		Gross Carrying Amount				Accumulated Amortization				Net Carrying Amount
						(in thousands)
Patent		$	728			$	250			$	478
Developed Technology			78				27				51
Trade Name			184				33				151
Customer List			470				83				387
Total		$	1,460			$	393			$	1,067

 

The Partnership had a licensing agreement with a third party that was attempting to develop a commercially viable roof bolt product that utilized the intellectual property of the Partnership’s patent and developed technology assets. In the fourth quarter of 2015, the third party notified the Partnership that they would not renew the licensing agreement and pursue the development of the product that would utilize the Partnership’s patent and developed technology. Based on the third party’s decision to discontinue the license agreement, the Partnership performed an impairment analysis of its patent and developed technology intangible assets. This analysis determined these intangible assets had no realizable value since the Partnership could not market these asset to another third party for development and the Partnership could not internally develop a product utilizing the technology of these intangible assets. As of December 31, 2015, the Partnership recorded an impairment charge of approximately $0.5 million to reduce the carrying amount of its patent and developed technology intangible assets to zero. The impairment charge for the intangible assets is recorded on the Asset impairment and related charges line of the consolidated statements of operations and comprehensive income.

 

The Partnership considers the trade name and customer list intangible assets to have a useful life of twenty years. These intangible assets are amortized over their useful life on a straight line basis. Amortization expense for the years ended December 31, 2015 and 2014 is included in the depreciation, depletion and amortization table included in Note 6.

 

The future total amortization expense for each of the five succeeding years related to intangible assets that are currently recorded in the consolidated statement of financial position is estimated to be as follows at December 31, 2015:

 

		Trade Name				Customer List				Total
						(in thousands)
2016		$	9			$	23			$	32
2017			9				23				32
2018			9				23				32
2019			9				23				32
2020			9				23				32

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

8. OTHER NON-CURRENT ASSETS

 

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

 

		December 31,
		2015				2014
		(in thousands)
Deposits and other		$	138			$	347
Debt issuance costs—net			—				1,513
Non-current receivable			23,908				14,237
Note receivable			2,000				—
Deferred expenses			261				313
Total		$	26,307			$	16,410

 

As of December 31, 2015 and 2014, the non-current receivable balance of $23.9 million and $14.2 million, respectively, consisted of the amount due from the Partnership’s workers’ compensation and black lung insurance providers for potential claims that are the primary responsibility of the Partnership, but are covered under the Partnership’s insurance policies. See Note 12 for a discussion of the $23.9 million and $14.2 million that is also recorded in the Partnership’s other non-current workers’ compensation liabilities.

 

9. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

 

Accrued expenses and other current liabilities as of December 31, 2015 and 2014 consisted of the following:

 

		December 31,
		2015				2014
		(in thousands)
Payroll, bonus and vacation expense		$	1,447			$	2,876
Non-income taxes			3,774				4,323
Royalty expenses			1,566				1,772
Accrued interest			575				385
Health claims			817				1,270
Workers’ compensation & pneumoconiosis			1,150				1,500
Deferred revenues			2,260				4,050
Accrued insured litigation claims			266				489
Other			2,247				669
Total		$	14,102			$	17,334

 

The $2.3 million deferred revenue balance as of December 31, 2015 decreased compared to the $4.1 million balance as of December 31, 2014 due to adverse coal market conditions in Central Appalachia during 2015 that affected lessees at the Partnership’s Elk Horn coal leasing operation. The $0.3 million and $0.5 million accrued for insured litigation claims as of December 31, 2015 and 2014, respectively, consists of probable and estimable litigation claims that are the primary obligation of the Partnership. The amount accrued for litigation claims decreased due to the settlement of various litigation claims during the year ended December 31, 2015. This amount is also due from the Partnership’s insurance providers and is included in Accounts receivable, net of allowance for doubtful accounts on the Partnership’s consolidated statements of financial position. The Partnership presents this amount on a gross asset and liability basis as a right of setoff does not exist per the accounting guidance in ASC Topic 210. This presentation has no impact on the Partnership’s results of operations or cash flows.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

10. DEBT

 

Debt as of December 31, 2015 and 2014 consisted of the following:

 

		December 31,
		2015				2014
		(in thousands)
Senior secured credit facility with PNC Bank, N.A.		$	41,200			$	54,450
Other notes payable			2,874				2,982
Total			44,074				57,432
Less current portion			(41,479	)			(210	)
Long-term debt		$	2,595			$	57,222

 

Senior Secured Credit Facility with PNC Bank, N.A.—On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility was $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million was available for letters of credit. As described below, in March 2016, December 2015, April 2015 and March 2014, the amended and restated credit facility was amended and the borrowing capacity under the facility was reduced to $80.0 million, with the amount available for letters of credit reduced to $30 million. Borrowings under the facility bear interest based upon the current PRIME rate plus an applicable margin of 3.50%. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability equal to 1.0%. Borrowings on the amended and restated senior secured credit facility are collateralized by all the unsecured assets of the Partnership. The amended and restated senior secured credit facility requires the Partnership to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Partnership was in compliance with all covenants contained in the amended and restated senior secured credit facility as of and for the twelve-month period ended December 31, 2015. The amended and restated senior secured credit facility is set to expire in July 2016.

 

In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. This second amendment permitted the Partnership to sell certain assets to Gulfport, as described in Note 4, which previously constituted a portion of the collateral under the amended and restated senior secured credit facility. This second amendment also reduced the borrowing capacity under the amended and restated senior secured credit facility to a maximum of $200 million and altered the maximum leverage ratio. In addition, the second amendment adjusted the maximum investments (other than by the Partnership) in hydrocarbons, hydrocarbon interests and assets and activities related to hydrocarbons, in each case, excluding coal, in an aggregate amount not to exceed $50 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s consolidated statements of financial position and in Cash flows (used in) financing activities in the Partnership’s consolidated statements of cash flows. In addition, the Partnership recorded a non-cash charge of approximately $1.1 million to write-off a portion of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility, which was recorded in Interest expense on the Partnership’s consolidated statements of operations and comprehensive income.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

10. DEBT (Continued)

 

In April 2015, the Partnership entered into a third amendment of its amended and restated senior secured credit facility. The third amendment extended the expiration date of the amended and restated credit agreement to July 2017. The extension is contingent upon (i) the Partnership’s leverage ratio being less than or equal to 2.75 to 1.0 and (ii) the Partnership having liquidity greater than or equal to $15 million, in each case for either the quarter ending December 31, 2015 or March 31, 2016. If both of these conditions are not satisfied for one of the periods, the expiration date of the amended and restated credit agreement will revert to July 2016. See Note 1 for further discussion regarding the extension of the expiration date of the credit agreement. The third amendment also reduced the borrowing commitment under the credit facility to a maximum of $100 million and reduced the amount available for letters of credit to $50 million. The third amendment also provides that the disposition of any assets by the Partnership consisting of net cash proceeds up to an aggregate $35 million shall reduce the total commitment under the facility on a dollar-for-dollar basis by up to a total of $10 million, and any dispositions of assets in excess of $35 million in the aggregate shall reduce the commitment under the facility on a dollar-for-dollar basis. The third amendment changed the maximum leverage ratio to 3.75 to 1.0 through September 30, 2015. The maximum leverage ratio decreases to 3.5 to 1.0 from October 1, 2015 through December 31, 2015 and then decreases to 3.25 to 1.0 from January 1, 2016 through March 31, 2016. The maximum leverage ratio decreases to 3.0 to 1.0 after March 31, 2016. Notwithstanding the above, the leverage ratio shall be reduced by 0.25 for every $10 million of gross cash proceeds received by the Partnership from the sale of any assets; provided, however, that in no event shall the maximum permitted leverage ratio be reduced below 3.0 to 1.0. The third amendment limits the Partnership’s quarterly distributions to a maximum of $0.035 per unit unless (i) the pro forma leverage ratio of the Partnership, immediately prior to and after giving effect to such distribution, is less than or equal to 3.0 to 1.0 and (ii) the amount of borrowings available under the credit facility, immediately prior to and after giving effect to such distribution, is at least $20 million. In addition, the third amendment removed the interest coverage ratio covenant and replaced it with a minimum fixed charge coverage ratio, which consists of the ratio of consolidated EBITDA minus maintenance capital expenditures to fixed charges. Fixed charges are defined in the third amendment to include the sum of cash interest expense, scheduled principal installments on indebtedness (as adjusted for prepayments), dividends and distributions. Commencing with the quarter ended September 30, 2015, the fixed charge coverage ratio for the trailing four quarters must be a minimum of 1.1 to 1.0. The third amendment also limits any investments made by the Partnership, including investments in hydrocarbons, to $10 million provided that the leverage ratio is less than or equal to 3.0 to 1.0 and the borrowers’ available liquidity is at least $20 million. The third amendment does not permit the Partnership to issue any new equity of the Partnership unless the proceeds of such equity issuance are used to reduce the outstanding borrowings under the facility. Issuances of equity under the Partnership’s long-term incentive plan are excluded from this requirement. The third amendment limits the amount of the Partnership’s capital expenditures to $20.0 million for fiscal year 2015 and limited capital expenditures to $27.5 million for each fiscal year after 2015. However, to the extent that capital expenditures for any fiscal year are less than indicated above, the Partnership may increase the following year’s capital expenditures by the lesser of such unused amount or $5.0 million. As part of executing the third amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $2.1 million to the lenders in April 2015, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s consolidated statements of financial position. In addition, the Partnership recorded a non-cash charge of approximately $0.2 million to write-off a portion of its unamortized debt issuance costs since the third amendment reduced the borrowing commitment under the amended and restated senior secured credit facility, which was recorded in Interest expense on the Partnership’s consolidated statements of operations and comprehensive income.

 

From the date of the third amendment in April 2015 of the amended and restated senior secured credit facility through December 31, 2015, the Partnership received gross proceeds from asset sales of approximately $14.3 million. Per the terms of the third amendment of the amended and restated senior secured credit facility described above for gross proceeds from asset sales in excess of $10 million but less than $35 million, the borrowing commitment under the credit facility was reduced to a maximum of $90 million and the maximum permitted leverage ratio decreased to 3.25 to 1.0 as of December 31, 2015.

 

On March 17, 2016, the Operating Company entered into an amendment (the “Fourth Amendment”) of its amended and restated senior secured credit facility. The Fourth Amendment amends the definition of change of control in the amended and restated credit agreement to permit Royal to purchase the membership interests of the General Partner and sets the expiration date of the facility at July 2016. The Fourth Amendment reduces the borrowing capacity under the credit facility to a maximum of $80 million and reduces the amount available for letters of credit to $30 million. The Fourth Amendment eliminates the option to borrow funds utilizing the LIBOR rate plus an applicable margin and establishes the borrowing rate for all borrowings under the facility to be based upon the current PRIME rate plus an applicable margin of 3.50%. The Fourth Amendment eliminates the capability to make Swing Loans under the facility and eliminates the ability of the Partnership to pay distributions to its common or subordinated unitholders. The Fourth Amendment alters the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve month basis, to 6.75 to 1.00. The leverage ratio shall be reduced by 0.50 to 1.00 for every $10 million of net cash proceeds, in the aggregate, received by the Partnership after the date of the Fourth Amendment from a liquidity event; provided, however, that in no event shall the maximum permitted leverage ratio be reduced below 3.00 to 1.00. A liquidity event is defined in the Fourth Amendment as the issuance of any equity by the Partnership on or after the Fourth Amendment effective date (other than the Royal equity contribution discussed above), or the disposition of any assets by the Partnership. The Fourth Amendment requires the Partnership to maintain minimum liquidity of $5 million and minimum EBITDA, calculated as of the end of the most recent month, on a trailing twelve month basis, of $8 million. The Fourth Amendment limits the amount of the Partnership’s capital expenditures to $15 million, calculated as of end of the most recent month, on a trailing twelve month basis. The Fourth Amendment requires the Partnership to provide monthly financial statements and a weekly rolling thirteen week cash flow forecast to the administrative agent.

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

At December 31, 2015, the Operating Company had borrowed $36.0 million at a variable interest rate of LIBOR plus 4.50% (4.70% at December 31, 2015) and an additional $5.2 million at a variable interest rate of PRIME plus 3.50% (7.00% at December 31, 2015). In addition, the Operating Company had outstanding letters of credit of $27.4 million at a fixed interest rate of 4.50% at December 31, 2015. Based upon a maximum borrowing capacity of 3.25 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $1.1 million of the borrowing availability at December 31, 2015.

 

For the year ended December 31, 2014, the Partnership capitalized interest costs of approximately $0.1 million, which was related to the construction of its Pennyrile mine in western Kentucky. The Partnership did not capitalize any interest costs during the year ended December 31, 2015.

 

Principal payments on long-term debt due subsequent to December 31, 2015 are as follows:

 

		in thousands
2016		$	41,479
2017			240
2018			257
2019			275
2020			295
Thereafter			1,528
Total principal payments		$	44,074

 

 

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RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

11. ASSET RETIREMENT OBLIGATIONS

 

The changes in asset retirement obligations for the years ended December 31, 2015 and 2014 are as follows:

 

		Year Ended December 31,
		2015				2014
		(in thousands)
Balance at beginning of period (including current portion)		$	29,883			$	34,451
Accretion expense			2,082				2,281
Adjustment resulting from addition of property			1,235				—
Adjustment resulting from disposal of property(1)			(6,861	)			(2,310	)
Adjustments to the liability from annual recosting and other			(2,078	)			(1,324	)
Reclassification to held for sale			—				(2,250	)
Liabilities settled			(514	)			(965	)
Balance at end of period			23,747				29,883
Less current portion of asset retirement obligation			(767	)			(1,431	)
Long-term portion of asset retirement obligation		$	22,980			$	28,452

 

(1) The ($6.9) million adjustment for the year ended December 31, 2015 relates to the sale of the Partnership’s Deane mining complex discussed in Note 6. The ($2.3) million adjustment for the year ended December 31, 2014 primarily relates to the transfer of certain mining permits to a third party that relieved the Partnership of the asset retirement obligations related to these permits.

 

12. WORKERS’ COMPENSATION AND BLACK LUNG

 

Certain of the Partnership’s subsidiaries are liable under federal and state laws to pay workers’ compensation and coal workers’ black lung benefits to eligible employees, former employees and their dependents. The Partnership currently utilizes an insurance program and state workers’ compensation fund participation to secure its on-going obligations depending on the location of the operation. Premium expense for workers’ compensation benefits is recognized in the period in which the related insurance coverage is provided.

 

The Partnership’s black lung benefit liability is calculated using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation. The Partnership’s actuarial calculations using the service cost method for its black lung benefit liability are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates. The Partnership’s liability for traumatic workers’ compensation injury claims is the estimated present value of current workers’ compensation benefits, based on actuarial estimates. The Partnership’s actuarial estimates for its workers’ compensation liability are based on numerous assumptions including claim development patterns, mortality, medical costs and interest rates. The discount rate used to calculate the estimated present value of future obligations for black lung was 4.0% for December 31, 2015 and 2014 and for workers’ compensation was 2.0% at December 31, 2015 and 2014.

 

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

12. WORKERS’ COMPENSATION AND BLACK LUNG (Continued)

 

The black lung and workers’ compensation expenses for the years ended December 31, 2015 and 2014 are as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Black lung benefits:
Service cost		$	(991	)	$	1,040
Interest cost			397			357
Actuarial loss/(gain)			—			1,625
Total black lung			(594	)		3,022
Workers’ compensation expense			4,334			1,197
Total expense		$	3,740		$	4,219

 

The changes in the black lung benefit liability for the years ended December 31, 2015 and 2014 are as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Benefit obligations at beginning of year		$	10,033		$	7,251
Service cost			(991	)		1,040
Interest cost			397			357
Actuarial loss/(gain)			—			1,625
Benefits and expenses paid			(214	)		(240	)
Benefit obligations at end of year		$	9,225		$	10,033

 

The classification of the amounts recognized for the Partnership’s workers’ compensation and black lung benefits liability as of December 31, 2015 and 2014 are as follows:

 

		December 31,
		2015			2014
		(in thousands)
Black lung claims		$	9,225		$	10,033
Insured black lung and workers’ compensation claims			23,907			14,237
Workers’ compensation claims			6,210			5,172
Total obligations		$	39,342		$	29,442
Less current portion			(1,150	)		(1,500	)
Non-current obligations		$	38,192		$	27,942

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

12. WORKERS’ COMPENSATION AND BLACK LUNG (Continued)

 

The balance for insured black lung and workers’ compensation claims as of December 31, 2015 and 2014 consisted of $23.9 million and $14.2 million, respectively, that is the primary obligation of the Partnership, but this amount is also due from the Partnership’s insurance providers, which is included in Note 8 as non-current receivables, based on the Partnership’s workers’ compensation insurance coverage. The increase in the 2015 balance compared to 2014 is primarily due to an expected increase in the frequency and success of entitlement claims for black lung exposure, which the Partnership believes is due to the Patient Protection and Affordable Care Act. The Partnership presents this amount on a gross asset and liability basis since a right of setoff does not exist per the accounting guidance in ASC Topic 210. This presentation has no impact on the Partnership’s results of operations or cash flows.

 

13. EMPLOYEE BENEFITS

 

Postretirement Plan—In conjunction with the acquisition of the coal operations of American Electric Power on April 16, 2004, the Operating Company acquired a postretirement benefit plan providing healthcare to eligible employees at its Hopedale operations. The Partnership has no other postretirement plans.

 

On December 10, 2015, the Partnership notified the employees at its Hopedale operations that healthcare benefits from the postretirement benefit plan would cease on January 31, 2016. The negative plan amendment that arose on December 10, 2015 resulted in an approximate $6.5 million prior service cost benefit. The Partnership is amortizing the prior service cost benefit over the remaining term of the benefits to be provided until January 31, 2016. For the year ended December 31, 2015, the Partnership recognized a benefit of approximately $2.6 million from the plan amendment in the Cost of operations line of the consolidated statements of operations and comprehensive income. The remaining $3.9 million benefit from the plan amendment will be recognized in the first quarter of 2016.

 

Summaries of the changes in benefit obligations and funded status of the plan as of the measurement dates of December 31, 2015 and 2014 are as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Benefit obligation at beginning of period		$	6,648		$	6,120
Changes in benefit obligations:
Service costs			254			297
Interest cost			191			236
Benefits paid			(217	)		(495	)
Plan amendment			(6,503	)		—
Actuarial loss/(gain)			(328	)		490
Benefit obligation at end of period		$	45		$	6,648
Fair value of plan assets at end of period		$	—		$	—
Funded status		$	(45	)	$	(6,648	)

 

  

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

13. EMPLOYEE BENEFITS (Continued)

 

The classification of net amounts recognized for postretirement benefits as of December 31, 2015 and 2014 are as follows:

 

		December 31,
		2015			2014
		(in thousands)
Current liability—postretirement benefits		$	(45	)	$	(425	)
Non-current liability—postretirement benefits			—			(6,223	)
Net amount recognized		$	(45	)	$	(6,648	)

 

The amounts recognized in accumulated other comprehensive income for the years ended December 31, 2015 and 2014 are as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Balance at beginning of year		$	1,373		$	2,231
Actuarial (loss)/gain			328			(490	)
Prior service (cost)/gain to be amortized			3,876			—
Amortization of net actuarial gain			(782	)		(368	)
Net actuarial gain		$	4,795		$	1,373

 

The amounts reclassified from accumulated other comprehensive income to Cost of operations in the Partnership’s consolidated statements of operations for the years ended December 31, 2015 and 2014 was $3.4 million (inclusive of the $2.6 million benefit from the negative plan amendment described above) and $0.4 million, respectively.

 

		December 31,
		2015			2014
Weighted Average assumptions used to determine benefit obligations:
Discount rate			n/a			3.15	%
Expected return on plan assets			n/a			n/a

 

		Year Ended December 31,
		2015			2014
Weighted Average assumptions used to determine periodic benefit cost:
Discount rate(1)			3.15	%		3.96	%
Expected return on plan assets			n/a			n/a
Rate of compensation increase			n/a			n/a

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

13. EMPLOYEE BENEFITS (Continued)

 

The components of net periodic benefit cost for the years ended December 31, 2015 and 2014 are as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Service costs		$	254		$	297
Interest cost			191			236
Amortization of prior service cost			(2,626	)		—
Amortization of (gain)			(782	)		(368	)
Benefit cost		$	(2,963	)	$	165

 

Amounts expected to be amortized from accumulated other comprehensive income into net periodic benefit cost during the year ending December 31, 2016, are as follows:

 

		(in thousands)
Net actuarial gain		$	4,795

 

401(k) Plans—The Partnership and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Partnership matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Partnership’s discretion. The expense under these plans for the years ended December 31, 2015 and 2014 was as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
401(k) plan expense		$	2,027		$	2,227

 

14. EQUITY-BASED COMPENSATION

 

In October 2010, the General Partner established the Rhino Long-Term Incentive Plan (the “Plan” or “LTIP”). The Plan is intended to promote the interests of the Partnership by providing to employees, consultants and directors of the General Partner, the Partnership or affiliates of either incentive compensation awards to encourage superior performance. The LTIP provides for grants of restricted units, unit options, unit appreciation rights, phantom units, unit awards, and other unit-based awards. The aggregate number of units initially reserved for issuance under the LTIP is 2,479,400.

 

As of December 31, 2015, the General Partner had granted phantom units to certain employees and restricted units and unit awards to its directors. These grants consisted of annual restricted unit awards to directors and phantom unit awards with tandem distribution equivalent rights (“DERs”) granted in the first quarter of each year since 2012 to certain employees in connection with the prior fiscal year’s performance. The DERs consist of rights to accrue quarterly cash distributions in an amount equal to the cash distribution the Partnership makes to unitholders during the vesting period.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

14. EQUITY-BASED COMPENSATION (Continued)

 

These awards are subject to service based vesting conditions and any accrued distributions will be forfeited if the related awards fail to vest according to the relevant service based vesting conditions. The phantom units granted to certain employees vest in equal annual installments over a three year period from the date of grant. A summary of non-vested LTIP awards as of and for the years ended December 31, 2015 and 2014 is as follows:

 

		Common Units			Weighted Average Grant Date Fair Value (per unit)
		(in thousands)
Non-vested awards at December 31, 2013			55		$	14.63
Granted			46		$	12.32
Vested			(34	)	$	13.95
Forfeited			(16	)	$	13.01
Non-vested awards at December 31, 2014			51		$	13.50
Granted			247		$	1.06
Vested			(86	)	$	5.68
Forfeited			(8	)	$	6.43
Non-vested awards at December 31, 2015			204		$	2.00

 

The Partnership accounts for its unit-based awards as liabilities with applicable mark-to-market adjustments at each reporting period because the Compensation Committee of the board of directors of the General Partner has historically elected to pay some of the awards in cash in lieu of issuing common units.

 

For the years ended December 31, 2015 and 2014, the Partnership recorded expense of approximately $0.1 million and approximately $0.3 million, respectively, for the LTIP awards. For the year ended December 31, 2015, the total fair value of the awards that vested was $0.1 million. As of December 31, 2015, the total unrecognized compensation expense related to the non-vested LTIP awards that are expected to vest was $0.3 million. The expense is expected to be recognized over a weighted-average period of 1.1 years. As of December 31, 2015, the intrinsic value of the non-vested LTIP awards was $0.1 million.

 

15. COMMITMENTS AND CONTINGENCIES

 

Coal Sales Contracts and Contingencies—As of December 31, 2015, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

 

Year		Tons (in thousands)			Number of customers
2016			3,255			14
2017			1,914			8
2018			264			1

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

15. COMMITMENTS AND CONTINGENCIES (Continued)

 

Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

 

Purchased Coal Expenses—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts. In addition, the Partnership incurs expense from time to time related to coal purchased on the over-the-counter market (“OTC”). Purchase coal expense from coal purchase contracts and expense from OTC purchases for the years ended December 31, 2015 and 2014 was as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Purchased coal expense		$	(26	)	$	6,168
OTC expense		$	—		$	—

 

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the years ended December 31, 2015 and 2014 was as follows:

 

		Year Ended December 31,
		2015			2014
		(in thousands)
Lease expense		$	6,204		$	3,478
Royalty expense		$	10,754		$	11,571

 

Approximate future minimum lease and royalty payments (not including advance royalties already paid and recorded as assets in the accompanying statements of financial position) are as follows:

 

Years Ended December 31,		Royalties			Leases
		(in thousands)
2016		$	2,824			3,664
2017			2,466			1,097
2018			2,436			148
2019			2,436			—
2020			2,556			—
Thereafter			12,780			—
Total minimum royalty and lease payments		$	25,498		$	4,909

 

Environmental Matters—Based upon current knowledge, the Partnership believes that it is in compliance with environmental laws and regulations as currently promulgated. However, the exact nature of environmental control problems, if any, which the Partnership may encounter in the future cannot be predicted, primarily because of the increasing number, complexity and changing character of environmental requirements that may be enacted by federal and state authorities.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

15. COMMITMENTS AND CONTINGENCIES (Continued)

 

Legal Matters—The Partnership is involved in various legal proceedings arising in the ordinary course of business due to claims from various third parties, as well as potential citations and fines from the Mine Safety and Health Administration, potential claims from land or lease owners and potential property damage claims from third parties. The Partnership is not party to any other pending litigation that is probable to have a material adverse effect on the financial condition, results of operations or cash flows of the Partnership. Management of the Partnership is also not aware of any significant legal, regulatory or governmental proceedings against or contemplated to be brought against the Partnership.

 

Guarantees/Indemnifications and Financial Instruments with Off-Balance Sheet Risk—In the normal course of business, the Partnership is a party to certain guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. No liabilities related to these arrangements are reflected in the consolidated statements of financial position. The amount of bank letters of credit outstanding with PNC Bank, N.A., as the letter of credit issuer under the Partnership’s credit facility, was $27.4 million as of December 31, 2015. The bank letters of credit outstanding reduce the borrowing capacity under the credit facility. In addition, the Partnership has outstanding surety bonds with third parties of $59.1 million as of December 31, 2015 to secure reclamation and other performance commitments.

 

The credit facility is fully and unconditionally, jointly and severally guaranteed by the Partnership and substantially all of its wholly owned subsidiaries. Borrowings under the credit facility are collateralized by the unsecured assets of the Partnership and substantially all of its wholly owned subsidiaries. See Note 10 for a more complete discussion of the Partnership’s debt obligations.

 

Joint Ventures—The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012. The Partnership did not make any capital contributions to the Timber Wolf joint venture during the year ended December 31, 2015.

 

The Partnership was required to contribute additional capital to the Muskie Proppant joint venture that was formed in the fourth quarter of 2012. During the year ended December 31, 2014, the Partnership made capital contributions to the Muskie Proppant joint venture of approximately $0.2 million based upon its proportionate ownership percentage. In addition, during the year ended December 31, 2013, the Partnership provided a loan based upon its ownership share to Muskie in the amount of $0.2 million. The note was fully repaid in November 2014 in conjunction with the contribution of the Partnership’s interests in Muskie to Mammoth. With the contribution of the Partnership’s interest in Muskie to Mammoth in the fourth quarter of 2014, the Partnership does not have any further funding commitments to Mammoth.

 

The Partnership may contribute additional capital to the Sturgeon joint venture that was formed in the third quarter of 2014. The Partnership made an initial capital contribution of $5.0 million during the year ended December 31, 2014 based upon its proportionate ownership interest.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

16. EARNINGS PER UNIT (“EPU”)

 

The following table presents a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the years ended December 31, 2015 and 2014:

 

Year ended December 31, 2015		General Partner			Common Unitholders			Subordinated Unitholders
		(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net (loss) from continuing operations		$	(1,119	)	$	(31,491	)	$	(23,356	)
Net income from discontinued operations			14			406			302
Interest in net income		$	(1,105	)	$	(31,085	)	$	(23,054	)
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations		$	5		$	139		$	(144	)
Net income from discontinued operations			—			—			—
Interest in net income		$	5		$	139		$	(144	)
Interest in net (loss)/income for EPU purposes:
Net (loss) from continuing operations		$	(1,114	)	$	(31,352	)	$	(23,500	)
Net income from discontinued operations			14			406			302
Interest in net income		$	(1,100	)	$	(30,946	)	$	(23,198	)
Denominator:
Weighted average units used to compute basic EPU			n/a			16,714			12,396
Effect of dilutive securities—LTIP awards			n/a			—			—
Weighted average units used to compute diluted EPU			n/a			16,714			12,396
Net (loss)/income per limited partner unit, basic:
Net (loss) per unit from continuing operations			n/a		$	(1.87	)	$	(1.89	)
Net income per unit from discontinued operations			n/a			0.02			0.02
Net income per limited partner unit, basic			n/a		$	(1.85	)	$	(1.87	)
Net (loss)/income per limited partner unit, diluted:
Net (loss) per unit from continuing operations			n/a		$	(1.87	)	$	(1.89	)
Net income per unit from discontinued operations			n/a			0.02			0.02
Net income per limited partner unit, diluted			n/a		$	(1.85	)	$	(1.87	)

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

16. EARNINGS PER UNIT (“EPU”) (Continued)

 

Year ended December 31, 2014		General Partner			Common Unitholders			Subordinated Unitholders
		(in thousands, except per unit data)
Numerator:
Interest in net income (as previously reported):
Net income from continuing operations		$	(1,626	)	$	(45,705	)	$	(33,962	)
Net income from discontinued operations			2,607			73,271			54,464
Interest in net income		$	981		$	27,566		$	20,502
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations		$	245		$	6,908		$	(7,153	)
Net income from discontinued operations			—			—			—
Interest in net income/(loss)		$	245		$	6,908		$	(7,153	)
Interest in net income/(loss) for EPU purposes (as restated):
Net income/(loss) from continuing operations		$	(1,381	)	$	(38,797	)	$	(41,115	)
Net income from discontinued operations			2,607			73,271			54,464
Interest in net income/(loss)		$	1,226		$	34,474		$	13,349
Denominator:
Weighted average units used to compute basic EPU			n/a			16,678			12,397
Effect of dilutive securities—LTIP awards			n/a			7			—
Weighted average units used to compute diluted EPU			n/a			16,685			12,397
Net income per limited partner unit, basic:
Net income per unit from continuing operations			n/a		$	(2.32	)	$	(3.31	)
Net income per unit from discontinued operations			n/a			4.39			4.39
Net income per limited partner unit, basic			n/a		$	2.07		$	1.08
Net income per limited partner unit, diluted:
Net income per unit from continuing operations			n/a		$	(2.32	)	$	(3.31	)
Net income per unit from discontinued operations			n/a			4.39			4.39
Net income per limited partner unit, diluted			n/a		$	2.07		$	1.08

 

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. Since the Partnership incurred a total net loss for the year ended December 31, 2015, all potential dilutive units were excluded from the diluted EPU calculation for this period because when an entity incurs a net loss in a period, potential dilutive units shall not be included in the computation of diluted EPU since their effect will always be anti-dilutive. There were no anti-dilutive units for the year ended December 31, 2014.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

17. MAJOR CUSTOMERS

 

The Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues or receivables (Note: customers with “n/a” had revenue or receivables below the 10% threshold in any period where this is indicated):

 

		December 31, 2015 Receivable Balance			Year Ended December 31, 2015 Sales			December 31, 2014 Receivable Balance			Year Ended December 31, 2014 Sales
		(in thousands)
NRG Energy Inc. (fka GenOn Energy, Inc.)		$	—		$	22,111		$	2,932		$	31,605
PPL Corporation			1,881			33,662			2,053			24,542
PacifiCorp Energy			1,969			21,519			n/a			n/a

 

18. FAIR VALUE OF FINANCIAL INSTRUMENTS

 

The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership’s senior secured credit facility was determined based upon a market approach and approximates the carrying value at December 31, 2015. The fair value of the Partnership’s senior secured credit facility is a Level 2 measurement.

 

As of December 31, 2015, the Partnership did not have any nonrecurring fair value measurements related to any assets held for sale. The Partnership previously had assets classified as held for sale that were related to the Partnership’s 2014 impairment actions related to its Red Cliff assets that are discussed in Note 6. As of December 31, 2015, the Partnership reclassified its previously held for sale assets to property, plant and equipment to be held and used since the Partnership no longer had an active plan to sell these assets in the next twelve months.

 

For the year ended December 31, 2015, the Partnership had nonrecurring fair value measurements related to asset impairments as described in Note 6. The nonrecurring fair value measurements for the asset impairments described in Note 6 for the year ended December 31, 2015 were Level 3 measurements.

 

For the year ended December 31, 2014, the Partnership had nonrecurring fair value measurements related to its assets and liabilities held for sale. These assets and liabilities are a result of the Partnership’s impairment actions discussed in Note 6. The fair value of the assets and liabilities held for sale at December 31, 2014 were based upon the highest and best use of the respective nonfinancial assets and liabilities. The Partnership had approximately $6.9 million in land value related to its Red Cliff assets that were classified as held for sale at December 31, 2014. This land was valued using a market approach by a third party appraisal firm that determined the fair value of the asset based on sales of comparable property in the market along with other market factors such as competitive listings. The fair value of the Partnership’s land held for sale at December 31, 2014 was a Level 2 measurement.

 

Additionally, the Partnership had approximately $2.4 million of assets and $2.2 million of liabilities held for sale at December 31, 2014 related to the Bevins Branch operation discussed in Note 6. The held for sale assets consisted of approximately $0.2 million of a future coal royalty income stream. The fair value of the future royalty income stream was determined by an income approach using a discounted cash flow analysis with an appropriate discount rate. The fair value of the remaining $2.2 million of assets and liabilities held for sale related to the Bevins Branch operation was also determined by an income approach using a discounted cash flow analysis. The $2.2 million of assets and liabilities held for sale related to the reclamation obligation being transferred in the Bevins Branch transaction and the income approach used to determine the fair value was based on the Partnership’s method to calculate its asset retirement obligations for reclamation, which is discussed in Note 2. The fair values of the Partnership’s assets and liabilities held for sale at December 31, 2014 for the Bevins Branch operation were Level 3 measurements. The Partnership completed the sale of its Bevins Branch assets and liabilities in May 2015.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

19. RELATED PARTY AND AFFILIATE TRANSACTIONS

 

Related Party		Description		2015			2014
				(in thousands)
Wexford Capital LP		Expenses for legal, consulting, and advisory services		$	143		$	131
Wexford Capital LP		Distributions paid			553			10,949
Wexford Capital LP		Partner’s contribution			2			6
Rhino Eastern LLC		Equity in net (loss)/income of unconsolidated affiliate			—			(12,089	)
Rhino Eastern LLC		Expenses for legal, health claims, workers’ compensation and other expenses			—			4,610
Rhino Eastern LLC		Receivable for legal, health claims and workers’ compensation and other expenses			—			223
Rhino Eastern LLC		Investment in unconsolidated affiliate			—			13,151
Timber Wolf Terminals LLC		Investment in unconsolidated affiliate			130			130
Muskie Proppant LLC		Investment in unconsolidated affiliate			—			—
Mammoth Energy Partners LP		Investment in unconsolidated affiliate			1,933			1,933
Sturgeon Acquisitions LLC		Investment in unconsolidated affiliate			5,515			5,440
Sturgeon Acquisitions LLC		Distributions from unconsolidated affiliate			232			—
Sturgeon Acquisitions LLC		Return of capital from unconsolidated affiliate			35			—
Sturgeon Acquisitions LLC		Equity in net income of unconsolidated affiliate			342			440

 

From time to time, employees from Wexford Capital perform legal, consulting, and advisory services to the Partnership. The Partnership incurred expenses of $0.1 million for the years ended December 31, 2015 and 2014 for legal, consulting, and advisory services performed by Wexford Capital.

 

For the year ended December 31, 2014, the $12.1 million equity in net loss of unconsolidated affiliate for Rhino Eastern includes the $5.9 million impairment charge for the joint venture that was discussed earlier.

 

From time to time, the Partnership has allocated and paid expenses on behalf of the Rhino Eastern joint venture. During the years ended December 31, 2014, the Partnership paid expenses for legal, health claims and workers’ compensation of $4.6 million on behalf of Rhino Eastern that were subsequently billed and paid by Rhino Eastern to the Partnership.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

20. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

 

Cash payments for interest were $3.4 million and $4.0 million for the years ended December 31, 2015 and 2014, respectively.

 

The consolidated statement of cash flows for the year ended December 31, 2015 is exclusive of approximately $0.7 million of property, plant and equipment additions which are recorded in Accounts payable. The consolidated statements of cash flows for the year ended December 31, 2015 also excludes approximately $0.1 million related to the value of LTIP units that were issued to certain employees and directors of the General Partner.

 

In January 2015, the Partnership dissolved the Rhino Eastern joint venture with Patriot. As part of the dissolution, the Partnership retained coal reserves, a prepaid advanced royalty balance and other assets and liabilities. In addition, the Partnership and Patriot agreed to a dissolution payment as part of the dissolution based upon a final working capital adjustment calculation, which is a liability of the Partnership. The Partnership recorded the dissolution of the joint venture by removing the investment in the Rhino Eastern unconsolidated subsidiary and recording the specific assets and liabilities retained in the dissolution. The dissolution of the Rhino Eastern joint venture completed in January 2015 had no impact on the Partnership’s consolidated statements of operations and comprehensive income for the year ended December 31, 2015. The consolidated statement of cash flows for the year ended December 31, 2015 excludes the removal of the investment in the unconsolidated subsidiary and the recognition of the retained assets and liabilities, which are detailed in the table below.

 

		(in thousands)
Coal properties (incl asset retirement costs)		$	12,104
Advance royalties, net of current portion			4,706
Other non-current assets—acquired			229
Other non-current assets—written off			(642	)
Accrued expenses and other			(2,012	)
Asset retirement obligations			(1,235	)
Net assets acquired			13,150
Investment in unconsolidated affiliates-Rhino Eastern—written off		$	(13,150	)

 

The consolidated statement of cash flows for the year ended December 31, 2014 is exclusive of approximately $0.2 million of property, plant and equipment additions which are recorded in Accounts payable. The consolidated statements of cash flows for the year ended December 31, 2014 also excludes approximately $0.3 million related to the value of LTIP units that were issued to certain employees and directors of the General Partner.

 

21. SEGMENT INFORMATION

 

The Partnership primarily produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah. The Partnership sells primarily to electric utilities in the United States. In addition, with the Elk Horn Acquisition mentioned earlier, the Partnership also leases coal reserves to third parties in exchange for royalty revenues.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

21. SEGMENT INFORMATION (Continued)

 

As of December 31, 2015, the Partnership has four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois Basin. Additionally, the Partnership has an Other category that includes its ancillary businesses. The Central Appalachia segment consists of two mining complexes: Tug River and Rob Fork, which, as of December 31, 2015, together included one active underground mine, three active surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, the Central Appalachia segment includes the Partnership’s Elk Horn coal leasing operations. The Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex and the Leesville field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of December 31, 2015. The Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2015. The Eastern Met segment included the Partnership’s 51% equity interest in the results of operations of the Rhino Eastern joint venture, which owned the Rhino Eastern mining complex, located in West Virginia, and for which the Partnership served as manager. The Rhino Eastern joint venture was dissolved in January 2015. The 2014 financial results are shown since the joint venture owned, and the Partnership operated, this mining complex during the year. The Rhino Western segment includes the Partnership’s underground mine in the Western Bituminous region at its Castle Valley mining complex in Utah. The Illinois Basin segment includes the Partnership’s underground mine, preparation plant and river loadout facility at its Pennyrile mining complex located in western Kentucky, as well as its Taylorville field reserves located in central Illinois. The Pennyrile mining complex began production and sales in mid-2014.

 

The Partnership’s Other category as reclassified is comprised of the Partnership’s ancillary businesses and its remaining oil and natural gas activities. Held for sale assets are included in the applicable segment for reporting purposes. The Partnership has not provided disclosure of total expenditures by segment for long-lived assets, as the Partnership does not maintain discrete financial information concerning segment expenditures for long lived assets, and accordingly such information is not provided to the Partnership’s chief operating decision maker. The information provided in the following tables represents the primary measures used to assess segment performance by the Partnership’s chief operating decision maker.

 

The Partnership has historically accounted for the Rhino Eastern joint venture (formed in the year ended December 31, 2008) under the equity method. Under the equity method of accounting, the Partnership has historically only presented limited information (net income). The Partnership considered this operation to comprise a separate operating segment prior to its dissolution in January 2015 and has presented additional operating detail (with corresponding eliminations and adjustments to reflect its percentage of ownership) below. Since this equity method investment met the significance test of ten percent of net income or loss in 2014, the Partnership has presented additional summarized financial information for this equity method investment below.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

21. SEGMENT INFORMATION (Continued)

 

Reportable segment results of operations and financial position for the year ended December 31, 2015 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

 

		Central Appalachia			Northern Appalachia			Rhino Western			Illinois Basin			Other			Total Consolidated
		(in thousands)
Total assets		$	227,880		$	17,218		$	37,198		$	82,700		$	39,671		$	404,667
Total revenues			67,942			63,273			35,322			38,641			1,568			206,746
DD&A			12,641			7,562			6,314			5,928			736			33,181
Interest expense			2,040			522			315			597			1,527			5,001
Net Income (loss) from continuing operations		$	(14,212	)	$	(20,487	)	$	(4,560	)	$	(13,807	)	$	(2,900	)	$	(55,966	)

 

Reportable segment results of operations and financial position for the year ended December 31, 2014 are as follows:

 

														Eastern Met
		Central Appalachia			Northern Appalachia			Rhino Western			Illinois Basin			Complete Basis			Equity Method Eliminations			Equity Method Presentation*			Other			Total Consolidated
		(in thousands)
Total assets		$	247,362		$	52,822		$	42,173		$	80,126		$	42,100		$	(42,100	)	$	—		$	50,855		$	473,338
Total revenues			109,432			71,472			44,081			9,755			21,722			(21,722	)		—			4,317			239,057
DD&A			20,224			7,574			6,021			2,286			1,860			(1,860	)		—			1,128			37,233
Interest expense			2,055			473			329			343			81			(81	)		—			2,508			5,708
Net Income (loss) from continuing operations		$	(33,019	)	$	2,101		$	(22,822	)	$	(6,411	)	$	(12,208	)	$	5,982		$	(12,089	)	$	(9,053	)	$	(81,293	)

  

*	For the year ended December 31, 2014, the equity method net loss from continuing operations for Rhino Eastern includes the $5.9 million impairment charge for the joint venture that was discussed earlier.

 Additional summarized financial information for the equity method investment as of and for the periods ended December 31, 2015 and 2014 is as follows:

 

		2015			2014 Unaudited)
		(in thousands)
Current assets		$	—		$	3,641
Noncurrent assets			—			38,459
Current liabilities			—			3,629
Noncurrent liabilities			—			3,202
Total costs and expenses			—			33,850
(Loss)/income from operations			—			(12,128	)

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

21. SEGMENT INFORMATION (Continued)

 

Additional information on the Partnership’s revenue by product category for the periods ended December 31, 2015 and 2014 is as follows:

 

		2015			2014
		(in thousands)
Met coal revenue		$	15,391		$	26,058
Steam coal revenue			155,683			176,823
Other revenue			35,672			36,176
Total revenue		$	206,746		$	239,057

 

22. QUARTERLY FINANCIAL DATA (UNAUDITED)

 

(in thousands, except per unit data)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter(1)
2015:
Revenues		$	56,184		$	56,765		$	54,153		$	39,644
(Loss) from operations			(3,748	)		(6,959	)		(7,994	)		(32,644	)
Net (loss) from continuing operations			(4,562	)		(8,112	)		(9,306	)		(33,986	)
Income from discontinued operations			722			—			—			—
Net (loss)		$	(3,840	)	$	(8,112	)	$	(9,306	)	$	(33,986	)
Basic and diluted net (loss)/income per limited partner unit:
Common units:
Net (loss) per unit from continuing operations		$	(0.15	)	$	(0.27	)	$	(0.31	)	$	(1.14	)
Net income per unit from discontinued operations			0.02			—			—			—
Net (loss) per common unit, basic and diluted		$	(0.13	)	$	(0.27	)	$	(0.31	)	$	(1.14	)
Subordinated units:
Net (loss) per unit from continuing operations		$	(0.17	)	$	(0.27	)	$	(0.31	)	$	(1.14	)
Net income per unit from discontinued operations			0.02			—			—			—
Net (loss) per subordinated unit, basic and diluted		$	(0.15	)	$	(0.27	)	$	(0.31	)	$	(1.14	)
Weighted average number of limited partner units outstanding, basic:
Common units			16,692			16,702			16,706			16,756
Subordinated units			12,397			12,397			12,397			12,393
Weighted average number of limited partner units outstanding, diluted:
Common units			16,692			16,702			16,706			16,756
Subordinated units			12,397			12,397			12,397			12,393

 

(1)	Fourth quarter 2015 results include approximately $27.1 million of asset impairment and related charges.

 

 

RHINO RESOURCE PARTNERS LP

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

22. QUARTERLY FINANCIAL DATA (UNAUDITED) (Continued)

 

(in thousands, except per unit data)		First Quarter			Second Quarter			Third Quarter			Fourth Quarter(1)
2014:
Revenues		$	59,942		$	55,886		$	61,359		$	61,870
Income from operations			(868	)		(4,445	)		(6,108	)		(52,726	)
Net (loss)/ income from continuing operations			(4,966	)		(6,826	)		(8,864	)		(60,636	)
Income from discontinued operations			130,511			(52	)		(43	)		(74	)
Net (loss)/income		$	125,545		$	(6,878	)	$	(8,907	)	$	(60,710	)
Basic and diluted net (loss)/income per limited partner unit:
Common units:
Net income per unit from continuing operations		$	0.02		$	(0.05	)	$	(0.28	)	$	(2.03	)
Net income per unit from discontinued operations			4.40			(0.00	)		(0.00	)		(0.00	)
Net income per common unit, basic and diluted		$	4.42		$	(0.05	)	$	(0.28	)	$	(2.03	)
Subordinated units:
Net income per unit from continuing operations		$	(0.43	)	$	(0.49	)	$	(0.33	)	$	(2.08	)
Net income per unit from discontinued operations			4.40			(0.00	)		(0.00	)		(0.00	)
Net income per subordinated unit, basic and diluted		$	3.97		$	(0.49	)	$	(0.33	)	$	(2.08	)
Weighted average number of limited partner units outstanding, basic:
Common units			16,667			16,677			16,681			16,685
Subordinated units			12,397			12,397			12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units			16,673			16,677			16,681			16,685
Subordinated units			12,397			12,397			12,397			12,397

 

(1)	Fourth quarter 2014 results include approximately $45.3 million of asset impairment and related charges as well as an approximate $5.9 million charge for the impairment of the Partnership’s equity investment in the Rhino Eastern joint venture.

 

 

EXHIBIT C

 

SELECTED FINANCIAL DATA OF RHINO RESOURCES PARTNERS, LP

 

On April 18, 2016, the Rhino Resource Partners, LP completed a 1-for-10 reverse split on its common units and subordinated units. The following tables present a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended December 31, 2015 and 2014, which include the retrospective application of the 1-for-10 reverse unit split:

 

Year ended December 31, 2015		General Partner				Common Unitholders				Subordinated Unitholders
		(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net (loss) from continuing operations		$	(1,119	)		$	(31,491	)		$	(23,356	)
Net income from discontinued operations			14				406				302
Interest in net income		$	(1,105	)		$	(31,085	)		$	(23,054	)
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations		$	5			$	139			$	(144	)
Net income from discontinued operations			-				-				-
Interest in net income		$	5			$	139			$	(144	)
Interest in net (loss)/income for EPU purposes:
Net (loss) from continuing operations		$	(1,114	)		$	(31,352	)		$	(23,500	)
Net income from discontinued operations			14				406				302
Interest in net income		$	(1,100	)		$	(30,946	)		$	(23,198	)
Denominator:
Weighted average units used to compute basic EPU			n/a				1,671				1,240
Effect of dilutive securities — LTIP awards			n/a				-				-
Weighted average units used to compute diluted EPU			n/a				1,671				1,240
Net (loss)/income per limited partner unit, basic:
Net (loss) per unit from continuing operations			n/a			$	(18.76	)		$	(18.96	)
Net income per unit from discontinued operations			n/a				0.24				0.24
Net income per limited partner unit, basic			n/a			$	(18.52	)		$	(18.72	)
Net (loss)/income per limited partner unit, diluted:
Net (loss) per unit from continuing operations			n/a			$	(18.76	)		$	(18.96	)
Net income per unit from discontinued operations			n/a				0.24				0.24
Net income per limited partner unit, diluted			n/a			$	(18.52	)		$	(18.72	)

  

Year ended December 31, 2014		General Partner				Common Unitholders				Subordinated Unitholders
			(in thousands, except per unit data)
Numerator:
Interest in net income (as previously reported):
Net income from continuing operations		$	(1,626	)		$	(45,705	)		$	(33,962	)
Net income from discontinued operations			2,607				73,271				54,464
Interest in net income		$	981			$	27,566			$	20,502
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations		$	245			$	6,908			$	(7,153	)
Net income from discontinued operations			-				-				-
Interest in net income/(loss)		$	245			$	6,908			$	(7,153	)
Interest in net income/(loss) for EPU purposes (as restated):
Net income/(loss) from continuing operations		$	(1,381	)		$	(38,797	)		$	(41,115	)
Net income from discontinued operations			2,607				73,271				54,464
Interest in net income/(loss)		$	1,226			$	34,474			$	13,349
Denominator:
Weighted average units used to compute basic EPU			n/a				1,668				1,240
Effect of dilutive securities — LTIP awards			n/a				1				-
Weighted average units used to compute diluted EPU			n/a				1,669				1,240
Net income per limited partner unit, basic:
Net income per unit from continuing operations			n/a			$	(23.26	)		$	(33.16	)
Net income per unit from discontinued operations			n/a				43.93				43.93
Net income per limited partner unit, basic			n/a			$	20.67			$	10.77
Net income per limited partner unit, diluted:
Net income per unit from continuing operations			n/a			$	(23.26	)		$	(33.16	)
Net income per unit from discontinued operations			n/a				43.92				43.93
Net income per limited partner unit, diluted			n/a			$	20.66			$	10.77

  

 

EXHIBIT D

 

ROYAL ENERGY RESOURCES, INC.

PRO FORMA (UNAUDITED) FINANCIAL STATEMENTS AS OF AND

FOR THE 12 MONTH PERIOD ENDED DECEMBER 31, 2015

 

Royal Energy Resources, Inc. (“Royal” or the “Company”) is a Delaware corporation formed on March 22, 1999. The consolidated financial statements as of December 31, 2015 include the accounts of Royal and its wholly owned subsidiaries Blaze Minerals, LLC and Blue Grove Coal, LLC, both West Virginia limited liability companies.

 

On January 21, 2016, the board of directors of the Company elected to change the Company’s fiscal year end to December 31 from August 31. Accordingly, the Company filed a transition report on Form 10-Q containing unaudited financial statements for the period from September 1, 2015 to December 31, 2015, together with comparative financial statements for the same 2014 period. In accordance with Rule 13a-10(c), the financial statements for Royal for the year ended December 31, 2015 have not been audited.

 

Rhino Resource Partners LP (“Rhino”) is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor” or the “Operating Company”). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Illinois, Kentucky, Ohio, West Virginia and Utah. The majority of sales are made to domestic utilities and other coal-related organizations in the United States. In addition to operating coal properties, the Operating Company manages and leases coal properties and collects royalties from such management and leasing activities.

 

The financial statements for Rhino are the audited financial statements included in its Form 10-K as of December 31, 2015 and for the year then ended.

 

Commencing January 21, 2016 and ending March 21, 2016, Royal entered into three separate transactions which resulted in Royal owning the general partner of Rhino, and approximately 86.8% of the Common Units and 76.5% of the Subordinated Units of Rhino.

 

The following pro forma (unaudited) financial statements include the financial statements described above for Royal and Rhino. The historical financial information has been adjusted to reflect certain adjustments to the historical financial information to reflect the revised asset valuations and related expense adjustments to give effect to the lower valuation.

 

The accompanying pro forma financial statements and pro forma adjustments and notes thereto should be read in conjunction with the most recent audited and unaudited financial statements of Royal and Rhino. The accompanying pro forma combined financial statements include pro forma calculations and adjustments that are based on estimates and as such may not necessarily represent what the actual combined financial statements would have been had the acquisition occurred on January 1, 2015.

 

The pro forma unaudited financial statements are provided for informational purposes only. Additionally, the pro forma unaudited financial statements are not necessarily, and should not be assumed to be, an indication of the results that would have been achieved had the acquisition occurred on January 1, 2015 or that may be achieved in the future. Pro forma financial statements do not include all required GAAP financial statement disclosures.

 

 

Royal Energy Resources, Inc.          

Pro Forma (Unaudited) Balance Sheet          

As of December 31, 2015          

(thousands)          

            

		Royal				Rhino								Pro
		Energy				Resourse								Forma
		Resources				Partners								Adjust-
		Inc.				LP								ments				Combined
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	7,104			$	78				1			$	(6,500	)		$	682
Accounts receivable, net			31				14,569												14,600
Inventories							8,570												8,570
Advance royalties, current portion							753												753
Notes receivable - related party			55																55
Prepaid expenses and other			110				5,474												5,584
Total current assets			7,300				29,444								(6,500	)			30,244
PROPERTY PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs			7,066				604,514				2				(521,551	)			90,029
Less accumulated depreciation, depletion and amortization			-				(271,007	)			2				265,079				(5,928	)
Net property, plant and equipment			7,066				333,507								(256,472	)			84,101
Advance royalties, net of current portion							7,326												7,326
Investment in unconsolidated affiliates							7,578												7,578
Goodwill											4				2,363				2,363
Intangible assets, net			100				505												605
Other non-current assets							26,307												26,307
		$	14,466			$	404,667							$	(260,609	)		$	158,524
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable		$	123			$	9,336											$	9,459
Accrued expenses and other			221				14,102												14,323
Due to related parties			39																39
Current portion of long-term debt							41,479				1				(2,000	)			39,479
Notes payable - related party			404				-												404
Current portion of asset retirement obligations							767												767
Current portion of postretirement benefits							45												45
Total current liabilities			787				65,729								(2,000	)			64,516
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion							2,595												2,595
Asset retirement obligations, net of current portion			22,980				2				4,142				27,122
Other non-current liabilities							45,435												45,435
Total non-current liabilities			-				71,010								4,142				75,152
Total liabilities			787				136,739								2,142				139,668
STOCKHOLDERS' EQUITY:
Preferred stock			-																-
Common stock			1																1
Additional paid-in capital			20,337																20,337
Retained earnings			(6,659	)							5				2,141				(4,518	)
Total stockholders' equity			13,679				-								2,141				15,820
Minority interest											3				3,036				3,036
Members' interest							267,928				4				(267,928	)			-
Equity available for stockholders			13,679				267,928								(262,751	)			18,856
Total liabilities and stockholders' equity		$	14,466			$	404,667							$	(260,609	)		$	158,524

 

 

Royal Energy Resources, Inc.          

Pro Forma (Unaudited) Statement of Operations          

For the year ended December 31, 2015          

(thousands, except pre share amounts)          

            

		Royal				Rhino								Pro
		Energy				Resourse								Forma
		Resources				Partners								Adjust-
		Inc.				LP								ments				Combined
REVENUES:
Coal sales		$	281			$	171,074											$	171,355
Freight and handling revenues			-				2,790												2,790
Other revenues			-				32,882												32,882
Total revenues			281				206,746								-				207,027
COSTS AND EXPENSES:
Cost of operations			290				175,499												175,789
Freight and handling costs			-				2,693												2,693
Depreciation, deletion and amortization			235				33,181				6				(27,213	)			6,197
Selling, general and administrative			1,026				15,446												16,472
Asset impairment and related charges			534				31,564				7				(31,564	)			527
(Gain) on sale/disposal of assets, net			-				(292	)			8				292				(8	)
Total costs and expenses			2,085				258,091								(58,485	)			201,670
(LOSS) FROM OPERATIONS			(1,804	)			(51,345	)							58,485				5,357
OTHER (EXPENSE) INCOME:
Interest and other income			1				38												39
Interest income - related party			3																3
Equity in net income (loss) of unconsolidated affiliates			-				342												342
Loss on marketable securities			(2	)															(2	)
Loss on cancellation of acquisition			(250	)															(250	)
Interest expense:																			-
Related party			(10	)															(10	)
Other			-				(5,001	)											(5,001	)
Total other (expense) income			(258	)			(4,621	)							-				(4,879	)
(LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS			(2,062	)			(55,966	)							58,485				478
INCOME TAXES			-				-												-
NET (LOSS) FROM CONTINUING OPERATIONS			(2,062	)			(55,966	)							58,485				478
DISCONTINUED OPERATIONS			-				722				9				(722	)			-
NET (LOSS) INCOME			(2,062	)			(55,244	)							57,763				478
LESS INCOME ATTRIBUTABLE TO NON-CONTROLLING INTEREST											10				(378	)			(378	)
NET INCOME ATTRIBUTABLE TO COMPANY'S STOCKHOLDERS																		$	100
EARNINGS PER COMMON SHARE, BASIC AND FULLY DILUTED																		$	0.01
WEIGHTED AVERAGE SHARES OUTSTANDING																		$	12,367,290

 

 

 

Royal Energy Resources, Inc.

Notes to Adjustments to Pro Forma Financial Statements

 

Balance Sheet

 

	1.	Cash paid for purchase of interest in Rhino of $4,500,000 and the application of $2,000,000 to reduce Rhino’s line of credit.
	2.	Adjustment to reflect valuation of Rhino assets and related asset retirement obligation.
	3.	Adjust minority interest to its fair value of $2,658,000 plus its share of current earnings of $378,000.
	4.	Reduce members’ interest to 0 and convert equity to stockholders’ equity. The components of the reduction include the revaluation of assets, cash paid for the interest by Royal, the separation of minority interest, retained earnings and goodwill.
	5.	Retained earnings is increased by the revised Rhino earnings of $2,519,000 less the minority interest share of $378,000.

 

Statement of Operations

 

	6.	Reduction in depreciation, depletion and amortization as a result of the revaluation of the Rhino assets.
	7.	Elimination of asset impairment charges due to the revaluation of Rhino assets.
	8.	Eliminate gain on sale of assets due to the revaluation of Rhino assets.
	9.	Eliminate discontinued operations which do not affect ongoing operations.
	10.	Minority interest share of revised revenue from Rhino.