UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-K

 

[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
or
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to

 

Commission file number: 000-52547

 

Royal Energy Resources, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware (State or other jurisdiction of incorporation or organization)	11-3480036 (I.R.S. Employer Identification No.)
56 Broad Street, Suite 2 Charleston, SC (Address of principal executive offices)	29401 (Zip Code)

 

 

Registrant’s telephone number, including area code: (843) 900-7693

 

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

 

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $0.00001 par value

 

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

 

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

 

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

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

 

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

 

Large accelerated filer [  ]

Accelerated filer [X]

Non-accelerated filer [  ] (Do not check if a smaller reporting company)

Smaller reporting company [  ]

 

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

 

As of June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s equity held by non-affiliates of the registrant was approximately $91,808,202 based on the closing price of the registrant’s common stock on the OTC Bulletin Board on such date. As of March 20, 2017, the registrant had 17,184,095 shares of common stock and 51,000 shares of Series A Convertible Preferred Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

 

 

 

TABLE OF CONTENTS

 

	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	48
Item 4.	Mine Safety Disclosure	48
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	49
Item 6.	Selected Financial Data	50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	72
Item 8.	Financial Statements and Supplementary Data	72
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
Item 9A.	Controls and Procedures	73
Item 9B.	Other Information	74
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	74
Item 11.	Executive Compensation	77
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	85
Item 13.	Certain Relationships and Related Transactions, and Director Independence	86
Item 14.	Principal Accounting Fees and Services	92
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	92
Item 16.	Form 10-K Summary	98
	FINANCIAL STATEMENTS
	Index to Financial Statements	100

 

 

GLOSSARY OF KEY TERMS

 

ash: Inorganic material consisting of iron, alumina, sodium and other incombustible matter that are contained in coal. The composition of the ash can affect the burning characteristics of coal.

 

assigned reserves: Proven and probable reserves that have the permits and infrastructure necessary for mining.

 

as received: Represents an analysis of a sample as received at a laboratory.

 

Btu: British thermal unit, or Btu, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

 

Central Appalachia: Coal producing area in eastern Kentucky, western Virginia and southern West Virginia.

 

coal seam: Coal deposits occur in layers typically separated by layers of rock. Each layer is called a “seam.” A seam can vary in thickness from inches to a hundred feet or more.

 

coke: A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel.

 

fossil fuel: A hydrocarbon such as coal, petroleum or natural gas that may be used as a fuel.

 

GAAP: Generally accepted accounting principles in the United States.

 

high-vol metallurgical coal: Metallurgical coal that has a volatility content of 32% or greater of its total weight.

 

Illinois Basin: Coal producing area in Illinois, Indiana and western Kentucky.

 

limestone: A rock predominantly composed of the mineral calcite (calcium carbonate (CaCO₃)).

 

lignite: The lowest rank of coal. It is brownish-black with high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu.

 

low-vol metallurgical coal: Metallurgical coal that has a volatility content of 17% to 22% of its total weight.

 

mid-vol metallurgical coal: Metallurgical coal that has a volatility content of 23% to 31% of its total weight.

 

Metallurgical, or “met”, coal: The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal typically has a particularly high Btu but low ash and sulfur content.

 

net mineral acre: The product of (i) the percentage of oil and natural gas mineral rights owned in a given tract of land and (ii) the total surface acreage of such tract.

 

non-reserve coal deposits: Non-reserve coal deposits are coal-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration stage work. However, this coal does not qualify as a commercially viable coal reserve as prescribed by standards of the SEC until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geologic limitations, or both.

 

Northern Appalachia: Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

 

overburden: Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

 

 

preparation plant: Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process separates higher ash coal and may also remove some of the coal’s sulfur content.

 

probable (indicated) coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

 

proven (measured) coal reserves: Coal reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

 

reclamation: The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes “re-contouring” or reshaping the land to its approximate original contour, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations, but the majority of reclamation costs are incurred once mining operations cease. Reclamation is closely regulated by both state and federal laws.

 

recompletion: The process of re-entering an existing wellbore that is either producing or not producing and completing new oil and natural gas reservoirs in an attempt to establish or increase existing production.

 

reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

 

steam coal: Coal used by power plants and industrial steam boilers to produce electricity, steam or both. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

 

sulfur: One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide (SO2) is produced as a gaseous by-product of coal combustion.

 

surface mine: A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil overburden. Surface mines are also known as open-pit mines.

 

tons: A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds. A “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.

 

Western Bituminous region: Coal producing area located in western Colorado and eastern Utah.

 

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

 

This report contains “forward-looking statements.” Statements included in this report that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as statements regarding our future financial position, expectations with respect to our liquidity, capital resources and ability to continue as a going concern, plans for growth of the business, future capital expenditures, references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are reasonable as and when made. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in “Part 1, Item 1A. Risk Factors.” The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

 

	●	our ability to maintain adequate cash flow and to obtain additional financing necessary to fund our capital expenditures, meet working capital needs and maintain and grow our operations or our ability to obtain alternative financing upon the expiration of our amended and restated senior secured credit facility and our related ability to continue as a going concern;
	●	our future levels of indebtedness and compliance with debt covenants;
	●	sustained depressed levels or further declines in coal prices, which depend upon several factors such as the supply of domestic and foreign coal, the demand for domestic and foreign coal, governmental regulations, price and availability of alternative fuels for electricity generation and prevailing economic conditions;
	●	declines in demand for electricity and coal;
	●	current and future environmental laws and regulations, which could materially increase operating costs or limit our ability to produce and sell coal;
	●	extensive government regulation of mine operations, especially with respect to mine safety and health, which imposes significant actual and potential costs;
	●	difficulties in obtaining and/or renewing permits necessary for operations;
	●	a variety of operating risks, such as unfavorable geologic conditions, adverse weather conditions and natural disasters, mining and processing equipment unavailability, failures and unexpected maintenance problems and accidents, including fire and explosions from methane;
	●	poor mining conditions resulting from the effects of prior mining;
	●	the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives;
	●	fluctuations in transportation costs or disruptions in transportation services, which could increase competition or impair our ability to supply coal;
	●	a shortage of skilled labor, increased labor costs or work stoppages;
	●	our ability to secure or acquire new or replacement high-quality coal reserves that are economically recoverable;
	●	material inaccuracies in our estimates of coal reserves and non-reserve coal deposits;

 

 

	●	existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds, which could affect coal consumers and reduce demand for coal;
	●	federal and state laws restricting the emissions of greenhouse gases;
	●	our ability to acquire or failure to maintain, obtain or renew surety bonds used to secure obligations to reclaim mined property;
	●	our dependence on a few customers and our ability to find and retain customers under favorable supply contracts;
	●	changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices;
	●	changes in governmental regulation of the electric utility industry;
	●	defects in title in properties that we own or losses of any of our leasehold interests;
	●	our ability to retain and attract senior management and other key personnel;
	●	material inaccuracy of assumptions underlying reclamation and mine closure obligations; and
	●	weakness in global economic conditions.

 

Readers are cautioned not to place undue reliance on forward-looking statements. The forward-looking statements speak only as of the date made, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

 

PART I

 

Unless the context clearly indicates otherwise, references in this report to “Royal,” “we,” “our,” “us” or similar terms refer to Royal Energy Resources, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references in this report to “Rhino” or “the Partnership” or similar terms refer to Rhino Resource Partners, LP and its subsidiaries.

 

Item 1. Business.

 

We were originally organized in Delaware on March 22, 1999, with the name Webmarketing, Inc. (“Webmarketing”). On July 7, 2004, we revived our charter and changed our name from Webmarketing to World Marketing, Inc. In December 2007, we changed our name to Royal Energy Resources, Inc.

 

Prior to March 2015, we pursued gold, silver, copper and rare earth metals mining concessions in Romania and mining leases in the United States. We engaged in these activities through two subsidiaries, Development Resources, Inc., a Delaware corporation, and S.C. Golden Carpathian Resources S.R.L., a Romanian subsidiary (collectively, the “Subsidiaries”). Effective January 31, 2015, we entered into a Subsidiaries Option Agreement with Jacob Roth, our chairman and chief executive officer at that time. Under the Subsidiaries Option Agreement, we conveyed all of our assets to the Subsidiaries, to the extent any assets were not already owned by the Subsidiaries. The Subsidiaries Option Agreement also granted Mr. Roth an option to acquire the Subsidiaries for 49,000 shares of Series A Preferred Stock owned by Mr. Roth. The Subsidiaries Option Agreement also granted us a put option to acquire 49,000 shares of Series A Preferred Stock owned by Mr. Roth in consideration for the Subsidiaries. Both options could be exercised at any time within 45 days after closing of the stock purchase agreement among Mr. Roth, E-Starts Money Co. and William Tuorto.

 

On March 6, 2015, E-Starts Money Co. (“E-Starts”) acquired an aggregate of 7,188,560 shares of common stock from two holders. At the same time, William Tuorto acquired 810,316 shares of common stock from Mr. Roth, and 51,000 shares of Mr. Roth’s Series A Preferred Stock. Mr. Tuorto controls E-Starts. As a result, Mr. Tuorto became the beneficial owner of 7,998,876 shares of common stock (representing 92.3% of the outstanding common stock at that time) and 51% of the outstanding shares of Series A Preferred Stock. In connection with these transactions: (i) Frimet Taub resigned as a director and from all positions as an officer, employee, or independent contractor of us; (ii) Mr. Tuorto was appointed to the board seat vacated by Ms. Taub; (iii) Mr. Roth resigned as chairman of the board and Mr. Tuorto was appointed chairman of the board; (iv) Mr. Roth resigned as the Chief Executive Officer and Chief Financial Officer of us, and any other position as an officer, employee or independent contractor of us, and Mr. Tuorto was appointed as the Chief Executive Officer, Interim Chief Financial Officer, Secretary and Treasurer; and (v) Mr. Roth resigned as a director of us, provided that his resignation was not effective until the close of business on the 10th day after we distributed an information statement to its shareholders in accordance with SEC Rule 14f-1.

 

Since acquiring control of us, Mr. Tuorto has repositioned us to focus on the acquisition of natural resources assets, including coal, oil, gas and renewable energy, seeking to acquire high quality assets at distressed pricing in today’s fragmented energy markets. To that effect, we have entered into the following initial transactions:

 

	●	On April 17, 2015, we completed the acquisition of all issued and outstanding membership units of Blaze Minerals, LLC, a West Virginia limited liability company (“Blaze Minerals”), from Wastech, Inc. Blaze Minerals’ sole asset consists of 40,976 net acres of coal and coal-bed methane mineral rights, located across 22 counties in West Virginia (the “Mineral Rights”). We acquired Blaze Minerals by the issuance of 2,803,621 shares of common stock. The shares were valued at $7,009,053 based upon a per share value of $2.50 per share, which was the price at which we issued our common stock in a private placement at the time.
	●	On April 20, 2015, we exercised the put option to acquire the remaining 49,000 shares of Series A Preferred Stock owned by Mr. Roth in consideration for the Subsidiaries. As a result, Mr. Tuorto became the sole owner of all outstanding shares of Series A Preferred Stock, and we ceased to be in the business of pursuing gold, silver, copper and rare earth metals mining concessions in Romania.
	●	On May 14, 2015, we entered into an Option Agreement to acquire substantially all the assets of Wellston Coal, LLC (“Wellston”) for 500,000 shares of common stock. We paid a nominal sum for the option and had the right to complete the purchase through September 1, 2015 (which was later extended to December 31, 2016). Wellston owns approximately 1,600 acres of surface and 2,200 acres of mineral rights in McDowell County, West Virginia. We planned to close on the acquisition of Wellston after the satisfactory completion of due diligence on the assets and operations. On September 13, 2016, Wellston sold its assets to an unrelated third party, and we received a royalty of $1 per ton on the first 250,000 tons of coal mined from the property in consideration for a release of our lien on Wellston’s assets.

 

 

	●	On May 29, 2015, we entered into an Option Agreement with Blaze Energy Corp. (“Blaze Energy”) to acquire all of the membership units of Blaze Mining Company, LLC (“Blaze Mining”), which is a wholly-owned subsidiary of Blaze Energy. Under the Option Agreement, as amended, we had the right to complete the purchase through March 31, 2016 by the issuance of 1,272,858 shares of the Company’s common stock and payment of $250,000 in cash. Blaze Mining controlled operations for and had the right to acquire 100% ownership of the Alpheus Coal Impoundment reclamation site in McDowell County, West Virginia under a contract with Gary Partners, LLC, which owned the property. On February 22, 2016, we facilitated a series of transactions wherein: (i) Blaze Mining and Blaze Energy entered into an Asset Purchase Agreement to acquire substantially all of the assets of Gary Partners, LLC; (ii) Blaze Mining entered into an Assignment Agreement to assign its rights under the Asset Purchase Agreement to a third party; and (iii) we and Blaze Energy entered into an Option Termination Agreement, as amended, whereby the following royalties granted to Blaze Mining under the Assignment Agreement were assigned to us: a $1.25 per ton royalty on raw coal or coal refuse mined or removed from the property, and a $1.75 per ton royalty on processed or refined coal or coal refuse mined or removed from the property (the “Royalties”). Pursuant to the Option Termination Agreement, the parties thereby agreed to terminate the Option Agreement by the issuance of 1,750,000 shares of our common stock to Blaze Energy in consideration for the payment by Blaze Energy of $350,000 to us and the assignment by Blaze Mining of the Royalties to us. The transactions closed on March 22, 2016. Pursuant to an Advisory Agreement with East Coast Management Group, LLC (“ECMG”), we agreed to compensate ECMG $200,000 in cash; $0.175 of the $1.25 royalty on raw coal or coal refuse; and $0.25 of the $1.75 royalty on processed or refined coal for its services in facilitating the Option Termination Agreement.
	●	On June 10, 2015, we completed the acquisition of Blue Grove Coal, LLC (“Blue Grove”) and entered into an agreement to acquire G.S. Energy, LLC (“GS Energy”). GS Energy owns and leases approximately 6,000 acres of mineral rights in McDowell County, West Virginia. Blue Grove is an affiliate company of GS Energy and is the operator of the mine. We acquired Blue Grove by the issuance of 350,000 shares of common stock (which amount was later reduced to 10,000 shares by an amendment). We initially agreed to acquire GS Energy by the issuance of common shares with a market value of $9,600,000 on the date of closing, subject to a minimum and maximum number of shares of 1,250,000 and 1,750,000, respectively; however, the agreement was terminated in December 2015. We are still in discussions to acquire GS Energy.
	●	As described in more detail below, we acquired control of the Partnership on March 17, 2016.
	●	We are currently evaluating a number of additional coal mining assets for acquisition, including expanding and balancing our portfolio in the thermal coal space.

 

Acquisition of Rhino GP, LLC and Rhino Resource Partners, LLC

 

On January 21, 2016, we entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Wexford Capital, LP, and certain of its affiliates (collectively, “Wexford”), under which we agreed to purchase, and Wexford agreed to sell, a controlling interest in the Partnership in two separate transactions. Pursuant to the Purchase Agreement, in an initial closing, we purchased 676,912 common units of the Partnership from three holders for total consideration of $3,500,000. The common units purchased by us represented approximately 40.0% of the issued and outstanding common units of the Partnership and 23.1% of the total outstanding common units and subordinated units. The subordinated units are convertible into common units on a one for one basis upon the occurrence of certain conditions.

 

At a second closing held on March 17, 2016, we purchased all of the membership interest of Rhino GP, LLC (“Rhino GP”), and 945,526 subordinated units of the Partnership from two holders thereof, for aggregate consideration of $1,000,000. The subordinated units purchased by us represented approximately 76.5% of the issued and outstanding subordinated units of the Partnership, and when combined with the common units already owned by us, resulted in us owning approximately 55.4% of the outstanding Units of the Partnership. Rhino GP is the general partner of the Partnership, and in that capacity controls the Partnership.

 

 

On March 21, 2016, we entered into a Securities Purchase Agreement (the “SPA”) with the Partnership, under which we purchased 6,000,000 newly issued common units of the Partnership for $1.50 per common unit, for a total investment in the Partnership of $9,000,000. Closing under the SPA occurred on March 22, 2016. We paid a cash payment of $2,000,000 and issued a promissory note in the amount of $7,000,000 to the Partnership, which was payable without interest on the following schedule: $3,000,000 on or before July 31, 2016; $2,000,000 on or before September 30, 2016; and $2,000,000 on or before December 31, 2016. On May 13, 2016 and September 30, 2016, we paid the Partnership $3.0 million and $2.0 million, respectively, for the promissory note installments that were due July 31, 2016 and September 30, 2016, respectively.  On December 30, 2016, we and the Partnership agreed to extend the maturity date of the final installment of the note to December 31, 2018, and agreed that the note may be converted, at our option, at any time prior to December 31, 2018, into unregistered shares of our common stock at a price per share equal to seventy five percent (75%) of the volume weighted average closing price for the ninety (90) trading days preceding the date of conversion, provided that the average closing price shall be no less than $3.50 per share and no more than $7.50 per share.

 

Yorktown Transactions

 

On September 30, 2016, we entered into an Equity Exchange Agreement with the Partnership, Yorktown Partners LLC (“Yorktown”), Resources Partners Holdings, LLC (“Rhino Holdings”), an entity wholly-owned by Yorktown, and Rhino GP. The Equity Exchange Agreement provided that Yorktown would cause investment partnerships it controls to contribute their shares of common stock of Armstrong Energy, Inc. (“Armstrong”) to Rhino Holdings and Rhino Holdings would contribute those shares to the Partnership in exchange for 10 million newly issued common units of the Partnership. The Agreement also contemplated that Rhino GP would issue a 50% ownership of Rhino GP to Rhino Holdings.

 

On December 30, 2016, we entered into an Option Agreement with the Partnership, Rhino Holdings, Yorktown, and Rhino GP. Upon execution of the Option Agreement, the Partnership received an option (the “Call Option”) from Rhino Holdings to acquire all of the shares of common stock of Armstrong Energy that are currently owned by investment partnerships managed by Yorktown (the “Armstrong Shares”), which currently represents approximately 97% of the outstanding common stock of Armstrong Energy. Armstrong Energy is a coal producing company with approximately 554 million tons of proven and probable reserves and six mines located in the Illinois Basin in western Kentucky as of September 30, 2016. The Option Agreement stipulates that the Partnership can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting the Partnership the Call Option, the Partnership issued 5.0 million common units (the “Call Option Premium Units”) to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement stipulates the Partnership can exercise the Call Option and purchase the Armstrong Shares in exchange for a number of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings owning 51% of the fully diluted common units of the Partnership (determined without considering any common units issuable upon conversion of subordinated units or Series A Preferred Units of the Partnership). The purchase of the Armstrong Shares through the exercise of the Call Option would also require us to transfer a 51% ownership interest in Rhino GP to Rhino Holdings. The Partnership’s ability to exercise the Call Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the amendment of the Partnership’s revolving credit facility to permit the acquisition of Armstrong Energy. The percentage ownership of Armstrong Energy represented by the Armstrong Shares as of the date the Call Option is exercised is subject to dilution based upon the terms under which Armstrong Energy restructures its indebtedness, the terms of which have not been determined.

 

The Option Agreement also contains an option (the “Put Option”) granted by the Partnership to Rhino Holdings whereby Rhino Holdings has the right, but not the obligation, to cause the Partnership to purchase the Armstrong Shares from Rhino Holdings under the same terms and conditions discussed above for the Call Option. The exercise of the Put Option is dependent upon (i) the entry by Armstrong into an agreement with its bondholders to restructure its bonds and (ii) the termination and repayment of any outstanding balance under the Partnership’s revolving credit facility. In the event either the Partnership or Rhino GP fail to perform their obligations in the event Rhino Holdings exercises the Put Option, then Rhino Holdings and the Partnership each have the right to terminate the Option Agreement, in which event no party thereto shall have any liability to any other party under the Option Agreement, although Rhino Holdings shall be allowed to retain the Call Option Premium Units.

 

The Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement and the GP Amendment (defined below). The Partnership has entered into a non-disclosure agreement with Armstrong Energy under which it has inspection rights with regard to the books, records and operations of Armstrong Energy, and the Option Agreement provides that those rights shall continue until the Call Option or Put Option are exercised or expire. Upon the request by Rhino Holdings, the Partnership will also enter into a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding common units.

 

 

Pursuant to the Option Agreement, Rhino GP amended its Second Amended and Restated Limited Liability Company Agreement (“GP Amendment”). Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of Rhino GP as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director. Rhino Holdings has the right to appoint two members to the Rhino GP board of directors for as long as it continues to own 20% of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent to any delegation of authority to any committee of Rhino GP’s board. Upon the exercise of the Call Option or the Put Option, the Second Amended and Restated Limited Liability Company Agreement of Rhino GP, as amended, will be further amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors, and that the remaining director will be the chief executive officer of Rhino GP unless agreed otherwise.

 

Transactions with Weston Energy, LLC

 

First Weston Loan

 

On September 30, 2016, we entered into a Secured Promissory Note and a Pledge and Security Agreement with Weston Energy, LLC (“Weston”), under which we borrowed $2,000,000 from Weston (the “Loan”). Weston is an affiliate of Yorktown. The Loan bears interest at 8% per annum. All principal and accrued interest was originally due and payable on December 31, 2016. The Loan is payable, at our option of the Company, either in cash or in common units of the Partnership (“Rhino Units”). In the event we elect to pay the Loan in Rhino Units, the number of Rhino Units that will be conveyed to satisfy the Loan will be equal to Loan balance divided by 80% of the average of the high and low price of the Partnership’s common units for the twenty trading days prior to the date of payment. The proceeds of the Loan were used to make an installment payment of $2,000,000 due to the Partnership on September 30, 2016.

 

On December 30, 2016, Weston contributed the Loan to the Partnership in payment for 200,000 shares of Series A Preferred Stock issued by the Partnership at $10 per unit. We simultaneously entered into a letter agreement with the Partnership which extended the maturity date of the Loan to December 31, 2018, and provided that the Loan may be converted, at our option, at any time prior to December 31, 2018, into unregistered shares of our common stock at a price per share equal to seventy five percent (75%) of the volume weighted average closing price for the ninety (90) trading days preceding the date of conversion, provided that the such average closing price shall be no less than $3.50 per share and no more than $7.50 per share.

 

Second Weston Loan

 

On December 30, 2016, we entered into a second Secured Promissory Note and a Pledge and Security Agreement with Weston, under which we borrowed $2.0 million from Weston (the “Second Loan”). The Second Loan bears interest at 8% per annum. All principal and accrued interest was due and payable on January 15, 2017. The Loan was payable, at the option of Royal, either in cash or Rhino Units. In the event Royal elected to pay the Second Loan in Rhino Units, the number of Rhino Units that would be conveyed to satisfy the Second Loan would be equal to Second Loan balance divided by 80% of the average of the high and low price of the Partnership’s common units for the twenty trading days prior to the date of payment. The proceeds of the Second Loan were used to make an investment of $2.0 million in Series A Preferred Units of the Partnership on December 30, 2016.

 

On January 27, 2017, we sold the 2.0 million in Series A Preferred Units for their purchase price, and used the proceeds to repay the Second Loan in full.

 

About Rhino

 

History

 

The Partnership’s predecessor was formed in April 2003 by Wexford Capital. The Partnership was formed in April 2010 to own and control the coal properties and related assets owned by Rhino Energy LLC. On October 5, 2010, the Partnership completed its IPO. Its common units were originally listed on the New York Stock Exchange under the symbol “RNO”. In connection with the IPO, Wexford contributed their membership interests in Rhino Energy LLC to the Partnership, and in exchange the Partnership issued subordinated units and common units to Wexford and issued incentive distribution rights to Rhino GP, its general partner.

 

 

Since the formation of the Partnership’s predecessor in April 2003, it has completed numerous coal asset acquisitions with a total purchase price of approximately $357.5 million. Through these acquisitions and coal lease transactions, it has substantially increased its proven and probable coal reserves and non-reserve coal deposits. In addition, it has successfully grown its production through internal development projects. In addition to its coal acquisitions, in 2011 it began to invest in oil and natural gas assets and operations.

 

The Partnership is managed by the board of directors and executive officers of Rhino GP. Its operations are conducted through, and its operating assets are owned by its wholly owned subsidiary, Rhino Energy LLC, and its subsidiaries.

 

Current Operations

 

The Partnership is a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. The Partnership produces, processes and sells high quality coal of various steam and metallurgical grades from multiple coal producing basins in the United States. The Partnership markets its steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for its metallurgical coal are primarily steel and coke producers who use its coal to produce coke, which is used as a raw material in the steel manufacturing process. Its business includes investments in joint ventures to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. The Partnership has also invested in joint ventures that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.

 

The Partnership has a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2016, it controlled an estimated 256.9 million tons of proven and probable coal reserves, consisting of an estimated 203.5 million tons of steam coal and an estimated 53.4 million tons of metallurgical coal. In addition, as of December 31, 2016, it controlled an estimated 196.5 million tons of non-reserve coal deposits. Both its estimated proven and probable coal reserves and non-reserve coal deposits as of December 31, 2016 decreased when compared to the estimated tons and deposits reported as of December 31, 2015 due to the sale of its Elk Horn coal leasing business in August 2016. As part of the recent audits of its coal reserves and deposits performed by Marshall Miller & Associates, Inc., this outside expert performed an independent pro forma economic analysis using industry-accepted guidelines and this was used, in part, to classify tonnage as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions.

The Partnership operates underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that it operates will vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. In the third quarter of 2015, it temporarily idled a majority of its Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. The Partnership resumed mining operations at all of its Central Appalachia operations in 2016 to fulfill customer contracts that it secured for 2016 and 2017.

 

For the year ended December 31, 2016, the Partnership produced and sold approximately 3.3 million tons of coal.

 

The Partnership’s principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from its diverse asset base in order to resume, and, over time, increase its quarterly cash distributions. In addition, it continues to seek opportunities to expand and diversify its operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. We believe that such assets will allow the Partnership to grow its cash available for distribution and enhance stability of its cash flow.

 

The Partnership’s common units currently trade on the OTCQB Marketplace under the symbol “RHNO.” The Partnership’s common units previously traded on the NYSE until December 17, 2015, when the NYSE suspended trading after the Partnership failed to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for its common units. The Partnership is exploring the possibility of listing its common units on the NASDAQ Stock Market (“NASDAQ”), pending its capability to meet the NASDAQ initial listing standards.

 

 

Current Liquidity and Outlook of Rhino

 

As of December 31, 2016, the Partnership’s available liquidity was $13.0 million, including cash on hand of $0.1 million and $12.9 million available under its amended and restated credit agreement. On May 13, 2016, the Partnership entered into a fifth amendment (the “Fifth Amendment”) of its amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintained the amount available for letters of credit at $30 million. As of December 31, 2016, the Partnership met the requirements to extend the maturity date of the credit facility to December 31, 2017. In December 2016, the Partnership entered into a seventh amendment of its amended and restated credit agreement (the “Seventh Amendment”). The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million to a maximum of $55 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. For more information about its amended and restated credit agreement, please read “Part 1, Item 1-- Recent Developments-Amendments to Amended and Restated Credit Agreement.”

 

Since the Partnership’s credit facility has an expiration date of December 2017, we determined that its credit facility debt liability of $10.0 million at December 31, 2016 should be classified as a current liability on our consolidated balance sheet. The classification of the Partnership’s our credit facility balance as a current liability raises substantial doubt of our 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. However, the Partnership may be unable to complete such a transaction on terms acceptable to us or at all. If the Partnership is unable to extend the expiration date of the Partnership’s amended and restated credit facility, it will have to secure alternative financing to replace the credit facility by the expiration date of December 31, 2017 in order to continue its business operations. If the Partnership is unable to extend the expiration date of the Partnership’s amended and restated credit facility or secure a replacement facility, it will lose a primary source of liquidity, and it may not be able to generate adequate cash flow from operations to fund its business, including amounts that may become due under its credit facility. Furthermore, although met coal prices and demand have improved in recent months, if weak demand and low prices for steam coal persist and if met coal prices and demand weaken, the Partnership may not be able to continue to give the required representations or meet all of the covenants and restrictions included in its credit facility. If the Partnership violates any of the covenants or restrictions in its amended and restated credit agreement, including the maximum leverage ratio, some or all of its indebtedness may become immediately due and payable, and its lenders’ commitment to make further loans to it may terminate. If the Partnership is unable to give a required representation or it violates a covenant or restriction, then it will need a waiver from its lenders in order to continue to borrow under its amended and restated credit agreement. Although we believe the Partnership’s lenders loans are well secured under the terms of its amended and restated credit agreement, there is no assurance that the lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause the Partnership to further curtail our operations and reduce its spending and to alter its business plan. The Partnership may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of its liquidity constraints, it may be required to pursue such an option at an inopportune time. If the Partnership is not able to fund its liquidity requirements for the next twelve months, it may not be able to continue as a going concern. For more information about our liquidity and the Partnership’s credit facility, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources.”

 

 

The Partnership continues to take measures, including the suspension of cash distributions on its common and subordinated units and cost and productivity improvements, to enhance and preserve its liquidity so that it can fund its ongoing operations and necessary capital expenditures and meet its financial commitments and debt service obligations.

 

Recent Developments - Rhino

Fourth Amended and Restated Partnership Agreement of Limited Partnership

 

On December 30, 2016, Rhino GP amended the Partnership’s partnership agreement to create, authorize and issue the Series A preferred units. The Series A preferred units are a new class of equity security that rank senior to all classes or series of its equity securities with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units shall be entitled to receive annual distributions equal to the greater of (i) 50% of the CAM Mining free cash flow (as defined below) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. “CAM Mining free cash flow” is defined in its partnership agreement as (i) the total revenue of its Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for its Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by the Partnership from its Central Appalachia business segment. If the Partnership fails to pay any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and it will not be permitted to pay any distributions on its partnership interests that rank junior to the Series A preferred units, including its common units. The Series A preferred units will be liquidated in accordance with their capital accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances of their capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.

 

The Series A preferred units vote on an as-converted basis with the common units, and the Partnership is restricted from taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the incurrence, assumption or guaranty of indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to entities or assets that are acquired by the Partnership or its affiliates that is in existence at the time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of its Central Appalachia business segment, subject to certain exceptions.

 

Series A Preferred Unit Purchase Agreement

 

On December 30, 2016, the Partnership entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Agreement”) with Weston, an entity wholly owned by certain investment partnerships managed by Yorktown, and Royal. Under the Preferred Unit Agreement, Weston and Royal agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred units representing limited partner interests in the Partnership at a price of $10.00 per Series A preferred unit. The Series A preferred units have the preferences, rights and obligations set forth in the Partnership’s Fourth Amended and Restated Agreement of Limited Partnership, which is described below. In exchange for the Series A preferred units, Weston and Royal paid cash of $11.0 million and $2.0 million, respectively, to the Partnership, and Weston assigned to the Partnership a $2.0 million note receivable from Royal originally dated September 30, 2016 (the “Weston Promissory Note”).

 

The Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for as long as the Series A preferred units are outstanding, the Partnership will cause CAM Mining, LLC, one of its subsidiaries, (“CAM Mining”) to conduct its business in the ordinary course consistent with past practice and use reasonable best efforts to maintain and preserve intact its current organization, business and franchise and to preserve the rights, franchises, goodwill and relationships of its employees, customers, lenders, suppliers, regulators and others having business relationships with CAM Mining.

 

The Preferred Unit Agreement stipulates that upon the request of the holder of the majority of the Partnership’s common units following their conversion from Series A preferred units, the Partnership will enter into a registration rights agreement with such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights.

 

On January 27, 2017, we sold 100,000 of our Series A preferred units to Weston and the other 100,000 Series A preferred units to another third party.

 

 

Elk Horn Coal Leasing Disposition

 

In August 2016, the Partnership entered into an agreement to sell its Elk Horn coal leasing company to a third party for total cash consideration of $12.0 million. The Partnership received $10.5 million in cash consideration upon the closing of the Elk Horn transaction and the remaining $1.5 million of consideration will be paid in ten equal monthly installments of $150,000 on the 20th of each calendar month beginning on September 20, 2016. Elk Horn is a coal leasing company located in eastern Kentucky that provided us with coal royalty revenues from coal properties owned by Elk Horn and leased to third-party operators.

 

Amended and Restated Credit Agreement Amendments

 

On March 17, 2016, the Partnership’s Operating Company, as borrower, and the Partnership and certain of its subsidiaries, as guarantors, entered into a fourth amendment (the “Fourth Amendment”) of its Amended and Restated Credit Agreement. The Fourth Amendment amended the definition of change of control in the Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of its general partner.

 

On May 13, 2016, the Partnership entered into the Fifth Amendment of the Amended and Restated Credit Agreement (“Fifth Amendment”), which extended the term to July 31, 2017.

 

In July 2016, the Partnership entered into a sixth amendment (the “Sixth Amendment”) of its amended and restated senior secured credit facility that permitted the sale of Elk Horn that was discussed earlier.

 

In December, 2016, the Partnership entered into a seventh amendment of its amended and restated credit agreement (the “Seventh Amendment”). The Seventh Amendment allows for the Series A preferred units discussed above. The Seventh Amendment immediately reduces the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. A condition precedent to the effectiveness of the Seventh Amendment was the receipt of the $13.0 million of cash proceeds received by us from the issuance of the Series A preferred units discussed above, which was used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contributions as outlined in the previous amendments to its credit agreement. (See “—Liquidity and Capital Resources—Amended and Restated Credit Agreement” for further details on the debt amendments).

 

 

Distribution Suspension

 

Pursuant to its partnership agreement, the Partnership’s common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, the Partnership announced cash distributions per common unit at levels lower than the minimum quarterly distribution. Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2016, the Partnership has suspended the cash distribution on its common units. The Partnership has not paid any distribution on its subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect its cash flow, as well as covenants in its loan agreement that prevent it from making distributions on its units. The inability of the Partnership to make distributions on its common units could impact Royal’s cash flow while it lacks other revenue generating operations.

 

Coal Operations

 

Mining and Leasing Operations

 

As of December 31, 2016, the Partnership operated two mining complexes located in Central Appalachia (Tug River and Rob Fork). In the third quarter of 2015, the Partnership temporarily idled a majority of its Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. The Partnership resumed mining operations at all of its Central Appalachia operations in 2016 to fulfill customer contracts that it secured for 2016 and 2017.

 

In addition, the Partnership operated two mining complexes located in Northern Appalachia (Hopedale and Sands Hill). In the Western Bituminous region, the Partnership operated one mining complex located in Emery and Carbon Counties, Utah (Castle Valley). During 2014, the Partnership developed a new mining complex in the Illinois Basin, its Riveredge mine at its Pennyrile mining complex, which began production in mid-2014. The Pennyrile complex consists of one underground mine, a preparation plant and river loadout facility.

 

The Partnership defines a mining complex as a central location for processing raw coal and loading coal into railroad cars or trucks for shipment to customers. These mining complexes include seven active preparation plants and/or loadouts, each of which receive, blend, process and ship coal that is produced from one or more of its active surface and underground mines. All of the preparation plants are modern plants that have both coarse and fine coal cleaning circuits.

 

 

The following map shows the location of its coal mining and leasing operations as of December 31, 2016 (Note: the McClane Canyon mine in Colorado was permanently idled at December 31, 2013):

 

 

 

The Partnership’s surface mines include area mining and contour mining. These operations use truck and wheel loader equipment fleets along with large production tractors and shovels. The Partnership’s underground mines utilize the room and pillar mining method. These operations generally consist of one or more single or dual continuous miner sections which are made up of the continuous miner, shuttle cars, roof bolters, feeder and other support equipment. The Partnership currently owns most of the equipment utilized in its mining operations. The Partnership employs preventive maintenance and rebuild programs to ensure that its equipment is modern and well-maintained. The rebuild programs are performed either by an on-site shop or by third-party manufacturers.

 

The following table summarizes the Partnership’s mining complexes and production by region as of December 31, 2016.

 

Region		Preparation Plants and Loadouts		Transportation to Customers(1)		Number and Type of Active Mines(2)				Tons Produced for the Year Ended December 31, 2016 (3)
										(in million tons)
Central Appalachia
Tug River Complex (KY, WV)		Tug Fork & Jamboree(4)		Truck, Barge, Rail (NS)			2S			0.4
Rob Fork Complex (KY)		Rob Fork		Truck, Barge, Rail (CSX)			1U,1S			0.3
Northern Appalachia
Hopedale Complex (OH)		Nelms		Truck, Rail (OHC, WLE)			1U			0.3
Sands Hill Complex (OH)		Sands Hill(5)		Truck, Barge			1S			0.1
Illinois Basin
Taylorville Field (IL)		n/a		Rail (NS)			—			—
Pennyrile Complex (KY)		Preparation plant & river loadout		Barge			1U			1.3
Western Bituminous
Castle Valley Complex (UT)		Truck loadout		Truck			1U			0.9
McClane Canyon Mine (CO)(6)		n/a		Truck			—			—
Total							4U,4S			3.3

 

(1)	NS = Norfolk Southern Railroad; CSX = CSX Railroad; OHC = Ohio Central Railroad; WLE = Wheeling & Lake Erie Railroad.
(2)	Numbers indicate the number of active mines. U = underground; S = surface. All of its mines as of December 31, 2016 were company-operated.
(3)	Total production based on actual amounts and not rounded amounts shown in this table.
(4)	Jamboree includes only a loadout facility.
(5)	Includes only a preparation plant.
(6)	The McClane Canyon mine was permanently idled as of December 31, 2013.

 

Central Appalachia. For the year ended December 31, 2016, the Partnership operated two mining complexes located in Central Appalachia consisting of one active underground mine and three surface mines. For the year ended December 31, 2016, the mines at its Tug River and Rob Fork mining complexes produced an aggregate of approximately 0.4 million tons of steam coal and an estimated 0.3 million tons of metallurgical coal.

 

Tug River Mining Complex. The Partnership’s Tug River mining complex is located in Kentucky and West Virginia bordering the Tug River. This complex produces coal from two surface mines, which includes one high-wall mining unit. Coal production from these operations is delivered to the Tug Fork preparation plant for processing and then transported by truck to the Jamboree rail loadout for blending and shipping. Coal suitable for direct-ship to customers is delivered by truck directly to the Jamboree rail loadout from the mine sites. The Tug Fork plant is a modern, 350 tons per hour preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions. The Jamboree loadout is located on the Norfolk Southern Railroad and is a modern unit train, batch weigh loadout. This mining complex produced approximately 0.3 million tons of steam coal and approximately 0.1 million tons of metallurgical coal for the year ended December 31, 2016.

 

 

Rob Fork Mining Complex. The Partnership’s Rob Fork mining complex is located in eastern Kentucky and produces coal from one surface mine and one underground mine. The Rob Fork mining complex is located on the CSX Railroad and consists of a modern preparation plant utilizing heavy media circuitry that is capable of cleaning coarse and fine coal size fractions and a unit train loadout with batch weighing equipment. The mining complex has significant blending capabilities allowing the blending of raw coals with washed coals to meet a wide variety of customers’ needs. The Rob Fork mining complex produced approximately 0.1 million tons of steam coal and 0.2 million tons of metallurgical coal for the year ended December 31, 2016.

 

Northern Appalachia. For the year ended December 31, 2016, the Partnership operated two mining complexes located in Northern Appalachia consisting of one underground mine and two surface mines.

 

Hopedale Mining Complex. The Hopedale mining complex includes an underground mine located in Hopedale, Ohio approximately five miles northeast of Cadiz, Ohio. Coal produced from the Hopedale mine is first cleaned at its Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to its customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 0.3 million tons of steam coal for the year ended December 31, 2016.

 

Sands Hill Mining Complex. The Partnership currently operates one surface mine at its Sands Hill mining complex, located near Hamden, Ohio, and it permanently idled the second surface mine at this complex during the second half of 2016. The infrastructure includes a preparation plant along with a river front barge and dock facility on the Ohio River. The Sands Hill mining complex produced approximately 0.1 million tons of steam coal and approximately 0.4 million tons of limestone aggregate for the year ended December 31, 2016. Coal mining at its Sands Hill complex will cease during the first quarter of 2017 as market conditions for coal from this complex have continued to be weak. The Partnership will continue its limestone aggregate business at the Sands Hill complex for the next twelve to eighteen months as it has enough limestone inventory to process and sell for this time period. For the year ended December 31, 2016, these mines produced an aggregate of approximately 0.4 million tons of steam coal.

 

Western Bituminous Region. The Partnership operates one mining complex in the Western Bituminous region that produces coal from an underground mine located in Emery and Carbon Counties, Utah. The Partnership also had one underground mine located in the Western Bituminous region in Colorado (McClane Canyon) that was permanently idled at the end of 2013.

 

Castle Valley Mining Complex. The Partnership’s Castle Valley mining complex includes one underground mine located in Emery and Carbon Counties, Utah and includes coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. The Partnership produced approximately 0.9 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2016.

 

Illinois Basin. In May 2012, the Partnership completed the purchase of certain rights to coal leases and surface property that is contiguous to the Green River and located in Daviess and McLean counties in western Kentucky where it constructed a new underground mining complex. The coal leases and property are contiguous to the Green River. The property is fully permitted and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers.

 

Pennyrile Mining Complex. In mid-2014, it completed the initial construction of a new underground mining operation on the purchased property, referred to as its Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. Production from this underground mine began in mid-2014 and it produced approximately 1.3 million tons for the year ended December 31, 2016. The Partnership believes the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex. The Partnership has long-term sales contracts with local electric utility customers and it has other potential customers that it believes could lead to additional long-term sales agreements if it can successfully expand its production capacity at this operation.

 

 

Other Non-Mining Operations

 

In addition to its mining operations, the Partnership operates several subsidiaries which provide auxiliary services for its coal mining operations. Rhino Trucking provides its southeastern Ohio coal operations with reliable transportation to its customers where rail is not available. Rhino Services is responsible for mine-related construction, site and roadway maintenance and post-mining reclamation. Through Rhino Services, the Partnership plans and monitors each phase of its mining projects as well as the post-mining reclamation efforts. The Partnership also performs the majority of its drilling and blasting activities at its surface mines in-house rather than contracting to a third party.

 

Other Natural Resource Assets - Rhino

 

Oil and Natural Gas

 

In addition to its coal operations, the Partnership has invested in oil and natural gas assets and operations.

 

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 Energy (“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. The Partnership recorded its proportionate portion of the operating (losses)/gains for this investment during the nine months ended December 31, 2016 of approximately ($0.2 ) million.

In November 2014, the Partnership contributed its investment interest in a joint venture, Muskie Proppant LLC (“Muskie”) with affiliates of Wexford Capital that 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 to Mammoth Energy Partners LP (“Mammoth”) in return for a limited partner interest in Mammoth. Mammoth was formed to provide services to companies, which engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth provides 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 its investment interest in the Muskie entity for an investment interest in Mammoth. Thus, the Partnership determined that the non-cash exchange of its ownership interest in Muskie did not result in any gain or loss. In October 2016, the Partnership contributed its limited partner interests in Mammoth to Mammoth Energy Services, Inc. (“Mammoth Inc.”) in exchange for 234,300 shares of common stock of Mammoth Inc. The common stock of Mammoth Inc. began trading on the NASDAQ Global Select Market in October 2016 under the ticker symbol TUSK and the Partnership sold 1,953 shares during the initial public offering of Mammoth Inc. and received proceeds of approximately $27,000. The Partnership’s remaining shares of Mammoth Inc. are subject to a 180 day lock-up period from the date of Mammoth Inc.’s initial public offering. As of December 31, 2016, the Partnership recorded a fair market value adjustment of $1.6 million for the available-for-sale investment, which was recorded in other comprehensive income. The Partnership has included its investment in Mammoth and its prior investment in Muskie in its Other category for segment reporting purposes.  

 

Limestone

 

Incidental to its coal mining process, the Partnership mines limestone from reserves located at its Sands Hill mining complex and sell it as aggregate to various construction companies and road builders that are located in close proximity to the mining complex when market conditions are favorable. The Partnership believes that its production of limestone will provide us with an additional source of revenues at low incremental capital cost for the next twelve to eighteen months.

 

Coal Customers - Rhino

 

General

 

The Partnership’s primary customers for its steam coal are electric utilities, and the metallurgical coal the Partnership produces is sold primarily to domestic and international steel producers. For the year ended December 31, 2016, approximately 90.0% of its coal sales tons consisted of steam coal and approximately 10.0% consisted of metallurgical coal. For the year ended December 31, 2016, approximately 83.0% of its coal sales tons that the Partnership produced were sold to electric utilities. The majority of its electric utility customers purchase coal for terms of one to three years, but it also supplies coal on a spot basis for some of its customers. For the year ended December 31, 2016, the Partnership derived approximately 87.4% of its total coal revenues from sales to its ten largest customers, with affiliates of its top three customers accounting for approximately 48.5% of its coal revenues for that period: PPL Corporation (26.2%); PacificCorp Energy (12.2%); and Big Rivers (10.1%).

 

 

Coal Supply Contracts

 

For the year ended December 31, 2016, approximately 90% of the Partnership’s aggregate coal tons sold were sold through supply contracts. The Partnership expects to continue selling a significant portion of its coal under supply contracts. As of December 31, 2016, the Partnership had commitments under supply contracts to deliver annually scheduled base quantities as follows:

 

Year		Tons (in thousands)				Number of customers
2017			3,669				14
2018			701				5

 

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

 

Quality and volumes for the coal are stipulated in coal supply contracts, and in some instances buyers have the option to vary annual or monthly volumes. Most of the Partnership’s coal supply contracts contain provisions requiring it to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Some of its contracts specify approved locations from which coal may be sourced. Some of its contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions, mine closures, or serious transportation problems that affect it or unanticipated plant outages that may affect the buyers.

 

The terms of its coal supply contracts result from competitive bidding procedures and extensive negotiations with customers. As a result, the terms of these contracts, including price adjustment features, price re-opener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions, vary significantly by customer.

 

Transportation

 

The Partnership ships coal to its customers by rail, truck or barge. The majority of its coal is transported to customers by either the CSX Railroad or the Norfolk Southern Railroad in eastern Kentucky and by the Ohio Central Railroad or the Wheeling & Lake Erie Railroad in Ohio. In addition, in southeastern Ohio, the Partnership uses its own trucking operations to transport coal to its customers where rail is not available. The Partnership uses third-party trucking to transport coal to its customers in Utah. For its Pennyrile complex in western Kentucky, coal is transported to its customers via barge from its river loadout on the Green River located on its Pennyrile mining complex. In addition, coal from certain of its Central Appalachia and southern Ohio mines is located within economical trucking distance to the Big Sandy River and/or the Ohio River and can be transported by barge. It is customary for customers to pay the transportation costs to their location.

 

The Partnership believes that it has good relationships with rail carriers and truck companies due, in part, to its modern coal-loading facilities at its loadouts and the working relationships and experience of its transportation and distribution employees.

 

 

Suppliers - Rhino

 

Principal supplies used in the Partnership’s business include diesel fuel, explosives, maintenance and repair parts and services, roof control and support items, tires, conveyance structures, ventilation supplies and lubricants. The Partnership uses third-party suppliers for a significant portion of its equipment rebuilds and repairs, drilling services and construction.

 

The Partnership has a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods and to support the mining and coal preparation plants. The Partnership is not dependent on any one supplier in any region. The Partnership promotes competition between suppliers and seek to develop relationships with those suppliers whose focus is on lowering its costs. The Partnership seeks suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

 

Competition - Rhino

 

The coal industry is highly competitive. There are numerous large and small producers in all coal producing regions of the United States and the Partnership competes with many of these producers. The Partnership’s main competitors include Alliance Resource Partners LP, Alpha Natural Resources, Inc., Arch Coal, Inc., Booth Energy Group, Murray Energy Corporation, Foresight Energy LP, Westmoreland Resource Partners, LP and Bowie Resource Partners LLC.

 

The most important factors on which the Partnership competes are coal price, coal quality and characteristics, transportation costs and the reliability of supply. Demand for coal and the prices that the Partnership will be able to obtain for its coal are closely linked to coal consumption patterns of the domestic electric generation industry and international consumers. These coal consumption patterns are influenced by factors beyond its control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, availability, quality and price of competing sources of fuel such as natural gas, oil and nuclear, and alternative energy sources such as hydroelectric power and wind power.

 

Regulation and Laws

 

The Partnership’s current operations are, and future coal mining operations that we acquire will be, subject to regulation by federal, state and local authorities on matters such as:

 

	●	employee health and safety;
	●	governmental approvals and other authorizations such as mine permits, as well as other licensing requirements;
	●	air quality standards;
	●	water quality standards;
	●	storage, treatment, use and disposal of petroleum products and other hazardous substances;
	●	plant and wildlife protection;
	●	reclamation and restoration of mining properties after mining is completed;
	●	the discharge of materials into the environment, including waterways or wetlands;
	●	storage and handling of explosives;
	●	wetlands protection;
	●	surface subsidence from underground mining;
	●	the effects, if any, that mining has on groundwater quality and availability; and
	●	legislatively mandated benefits for current and retired coal miners.

 

 

In addition, many of our customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for our coal. The possibility exists that new laws or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a significant impact on our mining operations, oil and natural gas investments, or our customers’ ability to use coal. Moreover, environmental citizen groups frequently challenge coal mining, terminal construction, and other related projects.

 

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

 

While it is not possible to quantify the costs of compliance with applicable federal and state laws and regulations, those costs have been and are expected to continue to be significant. Nonetheless, capital expenditures for environmental matters have not been material in recent years. The Partnership has accrued for the present value of estimated cost of reclamation and mine closings, including the cost of treating mine water discharge when necessary. The accruals for reclamation and mine closing costs are based upon permit requirements and the costs and timing of reclamation and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if the Partnership later determined these accruals to be insufficient. Compliance with these laws and regulations has substantially increased the cost of coal mining for all domestic coal producers. Most of the statutes discussed below apply to exploration and development activities associated with our oil and natural gas investments as well, and therefore we do not present a separate discussion of statutes related to those activities.

 

Mining Permits and Approvals

 

Numerous governmental permits or approvals are required for coal mining operations. When we apply for these permits and approvals, we are often required to assess the effect or impact that any proposed production of coal may have upon the environment. Final guidance released by the CEQ regarding climate change considerations in the NEPA analyses may increase the likelihood of future challenges to the NEPA documents prepared for actions requiring federal approval. The permit application requirements may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations in certain locations. In addition, these permits and approvals can result in the imposition of numerous restrictions on the time, place and manner in which coal mining operations are conducted. Future laws and regulations may emphasize more heavily the protection of the environment and, as a consequence, our activities may be more closely regulated. Laws and regulations, as well as future interpretations or enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs, or delays, interruptions or terminations of operations, the extent of any of which cannot be predicted. For example, in January 2016, the federal Bureau of Land Management announced a moratorium on new coal leases for federal lands. The moratorium does not affect existing leases. In addition, the permitting process for certain mining operations can extend over several years, and can be subject to judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We may experience difficulty and/or delay in obtaining mining permits in the future.

 

Regulations provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although, like other coal companies, we have been cited for violations in the ordinary course of business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

 

Before commencing mining on a particular property, we must obtain mining permits and approvals by state regulatory authorities of a reclamation plan for restoring, upon the completion of mining, the mined property to its approximate prior condition, productive use or other permitted condition.

 

Mine Health and Safety Laws

 

Stringent safety and health standards have been in effect since the adoption of the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 (the “Mine Act”), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards and imposed comprehensive safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Mine Safety and Health Administration (“MSHA”) monitors compliance with these laws and regulations. In addition, the states where we operate also have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal industry are complex, rigorous and comprehensive, and have a significant effect on our operating costs.

 

 

The Mine Act is a strict liability statute that requires mandatory inspections of surface and underground coal mines and requires the issuance of enforcement action when it is believed that a standard has been violated. A penalty is required to be imposed for each cited violation. Negligence and gravity assessments result in a cumulative enforcement scheme that may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act contains criminal liability provisions. For example, criminal liability may be imposed for corporate operators who knowingly or willfully authorize, order or carry out violations. The Mine Act also provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly authorize, order or carry out violations.

 

The Partnership has developed a health and safety management system that, among other things, includes training regarding worker health and safety requirements including those arising under federal and state laws that apply to our mines. In addition, our health and safety management system tracks the performance of each operational facility in meeting the requirements of safety laws and company safety policies. As an example of the resources we allocate to health and safety matters, our safety management system includes a company-wide safety director and local safety directors who oversee safety and compliance at operations on a day-to-day basis. We continually monitor the performance of our safety management system and from time-to-time modify that system to address findings or reflect new requirements or for other reasons. The Partnership has even integrated safety matters into our compensation and retention decisions. For instance, our bonus program includes a meaningful evaluation of each eligible employee’s role in complying with, fostering and furthering our safety policies.

 

We evaluate a variety of safety-related metrics to assess the adequacy and performance of our safety management system. For example, we monitor and track performance in areas such as “accidents, reportable accidents, lost time accidents and the lost-time accident frequency rate” and a number of others. Each of these metrics provides insights and perspectives into various aspects of our safety systems and performance at particular locations or mines generally and, among other things, can indicate where improvements are needed or further evaluation is warranted with regard to the system or its implementation. An important part of this evaluation is to assess our performance relative to certain national benchmarks.

 

For the year ended December 31, 2016 the Partnership’s average MSHA violations per inspection day was 0.25 as compared to the most recent national average of 0.67 violations per inspection day for coal mining activity as reported by MSHA, or 62.69% below this national average.

 

Mining accidents in the last several years in West Virginia, Kentucky and Utah have received national attention and instigated responses at the state and national levels that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. For example, in 2014, MSHA adopted a final rule to lower miners’ exposure to respirable coal mine dust. The rule had a phased implementation schedule. The second phase of the rule went into effect in February 2016, and requires increased sampling frequency and the use of continuous personal dust monitors. In August 2016, the third and final phase of the rule became effective, reducing the overall respirable dust standard in coal mines from 2.0 to 1.5 milligrams per cubic meter of air. Additionally, in September 2015, MSHA issued a proposed rule requiring the installation of proximity detection systems on coal hauling machines and scoops. The rulemaking record for this proposed rule was closed on December 15, 2016, but on January 9, 2017, MSHA published a notice reopening the record and extending the comment period for this proposed rule for 30 days. 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. In addition, more stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. For example, in 2006, the Mine Improvement and New Emergency Response Act of 2006, or MINER Act, was enacted. The MINER Act significantly amended the Mine Act, requiring improvements in mine safety practices, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection and enforcement activities. Since passage of the MINER Act in 2006, enforcement scrutiny has increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. For example, 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 result in increased civil penalty assessments for medium and larger mine operators and contractors by 300 to 1,000 percent. MSHA proposed some revisions to the original proposed rule in February 2015, but, to date, has not taken any further action. Other states have proposed or passed similar bills, resolutions or regulations addressing enhanced mine safety practices and increased fines and penalties. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine incident, have resulted in more inspection hours at mine sites, increased number of inspections and increased issuance of the number and severity of enforcement actions and the passage of new laws and regulations. These trends are likely to continue.

 

 

Indeed, in 2013, MSHA began implementing its recently released Pattern of Violation (“POV”) regulations under the Mine Act. Under this regulation, MSHA eliminated the ninety (90) day window to take corrective action and engage in mitigation efforts for mine operators who met certain initial POV screening criteria. Additionally, MSHA will make POV determinations based upon enforcement actions as issued, rather than enforcement actions that have been rendered final following the opportunity for administrative or judicial review. After a mine operator has been placed on POV status, MSHA will thereafter issue an order withdrawing miners from the area affected by any enforcement action designated by MSHA as posing a significant and substantial, or S&S, hazard to the health and/or safety of miners. Further, once designated as a POV mine, a mine operator can be removed from POV status only upon: (1) a complete inspection of the entire mine with no S&S enforcement actions issued by MSHA; or (2) no POV-related withdrawal orders being issued by MSHA within ninety (90) days of the mine operator being placed on POV status. Although it remains to be seen how these new regulations will ultimately affect production at our mines, they are consistent with the trend of more stringent enforcement.

 

From time to time, certain portions of individual mines have been required to suspend or shut down operations temporarily in order to address a compliance requirement or because of an accident. For instance, MSHA issues orders pursuant to Section 103(k) that, among other things, call for operations in the area of the mine at issue to suspend operations until compliance is restored. Likewise, if an accident occurs within a mine, the MSHA requirements call for all operations in that area to be suspended until the circumstance leading to the accident has been resolved. During the fiscal year ended December 31, 2016 (as in earlier years), the Partnership received such orders from government agencies and has experienced accidents within its mines requiring the suspension or shutdown of operations in those particular areas until the circumstances leading to the accident have been resolved. While the violations or other circumstances that caused such an accident were being addressed, other areas of the mine could and did remain operational. These circumstances did not require the Partnership to suspend operations on a mine-wide level or otherwise entail material financial or operational consequences for it. Any suspension of operations at any one of the Partnership’s locations that may occur in the future may have material financial or operational consequences for us.

 

It is the Partnership’s practice to contest notices of violations in cases in which it believes it has a good faith defense to the alleged violation or the proposed penalty and/or other legitimate grounds to challenge the alleged violation or the proposed penalty. The Partnership exercises substantial efforts toward achieving compliance at its mines. For example, it has further increased its focus with regard to health and safety at all of its mines. These efforts include hiring additional skilled personnel, providing training programs, hosting quarterly safety meetings with MSHA personnel and making capital expenditures in consultation with MSHA aimed at increasing mine safety. We believe that these efforts have contributed, and continue to contribute, positively to safety and compliance at the Partnership’s mines. In “Part 1, Item 4. Mine Safety Disclosure” and in Exhibit 95.1 to this Annual Report on Form 10-K, we provide additional details on how the Partnership monitors safety performance and MSHA compliance, as well as provide the mine safety disclosures required pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

 

Black Lung Laws

 

Under the Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, coal mine operators must make payments of black lung benefits to current and former coal miners with black lung disease, some survivors of a miner who dies from this disease, and to fund a trust fund for the payment of benefits and medical expenses to claimants who last worked in the industry prior to January 1, 1970. To help fund these benefits, a tax is levied on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price. This excise tax does not apply to coal that is exported outside of the United States. In 2016, we recorded approximately $3.0 million of expense related to this excise tax.

 

The Patient Protection and Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. We may also be liable under state laws for black lung claims that are covered through either insurance policies or state programs.

 

 

Workers’ Compensation

 

The Partnership is required to compensate employees for work-related injuries under various state workers’ compensation laws. The states in which we operate consider changes in workers’ compensation laws from time to time. Its costs will vary based on the number of accidents that occur at our mines and other facilities, and its costs of addressing these claims. The Partnership is insured under the Ohio State Workers Compensation Program for our operations in Ohio. Its remaining operations, including Central Appalachia and the Western Bituminous region, are insured through Rockwood Casualty Insurance Company.

 

Surface Mining Control and Reclamation Act (“SMCRA”)

 

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, including the surface effects of underground coal mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, the Partnership reclaims and restores the mined areas by grading, shaping and preparing the soil for seeding. Upon completion of mining, reclamation generally is completed by seeding with grasses or planting trees for a variety of uses, as specified in the approved reclamation plan. We believe the Partnership is in compliance in all material respects with applicable regulations relating to reclamation.

 

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. The act requires that we restore the surface to approximate the original contours as soon as practicable upon the completion of surface mining operations. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Mine operators can also be responsible for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of long-wall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed prior to SMCRA’s adoption in 1977. The maximum tax for the period from October 1, 2012 through September 30, 2021, has been decreased to 28 cents per ton on surface mined coal and 12 cents per ton on underground mined coal. However, this fee is subject to change. The President’s Budget for Fiscal Year 2017 proposes to restore fees on coal production to pre-2006 levels in order to fund the reclamation of abandoned mines. If enacted into law, this proposal would increase the fees on surface mining to $0.35 per ton and increase the fees on underground mining to $0.15 per ton. Given the market for coal, it is unlikely that coal mining companies would be able to recover all of these fees from their customers. As of December 31, 2016, the Partnership had accrued approximately $23.3 million for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

 

After a mine application is submitted, public notice or advertisement of the proposed permit action is required, which is followed by a public comment period. It is not uncommon for a SMCRA mine permit application to take over two years to prepare and review, depending on the size and complexity of the mine, and another two years or even longer for the permit to be issued. The variability in time frame required to prepare the application and issue the permit can be attributed primarily to the various regulatory authorities’ discretion in the handling of comments and objections relating to the project received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of judicial challenges related to the specific permit or another related company’s permit.

 

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

 

 

In addition, a February 2014 decision by the U.S. District Court for the District of Columbia invalidated the Office of Surface Mining Reclamation and Enforcement’s (“OSM”) 2008 Stream Buffer Zone Rule, which prohibited mining disturbances within 100 feet of streams, subject to various exemptions. In December 2016, the OSM published the final Stream Protection Rule, which, among other things, would require operators to test and monitor conditions of streams they might impact before, during and after mining. The final rule took effect in January 2017 and would have required mine operators to collect additional baseline data about the site of the proposed mining operation and adjacent areas; imposed additional surface and groundwater monitoring requirements; enacted specific requirements for the protection or restoration of perennial and intermittent streams; and imposed additional bonding and financial assurance requirements. However, in February 2017, both the House and the Senate passed measures to revoke the Stream Protection Rule under the Congressional Review Act (“CRA”), which gives Congress the ability to repeal regulations promulgated in the last 60 days of the congressional session. President Trump signed the resolution on February 16, 2017 and, pursuant to the CRA, the Stream Protection Rule “shall have no force or effect” and OSM cannot promulgate a substantially similar rule absent future legislation. Whether Congress will enact future legislation to require a new Stream Protection Rule remains uncertain. A new Stream Protection Rule, or other new SMCRA regulations, could result in additional material costs, obligations, and restrictions associated with the Partnership’s operations.

 

Surety Bonds

 

Federal and state laws require a mine operator to secure the performance of its reclamation obligations required under SMCRA through the use of surety bonds or other approved forms of performance security to cover the costs the state would incur if the mine operator were unable to fulfill its obligations. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In August 2016, the OSMRE issued a Policy Advisory discouraging state regulatory authorities from approving self-bonding arrangements. The Policy Advisory indicated that the OSM would begin more closely reviewing instances in which states accept self-bonds for mining operations. In the same month, the OSM also announced that it was beginning the rulemaking process to strengthen regulations on self-bonding. In addition, surety bond costs have increased while the market terms of surety bond have generally become less favorable. It is possible that surety bonds issuers may refuse to renew bonds or may demand additional collateral upon those renewals. The Partnership’s failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on its ability to produce coal, which could affect its profitability and cash flow.

 

As of December 31, 2016, the Partnership had approximately $48.9 million in surety bonds outstanding to secure the performance of its reclamation obligations. It may be required to increase these amounts as a result of recent developments in West Virginia and Kentucky. In 2011, West Virginia passed legislation that provides for a minimum incremental bonding rate in lieu of a minimum bond amount that applies regardless of acreage. In addition, the Kentucky Department for Natural Resources and the Office of Surface Mining Reclamation and Enforcement Lexington Field Office executed an Action Plan for Improving the Adequacy of Kentucky Performance Bond Amounts, which provides for, among other things, revised bond computation protocols.

 

Air Emissions

 

The federal Clean Air Act (the “CAA”) and similar state and local laws and regulations, which regulate emissions into the air, affect coal mining operations both directly and indirectly. The CAA directly impacts the Partnership’s coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, on sources that emit various hazardous and non-hazardous air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other industrial consumers of coal, including air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds. There have been a series of recent federal rulemakings from the U.S. Environmental Protection Agency, or EPA, which are focused on emissions from coal-fired electric generating facilities. For example, In June 2015, the United States Supreme Court decided Michigan v. the EPA, which held that the EPA should have considered the compliance costs associated with its Mercury and Air Toxics Standards, or MATS, in deciding to regulate power plants under Section 112(n)(1) of the Clean Air Act. The Court did not vacate the MATS rule, and MATS has remained in place. In April 2016, EPA published its final supplemental finding that it is “appropriate and necessary” to regulate coal and oil-fired units under Section 112 of the Clean Air Act. In August 2016, EPA denied two petitions for reconsideration of startup and shutdown provisions in MATS, leaving in place the startup and shutdown provisions finalized in November 2014. The MATS rule was expected to result in the retirement of certain older coal plants. It remains to be seen whether any power plants may reevaluate their decision to retire following the Supreme Court’s decision and EPA’s recent actions, or whether plants that have already installed certain controls to comply with MATS will continue to operate them at all times. Installation of additional emissions control technology and additional measures required under laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans, or SIPs, could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

 

 

In addition to the greenhouse gas (“GHG”) regulations discussed below, air emission control programs that affect the Partnership’s operations, directly or indirectly, through impacts to coal-fired utilities and other manufacturing plants, include, but are not limited to, the following:

 

	●	The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels.
	●	On July 6, 2011, the EPA finalized the Cross State Air Pollution Rule (“CSAPR”), which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions was to commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While the CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and, on December 30, 2011, the D.C. Circuit stayed the rule and advised that the EPA was expected to continue administering the Clean Air Interstate Rule until the pending challenges are resolved. The court vacated the CSAPR on August 21, 2012, in a two to one decision, concluding that the rule was beyond the EPA’s statutory authority. The U.S. Supreme Court on April 29, 2014 reversed the D.C. Circuit and upheld the CSAPR, concluding generally that the EPA’s development and promulgation of CSAPR was lawful, while acknowledging the possibility that under certain circumstances some states may have a basis to bring a particularized, as-applied challenge to the rule. In October 2014, the D.C. Circuit filed an order lifting its stay of CSAPR and addressing a number of preliminary motions regarding the implementation of the Supreme Court’s remand. On remand, the D.C. Circuit court held on July 28, 2015 that certain of EPA’s Phase II emission budgets were invalid because they required more emissions reductions than necessary to achieve the desired air pollutant reduction in the relevant downwind states. The court did not vacate the rule but required the EPA to reconsider the invalid emissions budgets. In September 2016, EPA finalized the CSAPR Rule Update for the 2008 ozone NAAQS. Starting in May 2017, the rule will reduce summertime NOx emissions from power plants in 22 states in the eastern U.S.
	●	In addition, in January 2013, the EPA issued final MACT standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters (Boiler MACT), which require significant reductions in the emission of particulate matter, carbon monoxide, hydrogen chloride, dioxins and mercury. Business and environmental groups have filed legal challenges in federal appeals court and have petitioned EPA to reconsider the rule. EPA has granted petitions for reconsideration for certain issues and promulgated a revised final rule in November 2015. The EPA retained a minimum carbon monoxide limit of 130 parts per million and the particulate matter continuous parameter monitoring system requirements, consistent with the January 2013 final rule, but made some minor changes to provisions related to boiler startup and shutdown practices. In July 2016, the D.C. Circuit issued a ruling on the consolidated cases challenging Boiler MACT, vacating key portions of the rule, including emission limits for certain subcategories of solid fuel boilers, and remanding other issues to the EPA for further rulemaking. In December 2016, the court issued a decision denying a full panel rehearing and remanding without vacating the numeric MACT standards set in the Major Boilers Rule for new and existing sources in each of the 18 subcategories. Certiorari petitions are likely. We cannot predict the outcome of any legal challenges that may be filed in the future, however, if Boiler MACT is upheld as previously finalized, EPA estimates the rule will affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. Some owners will make capital expenditures to retrofit boilers and process heaters, while a number of boilers and process heaters will be prematurely retired. The retirements are likely to reduce the demand for coal. The impact of the regulations will depend on the outcome of future legal challenges and EPA actions cannot be determined at this time.

 

 

 

	●	The EPA has adopted new, more stringent national air quality standards (“NAAQS”) for ozone, fine particulate matter, nitrogen dioxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards. For example, in June 2010, the EPA issued a final rule setting forth a more stringent primary NAAQS applicable to sulfur dioxide. The rule also modifies the monitoring increment for the sulfur dioxide standard, establishing a 1-hour standard, and expands the sulfur dioxide monitoring network. Initial non-attainment determinations related to the 2010 sulfur dioxide rule were published in August 2013 with an effective date in October 2013. States with non-attainment areas had to submit their SIP revisions in April 2015, which must meet the modified standard by summer 2017. For all other areas, states will be required to submit “maintenance” SIPs. EPA finalized its PM2.5 NAAQS designations in December 2014. Individual states must now identify the sources of PM2.5 emissions and develop emission reduction plans, which may be state-specific or regional in scope. Nonattainment areas must meet the revised standard no later than 2021. More recently, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. Significant additional emissions control expenditures will likely be required at coal-fired power plants and coke plants to meet the new standards. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, the Partnership’s mining operations and customers could be affected when the standards are implemented by the applicable states. Moreover, the Partnership could face adverse impacts on its business to the extent that these and any other new rules affecting coal-fired power plants result in reduced demand for coal.
	●	In June 2005, the EPA amended its regional haze program to improve visibility in national parks and wilderness areas. Affected states were required to develop SIPs by December 2007 that, among other things, identify facilities that will have to reduce emissions and comply with stricter emission limitations. Implementation of this program may restrict construction of new coal-fired power plants where emissions are projected to reduce visibility in protected areas. In addition, this program may require certain existing coal-fired power plants to install emissions control equipment to reduce haze-causing emissions such as sulfur dioxide, nitrogen oxide, and particulate matter. Consequently, demand for its steam coal could be affected.

 

In addition, over the years, the Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the new source review provisions of the CAA. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the new source review program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for the Partnership’s coal could be affected.

 

Non-government organizations have also petitioned EPA to regulate coal mines as stationary sources under the Clean Air Act. On May 13, 2014, the D.C. Circuit in WildEarth Guardians v. United States Environmental Protection Agency upheld EPA’s denial of one such petition. On July 18, 2014, the D.C. Circuit denied a petition to rehear that case en banc. We cannot guarantee that these groups will not make similar efforts in the future. If such efforts are successful, emissions of these or other materials associated with the Partnership’s mining operations could become subject to further regulation pursuant to existing laws such as the CAA. In that event, the Partnership may be required to install additional emissions control equipment or take other steps to lower emissions associated with its operations, thereby reducing its revenues and adversely affecting its operations.

 

Carbon Dioxide Emissions

 

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, or 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. The Paris climate agreement entered into force in November 2016.

 

 

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 were to be 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 either the Circuit Court or the Supreme Court will rule on the legality of the CPP. Additionally, it is unclear how the CPP will be impacted under President Trump’s new administration. 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 (“CCS”). 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 the Partnership mines and sells, thereby reducing its revenues and materially and adversely affecting its 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 (“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 due to 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 the Partnership’s current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for its 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. In October 2015, the EPA released a rule that established, for the first time, new source performance standards under the federal Clean Air Act for CO₂ emissions from new fossil fuel-fired electric utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. 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.

 

 

Clean Water Act

 

The Federal Clean Water Act (the “CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on the discharge of pollutants, including dredged or fill material, into waters of the U.S. The CWA establishes in-stream water quality and treatment standards for wastewater discharges that are applied to wastewater dischargers through Section 402 National Pollutant Discharge Elimination System (“NPDES”) permits. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of Section 402 NPDES permits. Individual permits or general permits under Section 404 of the CWA are required to discharge dredged or fill materials into waters of the U.S. including wetlands, streams, and other areas meeting the regulatory definition. Expansion of EPA jurisdiction over these areas has the potential to adversely impact the Partnership’s 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. On January 13, 2017, the Supreme Court agreed to review the Sixth Circuit’s finding that it has jurisdiction to hear challenges to the rule. 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. The Partnership’s surface coal mining and preparation plant operations typically require such permits to authorize activities such as the creation of slurry ponds, stream impoundments, and valley fills. The EPA, or a state that has been delegated such authority by the EPA, issues NPDES permits for the discharge of pollutants into navigable waters, while the U.S. Army Corps of Engineers (the “Corps”) issues dredge and fill permits under Section 404 of the CWA. Where Section 402 NPDES permitting authority has been delegated to a state, the EPA retains a limited oversight role. The CWA also gives the EPA an oversight role in the Section 404 permitting program, including drafting substantive rules governing permit issuance by the Corps, providing comments on proposed permits, and, in some cases, exercising the authority to delay or pre-empt Corps issuance of a Section 404 permit. The EPA has recently asserted these authorities more forcefully to question, delay, and prevent issuance of some Section 402 and 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.

 

For instance, even though the Commonwealth of Kentucky and the State of West Virginia have been delegated the authority to issue NPDES permits for coal mines in those states, the EPA is taking a more active role in its review of NPDES permit applications for coal mining operations in Appalachia. The EPA issued final guidance on July 21, 2011 that encouraged EPA Regions 3, 4 and 5 to object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA and with regard to state issued general Section 404 permits, support the previously drafted Enhanced Coordination Process (“ECP”) among the EPA, the Corps, and the U.S. Department of the Interior for issuing Section 404 permits, whereby the EPA undertook a greater level of review of certain Section 404 permits than it had previously undertaken. The D.C. Circuit upheld EPA’s use of the ECP in July 2014. Future application of the ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

 

The EPA also has statutory “veto” power under Section 404(c) to effectively revoke a previously issued Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.” On January 14, 2011, the EPA exercised its Section 404(c) authority to withdraw or restrict the use of a previously issued permit for the Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA’s exercise of this authority was made in the federal District Court in the District of Columbia and on March 23, 2012, the Court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. This decision was appealed and reversed by the D.C. Circuit Court of Appeals in April 2013, finding that EPA has the authority to issue a retroactive veto, but remanding for consideration of whether that decision was arbitrary and capricious. The mining company has also petitioned the U.S. Supreme Court for certiorari to overturn the ruling. The Supreme Court denied certiorari in March 2014. Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to the Partnership’s continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting its revenues.

 

 

The Corps is authorized to issue general “nationwide” permits for specific categories of activities that are similar in nature and that are determined to have minimal adverse environmental effects. We may no longer seek general permits under Nationwide Permit 21 (“NWP 21”) because in February 2012, the Corps reinstated the use of NWP 21, but limited application of NWP 21 authorizations to discharges with impacts not greater than a half-acre of water, including no more than 300 linear feet of streambed, and disallowed the use of NWP 21 for valley fills. This limitation remains in place in the new NWP 21 issued in January of 2017. If the newly issued NWP 21 cannot be used for any of the Partnership’s proposed surface coal mining projects, we will have to obtain individual permits from the Corps subject to the additional EPA measures discussed below with the uncertainties and delays attendant to that process.

 

We currently have a number of Section 404 permit applications pending with the Corps. Not all of these permit applications seek approval for valley fills or other obvious “fills”; some relate to other activities, such as mining through streams and the associated post-mining reconstruction efforts. We sought to prepare all pending permit applications consistent with the requirements of the Section 404 program. The Partnership’s five year plan of mining operations does not rely on the issuance of these pending permit applications. However, the Section 404 permitting requirements are complex, and regulatory scrutiny of these applications, particularly in Appalachia, has increased such that its applications may not be granted or, alternatively, the Corps may require material changes to its proposed operations before it grants permits. While the Partnership will continue to pursue the issuance of these permits in the ordinary course of its operations, to the extent that the permitting process creates significant delay or limits its ability to pursue certain reserves beyond its current five year plan, its revenues may be negatively affected.

 

Total Maximum Daily Load (“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards, and to allocate pollutant loads among the point- and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an anti-degradation review before approving discharge permits. The adoption of new TMDLs and load allocations or any changes to anti-degradation policies for streams near its coal mines could limit its ability to obtain NPDES permits, require more costly water treatment, and adversely affect its coal production.

 

In addition, in May 2014, EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power plants. These requirements could increase its customers’ costs and cause them to reduce their demand for coal, which may materially impact its results or operations.

 

Hazardous Substances and Wastes

 

The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Some products used by coal companies in operations generate waste containing hazardous substances. We are not aware of any material liability associated with the release or disposal of hazardous substances from the Partnership’s past or present mine sites.

 

The federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous wastes. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on the Partnership’s operations.

 

 

In June 2010, EPA released a proposed rule to regulate the disposal of certain coal combustion by-products (“CCB”). The proposed rule sets forth two proposed avenues for the regulation of CCB under RCRA. The first option called for regulation of CCB under Subtitle C as a hazardous waste, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option called for regulation of CCB under Subtitle D as a solid waste, which gives EPA authority to set performance standards for solid waste management facilities and would be enforced primarily through state agencies and citizen suits. In December 2014, EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rule also requires fugitive dust controls and imposes various monitoring, cleanup, and closure requirements. The rule leaves intact the Bevill exemption for beneficial uses of CCB, though it defers a final Bevill regulatory determination with respect to CCB that is disposed of in landfills or surface impoundments. Additionally, in December 2016, Congress passed the Water Infrastructure Improvements for the Nation Act, which provides for the establishment of state and EPA permit programs for the control of coal combustion residuals and authorizes states to incorporate EPA’s final rule for coal combustion residuals or develop other criteria that are at least as protective as the final rule. The costs of complying with these new requirements may result in a material adverse effect on the Partnership’s business, financial condition or results of operations, and could potentially increase its customers’ operating costs, thereby reducing their ability to purchase coal as a result. In addition, contamination caused by the past disposal of CCB, including coal ash, can lead to material liability to its customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

 

Endangered Species Act

 

The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying the Partnership from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to the Partnership’s properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect its ability to mine coal from its properties in accordance with current mining plans.

 

Use of Explosives

 

The Partnership uses explosives in connection with its surface mining activities. The Federal Safe Explosives Act (“SEA”) applies to all users of explosives. Knowing or willful violations of the SEA may result in fines, imprisonment, or both. In addition, violations of SEA may result in revocation of user permits and seizure or forfeiture of explosive materials.

 

The storage of explosives is also subject to regulatory requirements. For example, pursuant to a rule issued by the Department of Homeland Security in 2007, facilities in possession of chemicals of interest (including ammonium nitrate at certain threshold levels) are required to complete a screening review in order to help determine whether there is a high level of security risk, such that a security vulnerability assessment and a site security plan will be required. It is possible that its use of explosives in connection with blasting operations may subject the Partnership to the Department of Homeland Security’s new chemical facility security regulatory program.

 

The costs of compliance with these requirements should not have a material adverse effect on its business, financial condition or results of operations.

 

In December 2014, OSM announced its decision to propose a rule that will address all blast generated fumes and toxic gases. OSM has not yet issued a proposed rule to address these blasts. We are unable to predict the impact, if any, of these actions by the OSM, although the actions potentially could result in additional delays and costs associated with its blasting operations.

 

Other Environmental and Mine Safety Laws

 

The Partnership is also required to comply with numerous other federal, state and local environmental and mine safety laws and regulations in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these requirements is not expected to have a material adverse effect on the Partnership’s business, financial condition or results of operations.

 

 

Employees

 

We and our subsidiaries employed 570 full-time employees as of December 31, 2016. None of the employees are subject to collective bargaining agreements. We believe that the Partnership has good relations with these employees and since its inception it has had no history of work stoppages or union organizing campaigns.

 

Available Information

 

Our internet address is http://www.royalenergy.us, and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and Forms 3, 4 and 5 for our Section 16 filers (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

 

We file or furnish annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Additionally, the SEC’s website, http://www.sec.gov, contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

 

Item 1A. Risk Factors.

 

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below. If any of these risks or uncertainties, as well as other risks and uncertainties that are not currently known to us or that we currently believe are not material, were to occur, our business, financial condition or results of operation could be materially adversely affected and you may lose all or a significant part of your investment.

 

Risks Inherent in Our Business

 

We may not be able to generate adequate cash flow from operations or obtain adequate financing to meet working capital needs, fund our capital expenditures and service our debt.

 

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. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to service our indebtedness, meet our working capital needs and achieve our planned growth and operating results. Our amended and restated credit agreement is currently scheduled to expire on December 31, 2017. 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. Furthermore, there can be no assurance that we will be able to obtain adequate replacement financing on acceptable terms or at all. 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 be required to consider other options, such as selling securities or 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 and we may be unable to complete any of these transactions on terms acceptable to us or at all. Any financing obtained through the sale of our equity will likely result in substantial dilution to the Partnership’s unitholders.

 

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 failure to obtain the financial resources necessary to fund our planned activities and service our debt and other obligations could materially and adversely affect our business, financial condition and results of operations.

 

Our common stock is currently traded on the OTCQB and will trade indefinitely on the OTCQB or one of the other over-the-counter markets, which could adversely affect the market liquidity of our common stock and harm our business.

 

Our common stock trades on the OTCQB under the ticker symbol “ROYE.” We anticipate that the common stock will continue to trade on the OTCQB or one of the other over-the-counter markets for the foreseeable future.

 

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 common stockholders:

 

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

 

Further, since our common stock is not listed on a national securities exchange, we are not subject to the rules of any national securities exchange, including rules requiring us to meet certain corporate governance standards. Without required compliance of these corporate governance standards, investor interest in our common stock may decrease.

 

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

 

The Partnership may not have sufficient cash each quarter to pay the full amount of its minimum quarterly distribution of $4.45 per unit, or $17.80 per unit per year, which will require it to have available cash of approximately $63.2 million per quarter, or $252.8 million per year, based on the number of common and subordinated units outstanding as of December 31, 2016 and our interest as general partner. The amount of cash the Partnership can distribute on its common and subordinated units principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

 

	●	the amount of coal it is 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 it is able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;
	●	the level of its operating costs, including reimbursement of expenses to us as general partner. Its partnership agreement does not set a limit on the amount of expenses for which we or our 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.

 

The Partnership may reduce or eliminate distributions at any time it determines that its 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 its common units were below the minimum level and, beginning with the quarter ended June 30, 2015, it suspended the quarterly distribution on its common units altogether. Pursuant to its partnership agreement, its common units accrue arrearages every quarter when the distribution level is below the minimum quarterly distribution level and its 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, the Partnership has arrearages accumulating on its common units since the distribution level has been below its minimum quarterly level of $4.45 per unit. In addition, it has not paid any distributions on its subordinated units for any quarter after the quarter ended March 31, 2012. It may not have sufficient cash available for distributions on its common or subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact its ability to pay any quarterly distribution on its common units. Moreover, it may not be able to increase distributions on our common units if it is unable to pay the accumulated arrearages on its common units as well as the full minimum quarterly distribution on its subordinated units.

 

Since the Partnership constitutes our only operating entity, the inability of the Partnership to pay distributions on its common units could impair our ability to generate cash to pay liabilities and operating expenses of Royal.

 

A decline in coal prices could adversely affect the Partnership’s results of operations and cash available for distribution to us.

 

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.

 

The Partnership performed a comprehensive review of its current coal mining operation as well as potential future development projects for the year ended December 31, 2016 to ascertain any potential impairment losses. Based on the impairment analysis, the Partnership concluded that none of the coal properties, mine development costs or other coal mining equipment and related facilities were impaired at December 31, 2016. However, for the year ended December 31, 2016, the Partnership recorded $2.6 million of asset impairment losses and related charges associated with the 2015 sale of the Deane mining complex. Of the total $2.6 million non-cash impairment and other non-cash charges incurred, approximately $2.0 million related to impairment of the note receivable that was recorded in 2015 relating to the sale of the Deane mining complex. The additional $0.6 million impairment related to other non-recoverable items associated with the sale of the Deane mining complex. The $2.6 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.

 

The Partnership also performed a comprehensive review of its current coal mining operations as well as potential future development projects to ascertain any potential impairment losses during 2015. 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. 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.

 

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.

 

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 the Partnership’s unitholders.

 

Steam coal accounted for approximately 90% of our coal sales volume for the year ended December 31, 2016. 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 the Partnership’s 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 the Partnership’s 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 had a phased implementation schedule, and the third and final phase of the rule became effective in August 2016. Under the phased approach, operators were required to adopt new measures and procedures for dust sampling, record keeping, and medical surveillance. Additionally, in September 2015, MSHA issued a proposed rule requiring the installation of proximity detection systems coal hauling machines and scoops. The rulemaking record for this proposed rule was closed on December 15, 2016, but on January 9, 2017, MSHA published a notice reopening the record and extending the comment period for this proposed rule for 30 days. 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 the Partnership’s unitholders and could result in harsher sanctions in the event of any violations. Please read “Part 1, Item 1. Business—Regulation and Laws.”

 

 

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 result in increased civil penalty assessments for medium and larger mine operators and contractors by 300% to 1,000%. 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.

 

The Partnership has in the past, and may in the future, be subject to fines, penalties or sanctions resulting from alleged violations of MSHA regulations. Any of our mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any future 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. For example, final guidance released by the CEQ regarding climate change considerations in the NEPA analyses may increase the likelihood of future challenges to the NEPA documents prepared for actions requiring federal approval. 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s 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 the Partnership’s unitholders could be adversely affected.

 

Our results of operations and cash available for distribution to the Partnership’s 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 the Partnership’s 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.

 

The Partnership invests in non-coal natural resource assets, which could result in a material adverse effect on its results of operations and cash available for distribution to its unitholders.

 

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

 

The amount of estimated maintenance capital expenditures we are 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 the Partnership’s unitholders.

 

The Partnership’s partnership agreement requires that we, as it general partner, 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. Its annual estimated maintenance capital expenditures for purposes of calculating operating surplus is based on its estimates of the amounts of expenditures it will be required to make in the future to maintain its long-term operating capacity. Its partnership agreement does not cap the amount of maintenance capital expenditures that its general partner may estimate. The amount of its estimated maintenance capital expenditures may be more than its actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that it 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 us as 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 us as general partner and our affiliates will reduce the amount of available cash from operating surplus that it would otherwise have available for distribution to its 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 the our coal. A reduction in demand for the our coal could adversely affect our results of operations and cash available for distribution to the Partnership’s 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. Please read “Part I, Item 1. Business—Regulation and Laws.”

 

 

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 were to be 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. Additionally, it is unclear how the CPP will be impacted under President Trump’s new administration. 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 due to 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. In October 2015, the EPA released a rule that established, for the first time, new source performance standards under the federal Clean Air Act for CO₂ emissions from new fossil fuel-fired electric utility generating power plants. The EPA has designated partial carbon capture and sequestration as the best system of emission reduction for newly constructed fossil fuel-fired steam generating units at power plants to employ to meet the standard. 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 the Partnership’s unitholders. Please read “Part I, Item 1. Business—Regulation and Laws—Carbon Dioxide Emissions.”

 

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 the Partnership’s 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. In August 2016, the OSMRE issued a Policy Advisory discouraging state regulatory authorities from approving self-bonding arrangements. The Policy Advisory indicated that the OSMRE would begin more closely reviewing instances in which states accept self-bonds for mining operations. In the same month, the OSMRE also announced that it was beginning the rulemaking process to strengthen regulations on self-bonding. 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, 2016, we had $48.9 million in reclamation surety bonds, secured by $26.1 million in letters of credit outstanding under our credit agreement. Based on the Seventh Amendment, our credit agreement provides for a $49.1 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. For more information, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.” 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 the Partnership’s 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 the Partnership’s unitholders could be adversely affected.

 

We sell a material portion of our coal under supply contracts. As of December 31, 2016, we had sales commitments for approximately 100% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2017. 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 84% in 2017, and 16% in 2018. We derived approximately 87.4% of our total coal revenues from coal sales to our ten largest customers for the year ended December 31, 2016, with affiliates of our top three customers accounting for approximately 48.5% 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. For additional information relating to these contracts, please read “Part I, Item 1. Business—Customers—Coal Supply Contracts.”

 

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 the Partnership’s 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.

 

 

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 the Partnership’s ability to make distributions to the Partnership’s unitholders, including Royal. 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. Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Asset Retirement Obligations.”

 

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 the Partnership’s 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, 2016 our current portion of long-term debt that will be funded from cash flows from operating activities during 2017 was approximately $10.0 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. For more information, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.”

 

Risks Inherent in an Investment in Us

 

There Is A Limited Market For Our Common Stock.

 

Our common stock is currently quoted on the OTCQB under the symbol “ROYE.” The trading market for our common stock is limited. We are exploring a possible listing of our common stock on the NASDAQ, which may improve the trading market for our common stock. However, there is no assurance that we will be approved for listing or that the listing will improve the trading market for our common stock. A more active trading market for our common stock may never develop, or if such a market develops, it may not be sustained.

 

Because the market may respond to our business operations and that of our competitors, our stock price will likely be volatile.

 

The OTCQB is a network of security dealers who buy and sell stock. The dealers are connected by a computer network that provides information on current "bids" and "asks", as well as volume information. We anticipate that the market price of our common stock will be subject to wide fluctuations in response to several factors, including: our ability to economically exploit our properties successfully; increased competition from competitors; and our financial condition and results of our operations.

 

We do not intend to pay dividends for the foreseeable future.

 

We have never declared or paid any dividends on our common stock. We intend to retain all of our earnings for the foreseeable future to finance the operation and expansion of our business, and we do not anticipate paying any cash dividends in the future. As a result, you may only receive a return on your investment in our common stock if the market price of our common stock increases. Our board of directors retains the discretion to change this policy.

 

An increase in interest rates may cause the market price of our common shares to decline.

 

Like all equity investments, an investment in our common shares is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally. Reduced demand for our common shares resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common shares to decline.

 

Concentration of ownership among our existing directors, executive officers and principal stockholders may prevent new investors from influencing significant corporate decisions.

 

Our current directors and executive officers and their respective affiliates will, in the aggregate, beneficially own approximately 52.2% of our outstanding common stock and 100% of our outstanding Series A Preferred Stock. Because of the special voting rights of our Series A Preferred Stock (which is entitled to 54% of the total votes on any matter on which shareholders have a right to vote), William L. Tuorto currently controls 75.4% of the votes on any matter requiring a shareholder vote. As a result, these stockholders will be able to exercise a controlling influence over matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions, and will have significant influence over our management and policies for the foreseeable future. Some of these persons or entities may have interests that are different from yours. For example, these stockholders may support proposals and actions with which you may disagree or which are not in your interests. The concentration of ownership could delay or prevent a change in control of our company or otherwise discourage a potential acquirer from attempting to obtain control of our company, which in turn could reduce the price of our common stock. In addition, these stockholders, some of which have representatives sitting on our board of directors, could use their voting control to maintain our existing management and directors in office, delay or prevent changes of control of our company, or support or reject other management and board of director proposals that are subject to stockholder approval, such as amendments to our employee stock plans and approvals of significant financing transactions.

 

 

Additional equity or debt financing may be dilutive to existing stockholders or impose terms that are unfavorable to us or our existing stockholders.

 

We will need to raise substantial capital in order to finance the acquisition of coal properties, provide working capital, and create reserves against the many contingencies that are inherent in the mining industry. If we raise additional funds by issuing equity securities, our stockholders will experience dilution. Debt financing, if available, may involve arrangements that include covenants limiting or restricting our ability to take specific actions, such as incurring additional debt, making capital expenditures or declaring dividends. Any debt financing or additional equity that we raise may contain terms, such as liquidation and other preferences that are not favorable to us or our current stockholders.

 

We depend on key personnel and could be harmed by the loss of their services because of the limited number of qualified people in our industry.

 

Because of our small size, we require the continued service and performance of our management team, all of whom we consider to be key employees. Competition for highly qualified employees in the mining industry is intense. Our success will depend to a significant degree upon our ability to attract, train, and retain highly skilled directors, officers, management, business, financial, legal, marketing, sales, and technical personnel and upon the continued contributions of such people. In addition, we may not be able to retain our current key employees. The loss of the services of one or more of our key personnel and our failure to attract additional highly qualified personnel could impair our ability to expand our operations and provide service to our customers.

 

Under the terms of our Certificate of Incorporation, our Board of Directors is authorized to issue shares of preferred stock with rights and privileges superior to common stockholders without common stockholder approval.

 

Under the terms of our Certificate of Incorporation, our board of directors is authorized to issue shares of preferred stock in one or more classes or series without stockholder approval. The board has discretion to set the terms, preferences, conversion or other rights, voting powers, restrictions, limitations as to dividends or other distributions, qualifications and terms or conditions of redemption for each class or series of preferred stock. Accordingly, we may designate and issue additional shares or series of preferred stock that would rank senior to the shares of common stock as to dividend rights or rights upon our liquidation, winding-up, or dissolution.

 

Provisions in Our Certificate of Incorporation and Bylaws and Delaware law May Inhibit a Takeover of Us, Which Could Limit the Price Investors Might Be Willing to Pay in the Future for our Common Stock and Could Entrench Management.

 

Our certificate of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that stockholders may consider to be in their best interests. Our board has authorized the issuance of 100,000 shares of one class of preferred stock, known as “Series A Preferred Stock.” The Series A Preferred Stock has voting rights entitling it to 54% of the total votes on any matter on which stockholders are entitled to vote. In addition, we cannot authorize or issue any class of capital stock or bonds, debentures, notes or other securities or other obligations ranking senior to or on a parity with the Series A Preferred Stock without the approval of the Series A Preferred Stock voting as a separate class. Mr. Tuorto holds all of the outstanding shares of Series A Preferred Stock. As a result, at any meeting of shareholders Mr. Tuorto has a disproportionate voting power.

 

Mr. Tuorto’s control of our Series A Preferred Stock may prevent our stockholders from replacing a majority of our board of directors at any shareholder meeting, which may entrench management and discourage unsolicited stockholder proposals that may be in the best interests of stockholders. Moreover, our board of directors has the ability to designate the terms of and issue new series of preferred stock without stockholder approval.

 

In addition, as a Delaware corporation, we are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless certain specific requirements are met as set forth in Section 203. Collectively, these provisions may make more difficult the removal of management and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our securities.

 

 

We Will Incur Significant Costs As A Result Of Operating As A Public Company. We May Not Have Sufficient Personnel For Our Financial Reporting Responsibilities, Which May Result In The Untimely Close Of Our Books And Record And Delays In The Preparation Of Financial Statements And Related Disclosures.

 

As a registered public company, we experienced an increase in legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), as well as new rules subsequently implemented by the SEC, has imposed various requirements on public companies, including requiring changes in corporate governance practices. Our management and other personnel need to devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and make some activities more time-consuming and costly.

 

If we are not able to comply with the requirements of Sarbanes-Oxley Act, or if we or our independent registered public accounting firm identifies additional deficiencies in our internal control over financial reporting that are deemed to be material weaknesses, the market price of our stock could decline and we could be subject to sanctions or investigations by the SEC and other regulatory authorities.

 

If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board which would limit the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

 

Companies trading on the OTC Bulletin Board, such as us, must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTC Bulletin Board. More specifically, the Financial Industry Regulatory Authority (“FINRA”) has enacted Rule 6530, which determines eligibility of issuers quoted on the OTC Bulletin Board by requiring an issuer to be current in its filings with the Commission. Pursuant to Rule 6530(e), if we file our reports late with the Commission three times our securities will be removed from the OTC Bulletin Board for failure to timely file. As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

 

We owe substantial indebtedness to the Partnership, repayment of which will likely result in dilution to existing shareholders.

 

As of March 17, 2017, we were indebted to the Partnership in the amount of $4.0 million plus accrued interest. The indebtedness is due December 31, 2018. In order to pay the indebtedness, we will need to raise capital in a debt or equity offering, which could be on unfavorable terms and result in dilution to existing shareholders. Alternatively, we have entered into a letter agreement under which we have the right to convert the indebtedness into that number of shares of our common stock equal to the outstanding balance multiplied by seventy-five percent (75%) of the volume-weighted average closing price of our common stock for the 90 days preceding the date of conversion (“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50. Because the conversion of the indebtedness will be effectuated at a discount to our then current market price, repaying the indebtedness in that manner will be dilutive our existing shareholders.

 

The Series A preferred units of the Partnership are senior in right of distributions and liquidation and upon conversion, would result in the issuance of additional common units in the future, which could result in substantial dilution of our interest in the Partnership.

 

The Series A preferred units of the Partnership are a new class of partnership interests that rank senior to its common units with respect to distribution rights and rights upon liquidation. The Partnership is required to pay annual distributions on the Series A preferred units in an amount equal to the greater of (i) 50% of CAM Mining free cash flow (which is defined in our partnership agreement as (i) the total revenue of the our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for the its Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by the Partnership from its Central Appalachia business segment) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. If the Partnership fails to pay any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and it will not be permitted to pay any distributions on Royal’s partnership interests that rank junior to the Series A Preferred Units, including its common units. The preferred units also rank senior to the common units in right of liquidation, and will be entitled to receive a liquidation preference in any such case.

 

 

The Partnership may convert the Series A preferred units into common units at any time on or after the time at which the amount of aggregate distributions paid in respect of each Series A Preferred Unit exceeds $10.00 per unit. All unconverted Series A preferred units will convert into common units on December 31, 2021. The number of common units issued in any conversion will be based on the volume-weighted average closing price of the common units for 90 days preceding the date of conversion. Accordingly, the lower the trading price of the Partnership’s common units over the 90 day measurement period, the greater the number of common units that will be issued upon conversion of the preferred units, which would result in greater dilution to our interest in the Partnership. Dilution has the following effects on our interest in the Partnership:

 

	●	our proportionate ownership interest in the Partnership will decrease;
	●	the amount of cash available for distribution on each unit may decrease;
	●	the relative voting strength of our ownership interest will be diminished; and
	●	the market price of our common units may decline.

 

In addition, to the extent the preferred units are converted into more than 66 2/3% of the Partnership’s common units, the holders of the preferred units will have the right to remove us as general partner of the Partnership.

 

Holders of the Partnership’s Series A Preferred Units have substantial negative control rights.

 

For as long as the Series A preferred units are outstanding, the Partnership will be restricted from taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining, LLC or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the incurrence, assumption or guaranty indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to entities or assets that are acquired by the Partnership or its affiliates that is in existence at the time of such acquisition; or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of the its Central Appalachia business segment, subject to certain exceptions. These consent rights effectively add a constituency to the Partnership’s fundamental decision-making process, and failure to obtain such consent from the Series A preferred holders could prevent the Partnership from taking actions that its management or board of directors otherwise view as prudent or necessary for its business operations or the execution of its business strategy.

 

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public or private markets, including sales by our officers and directors.

 

As of March 17, 2017, we had 17,184,095 shares of common stock and 51,000 shares of Series A Preferred Stock outstanding. All of the Series A Preferred Shares are convertible into common stock on a one for one basis. Approximately 52.2% of our common stock is owed by our officers and directors, including approximately 46.6% by William Tuorto and entities he controls. There is currently only a limited market for our commons stock. Sales by our large holders of a substantial number of shares of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities.

 

Item 1B. Unresolved Staff Comments

 

None.

 

Item 2. Properties.

 

See “Part I, Item 1. Business” for information about our coal operations and other natural resource assets.

 

 

Coal Reserves and Non-Reserve Coal Deposits

 

We base our coal reserve and non-reserve coal deposit estimates on engineering, economic and geological data assembled and analyzed by our staff. 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, coal reserves recently acquired and estimated costs of production and sales prices. Changes in mining methods may increase or decrease the recovery basis for a coal seam as will plant processing efficiency tests. We maintain reserve and non-reserve coal deposit information in secure computerized databases, as well as in hard copy. The ability to update and/or modify the estimates of our coal reserves and non-reserve coal deposits is restricted to a few individuals and the modifications are documented.

 

Periodically, we retain outside experts to independently verify our coal reserve and our non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller, Inc. as of November 30, 2016, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date. The coal reserve estimates were updated through December 31, 2016 by our internal staff of engineers based upon production data. We intend to continue to periodically retain outside experts to assist management with the verification of our estimates of our coal reserves and non-reserve coal deposits going forward.

 

As of December 31, 2016, we controlled an estimated 256.9 million tons of proven and probable coal reserves and an estimated 196.5 million tons of non-reserve coal deposits. As discussed earlier, Rhino Eastern, a joint venture in which we had a 51% membership interest and for which we served as manager, was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2016.

 

Both our estimated proven and probable coal reserves and our non-reserve coal deposits as of December 31, 2016 decreased when compared to the estimated tons reported as of December 31, 2015 due to the sale of our Elk Horn coal leasing business in August 2016. As part of the recent audits performed by Marshall Miller, Inc., this outside expert performed an independent pro forma economic analysis using industry-accepted guidelines and these were used, in part, to classify tonnage as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions. In the currently depressed coal market environment, some of our coal deposits that were previously classified as proven and probable coal reserves were re-classified as non-reserve coal deposits due to unfavorable projected economic performance.

 

Coal Reserves

 

The following table provides information as of December 31, 2016 on the type, amount and ownership of the coal reserves:

 

		Proven and Probable Coal Reserves (1)
Region		Total (3)				Proven				Probable				Assigned				Unassigned				Owned				Leased				Steam (2)				Metallurgical (2)
		(in million tons)
Central Appalachia
Tug River Complex (KY, WV)			21.4				18.3				3.1				17.2				4.2				7.9				13.5				15.4				6.0
Rob Fork Complex (KY)			7.2				6.1				1.1				7.2				-				1.0				6.2				1.9				5.3
Rhino Eastern Field (WV) (3)			33.9				19.4				14.5				29.1				4.8				-				33.9				-				33.9
Rich Mountain Field (WV)			8.2				2.7				5.5				-				8.2				8.2				-				-				8.2
Total Central Appalachia (5)			70.7				46.5				24.2				53.5				17.2				17.1				53.6				17.3				53.4
Northern Appalachia
Hopedale Complex (OH)			21.3				17.0				4.3				21.3				-				6.6				14.7				21.3				-
Sands Hill Complex (OH)			-				-				-				-				-				-				-				-				-
Leesville Field (OH)			-				-				-				-				-				-				-				-				-
Springdale Field (PA)			-				-				-				-				-				-				-				-				-
Total Northern Appalachia (5)			21.3				17.0				4.3				21.3				-				6.6				14.7				21.3				-
Illinois Basin
Taylorville Field (IL)			111.1				38.9				72.2				-				111.1				-				111.1				111.1				-
Pennyrile Complex (KY)			29.6				16.0				13.6				29.6				-				-				29.6				29.6				-
Total Illinois Basin (5)			140.7				54.9				85.8				29.6				111.1				-				140.7				140.7				-
Western Bituminous																							-
Castle Valley Complex (UT)			17.9				12.2				5.7				17.9				-				-				17.9				17.9				-
McClane Canyon Mine (CO) (4)			6.3				4.1				2.2				6.3				-				0.2				6.1				6.3				-
Total Western Bituminous (5)			24.2				16.3				7.9				24.2				-				0.2				24.0				24.2				-
Total (5)			256.9				134.7				122.2				128.6				128.3				23.9				233.0				203.5				53.4
Percentage of total (5)							52.4	%			47.6	%			50.1	%			49.9	%			9.3	%			90.7	%			79.2	%			20.8	%

 

(1)	Represents recoverable tons.
(2)	For purposes of this table, we have defined metallurgical coal reserves as reserves located in those seams that historically have been of sufficient quality and characteristics to be able to be used in the steel making process. All other coal reserves are defined as steam coal. However, some of the reserves in the metallurgical category can also be used as steam coal.
(3)	The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2016.
(4)	The McClane Canyon mine was permanently idled as of December 31, 2013.
(5)	Percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

 

 

The majority of our leases have an initial term denominated in years but also provide for the term of the lease to continue until exhaustion of the “mineable and merchantable” coal in the lease area so long as the terms of the lease are complied with. Some of our leases have terms denominated in years rather than mine-to-exhaustion provisions, but in all such cases, we believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine those reserves.

 

The following table provides information on particular characteristics of our coal reserves as of December 31, 2016:

 

		As Received Basis (1)																Proven and Probable Coal Reserves (2)
														S02/mm								Sulfur Content
Region		% Ash				% Sulfur				Btu/lb.				Btu				Total				<1%				1-1.5%				>1.5%				Unknown
																		(in million tons)
Central Appalachia
Tug River Complex (KY, WV)			9.58	%			1.25	%			13,084				1.91				21.4				9.3				9.1				2.0				1.0
Rob Fork Complex (KY)			5.47	%			0.96	%			13,591				1.42				7.2				6.5				0.5				0.2				-
Rhino Eastern Field (WV) (3)			4.17	%			0.67	%			14,035				0.96				33.9				28.8				4.9				-				0.2
Rich Mountain Field (WV)			7.28	%			0.60	%			13,235				0.91				8.2				8.2				-				-				-
Total Central Appalachia			6.26	%			0.86	%			13,615				1.27				70.7				52.8				14.5				2.2				1.2
Northern Appalachia
Hopedale Complex (OH)			7.22	%			2.45	%			14,910				3.28				21.3				-				-				21.3				-
Sands Hill Complex (OH)			-				-				-				-				-				-				-				-				-
Total Northern Appalachia			7.22	%			2.45	%			14,910				3.29				21.3				-				-				21.3				-
Illinois Basin
Taylorville Field (IL)			7.75	%			3.53	%			11,057				6.38				111.1				-				-				111.1				-
Pennyrile Complex (KY)			7.79	%			2.53	%			11,475				4.42				29.6				-				-				29.6				-
Total Illinois Basin			7.76	%			3.32	%			11,145				5.96				140.7				-				-				140.7				-
Western Bituminous
Castle Valley Complex (UT)			10.63	%			0.75	%			12,058				1.24				17.9				17.9				-				-				-
McClane Canyon Mine (CO) (4)			11.19	%			0.57	%			11,241				1.01				6.3				6.3				-				-				-
Total Western Bituminous			10.77	%			0.70	%			11,847				1.19				24.2				24.2				-				-				-
Total (5)			7.59	%			2.33	%			12,196				3.82				256.9				77.0				14.5				164.2				1.2
Percentage of total (5)																							30.0	%			5.6	%			63.9	%			0.5	%

 

(1)	As received basis represents average dry basis analytical test results which are normalized to a moisture content deemed to be representative of the saleable coal product.
(2)	Represents recoverable tons.
(3)	The Rhino Eastern joint venture was dissolved in January 2015. As part of this dissolution, we received approximately 34 million tons of premium metallurgical coal reserves, which we have included in the proven and probable reserves listed above as of December 31, 2016.
(4)	The McClane Canyon mine was permanently idled as of December 31, 2013.
(5)	Totals and percentages of totals are calculated based on actual amounts and not the rounded amounts presented in this table.

 

 

Non-Reserve Coal Deposits

 

The following table provides information on our non-reserve coal deposits as of December 31, 2016:

 

		Non-Reserve Coal Deposits
						Total Tons
Region		Total Tons				Owned				Leased
		(in million tons)
Central Appalachia			46.9				15.6				31.3
Northern Appalachia			85.6				70.2				15.4
Illinois Basin			34.0				-				34.0
Western Bituminous			30.0				-				30.0
Total			196.5				85.8				110.7
Percentage of total							43.66	%			56.34	%

 

Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to lands and non-reserve coal deposits of the lessors or grantors and the boundaries of our leased priorities are not completely verified until we prepare to mine the coal.

 

Blaze Minerals, LLC

 

Our subsidiary, Blaze Minerals, LLC, owns 40,976 net acres of coal and coalbed methane mineral rights in 22 counties in West Virginia.

 

Office Facilities

 

Our executive headquarters occupy leased office space at 56 Broad Street, Suite 2, Charleston, SC 29401 which provides for monthly lease of $1,400 per month.

 

The Partnership leases lease office space at 424 Lewis Hargett Circle, Lexington, Kentucky for its executives and administrative support staff. The Partnership executed an amendment to this lease in 2013 to extend the lease term for five additional years to August 2018.

 

Item 3. Legal Proceedings.

 

We may, from time to time, be involved in various legal proceedings and claims arising out of our operations in the normal course of business. While many of these matters involve inherent uncertainty, we do not believe that we are a party to any legal proceedings or claims that will have a material adverse impact on our business, financial condition or results of operations.

 

Item 4. Mine Safety Disclosures.

 

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the year ended December 31, 2016 is included in Exhibit 95.1 to this report.

 

 

PART II

 

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

 

Our common stock, par value $0.00001 per share, is traded in the over-the-counter market and is quoted on the OTCQB under the symbol “ROYE.OB.” Until we began trading on September 5, 2007, there was no public market for our common stock. Previously we traded under the symbol WRLM.OB.

 

The following table sets forth the quarterly high and low daily close for our common stock as reported by the OTCQB for the two years ended December 31, 2016 and 2015. The bids reflect inter dealer prices without adjustments for retail mark-ups, mark-downs or commissions and may not represent actual transactions. There is a very limited market for the Company’s common stock.

 

		Price Range
		High				Low
Year ended December 31, 2016
Fourth Quarter		$	8.25			$	5.40
Third Quarter		$	11.25			$	7.02
Second Quarter		$	13.75			$	2.01
First Quarter		$	13.80			$	5.00
Year ended December 31, 2015
Fourth Quarter		$	16.99			$	5.00
Third Quarter		$	15.95			$	4.51
Second Quarter		$	15.00			$	2.01
First Quarter		$	28.00			$	0.10

 

The OTCQB is a quotation service sponsored by the Financial Industry Regulatory Authority (FINRA) that displays real-time quotes and volume information in over-the-counter (“OTC”) equity securities. The OTCQB does not impose listing standards or requirements, does not provide automatic trade executions and does not maintain relationships with quoted issuers. A company traded on the OTCQB may face loss of market makers and lack of readily available bid and ask prices for its stock and may experience a greater spread between the bid and ask price of its stock and a general loss of liquidity with its stock. In addition, certain investors have policies against purchasing or holding OTC securities. Both trading volume and the market value of our securities have been, and will continue to be, materially affected by the trading on the OTCQB.

 

Recent Sales of Unregistered Securities

 

During three months ended December 31, 2016, we issued an aggregate of 411,116 shares of common stock in unregistered transactions as follows:

 

On November 12, 2016, we issued 447,857 shares of common stock in conversion of $2,150,000 principal amount of convertible notes and $111,137 of accrued interest thereon. The shares were issued at $5.50 per share, which was the stated conversion price of the convertible notes. The shares were issued pursuant to the exemption from registration provided by Section 4(a)(2) of the Securities Act of 1933.

 

Holders

 

As of March 20, 2017, we had 17,184,095 shares of common stock issued and outstanding, and 51,000 shares of Series A Preferred Stock issued and outstanding. As of March 20, 2017, there are approximately 82 shareholders of record of our common stock, which does not include shareholders holding their shares in street name.

 

Dividend Policy

 

Our Board of Directors has never declared or paid a cash dividend. At this time, our Board of Directors does not anticipate paying dividends in the future. We are under no legal or contractual obligation to declare or to pay dividends, and the timing and amount of any future cash dividends and distributions is at the discretion of our Board of Directors and will depend, among other things, on our future after-tax earnings, operations, capital requirements, borrowing capacity, financial condition and general business conditions. We plans to retain any earnings for use in the operation of our business and to fund future growth.

 

 

Issuer Purchases of Equity Securities

 

During the quarter ended December 31, 2016, we did not purchase any shares of its common stock.

 

Item 6. Selected Financial Data

 

The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidated financial statements. On March 6, 2015, William Tuorto acquired control of a majority of our voting shares, as well as control of our board of directors. Shortly thereafter, we sold subsidiaries that contained our then current operations to prior management, and entered into the business of natural resources assets, including coal, oil, gas and renewable energy. On March 17, 2016, we acquired control of Rhino Resource Partners, LP. a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. The selected historical consolidated financial data presented as of August 31, 2013 and 2012 and for the years ended August 31, 2013 and 2012 are derived from our audited historical consolidated financial statements that are not included in this report. The selected historical consolidated financial data presented as of August 31, 2015 and 2014, and as of December 31, 2016 and for the years ended August 31, 2015 and 2014, and the year ended December 31, 2016 are derived from our audited historical consolidated financial statements that are included elsewhere in this report.

 

The following selected consolidated financial data should be read in conjunction with “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”

 

										Year ended August 31,
		Year Ended December 31, 2016				Four Months Ended December 31, 2015				2015				2014				2013				2012
Revenues		$	138,569			$	-			$	281			$	-			$	-			$	17,000
(Loss) from continuing operations		$	(14,197	)		$	(1,204	)		$	(502	)		$	(817	)		$	(389	)		$	(126	)
(Loss) from continuing operations per share		$	(0.97	)		$	(0.08	)		$	(0.05	)		$	(0.16	)		$	(2.17	)		$	(0.73	)
Weighted average shares outstanding			14,527,495				14,794,212				10,335,741				5,060,675				179,527				172,517
Total assets		$	166,242			$	12,350			$	12,350			$	33			$	43			$	31
Long-term obligations		$	65,576			$	-			$	-			$	-			$	-			$	-
Cash dividends declared per common share		$	-			$	-			$	-			$	-			$	-			$	-

 

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

This Annual Report on Form 10-K includes forward looking statements (“Forward Looking Statements”). All statements other than statements of historical fact included in this report are Forward Looking Statements. In the normal course of its business, Royal Energy Resources, Inc. and it’s subsidiaries (the “Company,”) in an effort to help keep its shareholders and the public informed about the Company’s operations, may from time-to-time issue certain statements, either in writing or orally, that contains or may contain Forward-Looking Statements. Although the Company believes that the expectations reflected in such Forward Looking Statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Generally, these statements relate to business plans or strategies, projected or anticipated benefits or other consequences of such plans or strategies, past and possible future, of acquisitions and projected or anticipated benefits from acquisitions made by or to be made by the Company, or projections involving anticipated revenues, earnings, levels of capital expenditures or other aspects of operating results. All phases of the Company’s operations are subject to a number of uncertainties, risks and other influences, many of which are outside the control of the Company and any one of which, or a combination of which, could materially affect the results of the Company’s proposed operations and whether Forward Looking Statements made by the Company ultimately prove to be accurate. Such important factors (“Important Factors”) and other factors could cause actual results to differ materially from the Company’s expectations are disclosed in this report. All prior and subsequent written and oral Forward Looking Statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Important Factors described below that could cause actual results to differ materially from the Company’s expectations as set forth in any Forward Looking Statement made by or on behalf of the Company.

 

Overview

 

The Company previously pursued gold, silver, copper and rare earth metals mining concessions in Romania and mining leases in the United States. Commencing in January 2015, the Company began a series of transactions under which the Company would dispose of all of its existing assets, undergo a change in ownership control and management, and repurpose itself as a North American energy recovery company, with plans to purchase a group of synergistic, long-lived energy assets by taking advantage of favorable valuations for mergers and acquisitions in the current energy markets. In April 2015, the Company completed its first acquisition in furtherance of its change in principle operations, consisting of 40,976 net acres of coal and coalbed methane, located across 22 counties in West Virginia. See below regarding acquisition of majority control of Rhino Resource Partners, LP. See Note 3 to the consolidated financial statements for completed acquisitions.

 

Current management of the Company acquired control of the Company in March 2015, with the goal of using the Company as a vehicle to acquire undervalued natural resource assets. The Company has raised approximately $8.45 million through the sale of shares of common stock in private placements, $6.35 million through issuance of notes payable and is currently evaluating a number of possible acquisitions of operating coal mines and non-operating coal assets. There are currently many coal assets for sale at attractive prices due to distressed conditions in the coal industry. The distressed conditions are mainly due to low natural gas prices causing coal generated power to be displaced by gas generated power. Excessive environmental regulation and low international prices for metallurgical coal also increased the stress on the industry. The resulting drop in demand from coal buyers has caused the price of coal to decline considerably, and caused bankruptcy filings by many of the major coal operators. Despite the current distress in the industry, industry experts still predict that coal will supply a significant percentage of the nation’s energy needs for the foreseeable future, and thus overall demand for coal will remain significant. Also, demand for metallurgical coal has improved and metallurgical coal prices seem likely to stay in a range that will allow lower cost North American coal mines to produce profitably. Management believes there are a number of attractive acquisition candidates in the coal industry which can be operated profitably at current prices and under the current regulatory environment.

 

Royal Energy Resources, Inc. Purchase of Majority Control of Rhino Resource Partners, LP

 

On January 21, 2016, a definitive agreement was completed between Royal and Wexford Capital LP and certain of its affiliates (collectively, “Wexford”) whereby Royal acquired 676,912 of Rhino’s issued and outstanding common units from Wexford. The definitive agreement also included a commitment by Royal to acquire within 60 days from the date of the definitive agreement, or March 21, 2016, all of the issued and outstanding membership interests of Rhino GP LLC (Rhino GP”), Rhino’s general partner, as well as 945,526 of Rhino’s issued and outstanding subordinated units from Wexford.

 

 

On March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of Rhino GP as well as the 945,526 issued and outstanding subordinated units from Wexford. Royal obtained control of, and a majority limited partner interest, in Rhino with the completion of this transaction. Immediately subsequent to the consummation of the transaction, the following members of the board of directors of the Partnership’s general partner tendered their resignations effective immediately: Mark Zand, Philip Braunstein, Ken Rubin, Arthur Amron, Douglas Lambert and Mark Plaumann. As the owner of the Partnership’s general partner, Royal has the right to appoint the members of the board of directors of the Partnership’s general partner and so appointed the following individuals as new directors to fill the vacancies resulting from the resignations: William Tuorto, Ronald Phillips, Michael Thompson, Ian Ganzer, Douglas Holsted, Brian Hughs and David Hanig.

 

On March 21, 2016, Rhino and Royal entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant to which Rhino issued 6,000,000 of its common units to Royal in a private placement at $1.50 per common unit for an aggregate purchase price of $9.0 million. Royal paid Rhino $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. On May 13, 2016, the Company paid the $3,000,000 installment which was due on July 31, 2016, and on September 30, 2016 paid the $2,000,000 installment which was due on that date.

 

In the event the disinterested members of the board of directors of Rhino’s 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, Rhino has the option to rescind Royal’s purchase of 1,333,334 common units and the applicable installment will not be payable (each, a “Rescission Right”). If Rhino fails to exercise a Rescission Right, in each case, Rhino has the option to repurchase 1,333,334 of its common units at $3.00 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 Rhino has entered into an agreement to extend the Credit Facility, 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 cancelled divided by $1.50.

 

Overview after Rhino Acquisition

 

We are a diversified energy company formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition, we have expanded our business to include infrastructure support services, as well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in joint ventures that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.

 

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin, West Virginia and the Western Bituminous region. As of December 31, 2016, we controlled an estimated 256.9 million tons of proven and probable coal reserves, consisting of an estimated 203.5 million tons of steam coal and an estimated 53.4 million tons of metallurgical coal. In addition, as of December 31, 2016, we controlled an estimated 196.5 million tons of non-reserve coal deposits. Both our estimated proven and probable coal reserves and non-reserve coal deposits as of December 31, 2016 decreased when compared to the estimated tons and deposits reported as of December 31, 2015 due to the sale of our Elk Horn coal leasing business in August 2016. As part of the recent audits of themajority of our coal reserves and deposits performed by Marshall Miller, Inc., this outside expert performed an independent pro forma economic analysis using industry-accepted guidelines and this was used, in part, to classify tonnage as either proven and probable coal reserves or non-reserve coal deposits, based on current market conditions.

 

We operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate will vary from time to time depending on a number of factors, including the existing demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor. In the third quarter of 2015, we temporarily idled a majority of our Central Appalachia operations due to ongoing weak coal market conditions for met and steam coal produced from this region. We resumed mining operations at all of our Central Appalachia operations in 2016 to fulfill customer contracts that we secured for 2016 and 2017.

 

 

Our principal business strategy is to safely, efficiently and profitably produce and sell both steam and metallurgical coal from our diverse asset base. In addition, we intend to continue to expand and potentially diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. We believe that such assets will allow us to grow our cash and enhance stability of our cash flow.

 

For the year ended December 31, 2016, we generated revenues of approximately $137.6 million and a net loss from continuing operations of approximately $14.4 million. For the year ended December 31, 2016, we produced approximately 2.6 million tons of coal and sold approximately 2.6 million tons of coal, approximately 90% of which were pursuant to long-term supply contracts.

 

Factors That Impact Our Business

 

Our results of operations in the near term could be impacted by a number of factors, including (1) our ability to fund our ongoing operations and necessary capital expenditures, (2) the availability of transportation for coal shipments, (3) poor mining conditions resulting from geological conditions or the effects of prior mining, (4) equipment problems at mining locations, (5) adverse weather conditions and natural disasters or (6) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives.

 

On a long-term basis, our results of operations could be impacted by, among other factors, (1) our ability to fund our ongoing operations and necessary capital expenditures, (2) changes in governmental regulation, (3) the availability and prices of competing electricity-generation fuels, (4) the world-wide demand for steel, which utilizes metallurgical coal and can affect the demand and prices of metallurgical coal that we produce, (5) our ability to secure or acquire high-quality coal reserves and (6) our ability to find buyers for coal under favorable supply contracts.

 

We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of December 31, 2016, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

 

Year		Tons (in thousands)				Number of customers
2017			3,669				14
2018			701				5

 

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

 

Results of Operations

 

Segment Information

 

As of December 31, 2016, we have four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois Basin. Additionally, we have an Other category that includes our ancillary businesses and our remaining oil and natural gas activities. Our Central Appalachia segment consists of two mining complexes: Tug River and Rob Fork, which, as of December 31, 2016, together included one underground mines, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. We idled a majority of our Central Appalachia operations beginning in the third quarter of 2015 to reduce excess coal inventory. We resumed mining operations at all of our Central Appalachia operations during the three months ended September 30, 2016. The Central Appalachia segment also includes the GS Energy mine, which is currently inactive, the Blaze Mining royalty and Blaze Minerals. Our 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, 2016. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of December 31, 2016. Our Rhino Western segment includes our underground mine in the Western Bituminous region at our Castle Valley mining complex in Utah. Our Illinois Basin segment includes one underground mine, preparation plant and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our Taylorville field reserves located in central Illinois. The Pennyrile mining complex began production and sales in mid-2014. Our Other category is comprised of our ancillary businesses and our remaining oil and natural gas activities.

 

 

 

Evaluating Our Results of Operations

 

Our management uses a variety of financial measurements to analyze our performance, including (1) Adjusted EBITDA, (2) coal revenues per ton and (3) cost of operations per ton.

 

Adjusted EBITDA. The discussion of our results of operations below includes references to, and analysis of, our segments’ Adjusted EBITDA results. Adjusted EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization, while also excluding certain non-cash and/or non-recurring items. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate Adjusted EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA to net income by segment for each of the periods indicated.

 

Coal Revenues Per Ton. Coal revenues per ton represents coal revenues divided by tons of coal sold. Coal revenues per ton is a key indicator of our effectiveness in obtaining favorable prices for our product.

 

Cost of Operations Per Ton. Cost of operations per ton sold represents the cost of operations (exclusive of DD&A) divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency of operations.

 

Summary

 

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data on a historical basis for the year ended December 31, 2016, the four months ended December 31, 2015 and the years ended August 31, 2015 and 2014 and on a pro forma basis for the years ended December 31, 2016 and 2015 as if the acquisition of Rhino by Royal had occurred at the beginning of each period.

 

		Historical																Pro Forma
						Four months
		Year ended				Ended				Year ended								Year ended
		December 31,				December 31,				August 31,								December 31,
		2016				2015				2015				2014				2016				2015
		(millions)
Statement of Operations Data:
Total revenues		$	138.6			$	—			$	0.3			$	—			$	170.8			$	195.3
Costs and expenses:
Cost of operations			111.6				—				0.3				—				135.4				173.6
Freight and handling costs			1.3				—				—				—				1.7				2.7
Depreciation, depletion and amortization			4.5				0.2				0.1				—				6.1				8.2
Selling, general and administrative			14.1				0.8				0.4				0.8				16.3				16.0
Asset impairment			16.7				—				—				—				16.7				—
Total costs and expenses			148.2				1.0				0.8				0.8				176.2				200.5
(Loss) from operations			(9.7	)			(1.0	)			(0.5	)			(0.8	)			(5.6	)			(5.2	)
Other income (expense):
Interest expense			(4.3	)			—				—				—				(5.5	)			(5.0	)
Other			—				(0.2	)			—				—				—				(0.2	)
Equity in (loss) income of unconsolidated affiliates			(0.2	)			—				—				—				(0.2	)			0.3
Total other income (expense)			4.5				(0.2	)			—				—				(5.7	)			(4.9	)
Net (loss) before minority interest			(14.2	)			(1.2	)			(0.5	)			(0.8	)			(11.3	)			(10.1	)
Other Financial Data
Adjusted EBITDA		$	11.3			$	(1.0	)		$	(0.4	)		$	(0.8	)		$	17.1			$	3.1

 

*Totals may not foot due to rounding

 

We believe the weak demand in the met coal markets was primarily driven by a decrease in worldwide steel production due to ongoing global economic weakness, particularly in China. While coal prices and demand have increased recently, particularly met coal prices and demand, we do not anticipate the recent price increase will benefit our financial results until 2017.

 

 

Historical year ended December 31, 2016 Compared to Historical years ended August 31, 2015 and 2014

 

Our revenues increased to $138.6 million in the year ended December 31, 2016 as compared to $0.3 million in the year ended August 31, 2015 and none in the year ended August 31, 2014. Operations in the 2015 period included the initial operation in West Virginia of Blue Grove which operated the GS Energy mine commencing in June 2015. These operations were subsequently suspended at the end of July when the coal purchaser filed Chapter 11 Bankruptcy. The Company collected its unpaid receivables during the last quarter of 2016. On March 17, 2016, Royal acquired the majority of Rhino and began consolidating its operations. We sold 4 thousand tons of coal in the 2015 period and approximately 2.6 million tons in the 2016 period. During the 2014 period, the Company was seeking gold, silver, copper and rare earth metals mining concessions in Romania and mining leases in the United States and had no operations.

 

Costs and expenses also increased substantially in 2016 from the earlier periods primarily due to the acquisition of Rhino and the $16.7 million asset impairment recorded on the Blaze Mining royalty.

 

Interest expense in the 2016 period is primarily from Rhino.

 

The above factors combine to result in a loss of $14.2 million, $1.2 million, $0.5 million and $0.8 million for the year ended December 31, 2016, the four months ended December 31, 2015 and the years ended August 31, 2015 and 2014, respectively.

 

Pro forma year ended December 31, 2016 Compared to pro forma year ended December 31, 2015

 

The following discussion will involve the pro forma operations as if Rhino had been acquired by Royal at the beginning of each year. The amounts included for Rhino are based on provisional amounts which could change once the final appraisal of all assets and liabilities of Rhino is completed.

 

We made adjustments to reduce the depreciation, depletion and amortization to the amounts that would have been recorded due to the reduced asset basis from the acquisition of Rhino by Royal. In addition, it was assumed that the $31.6 million in asset impairments recorded in 2015 would have been excluded from the basis of the assets acquired and this amount was also omitted from the 2015 amounts. The gain on sale of assets was also omitted from the 2015 amounts. The operations of Royal prior to the acquisition have been added into the proforma amounts.

 

Summary. For the year ended December 31, 2016, our total revenues decreased to $170.8 million from $195.3 million for the year ended December 31, 2015. We sold 3.3 million tons of coal for the year ended December 31, 2016, which is 0.2 million tons less than, or a 4.59% decrease, from the 3.5 million tons of coal sold for the year ended December 31, 2015. The decrease in revenue and tons sold was primarily the result of continued weak demand and low prices in the met and steam coal markets, particularly in Central Appalachia, partially offset by increased sales from our Pennyrile operation in the Illinois Basin.

 

Net loss declined for the year ended December 31, 2016 compared to the year ended December 31, 2015. We generated a net loss of approximately $12.5 million for the year ended December 31, 2016 compared to a net loss of approximately $10.1 million for the year ended December 31, 2015. Adjusted EBITDA for these periods was $17.2 million and $3.1 million for the years ended December 31, 2016 and 2015. For the year ended December 31, 2016, our total net loss was negatively impacted by approximately $16.7 million of asset impairment from our Blaze Mining royalty impairment in the Central Appalachia segment. Adjusted EBITDA increased to $17.2 million for the year ended December 31, 2016 as compared to $3.1 million for the year ended December 31, 2015. Adjusted EBITDA increased period to period primarily due to the lower net loss generated from operations year-to-year.

 

 

 

Tons Sold. The following table presents tons of coal sold by reportable segment for the years ended December 31, 2016 and 2015:

 

										Increase
		Year Ended December 31,								(Decrease)
Segment		2016				2015				Tons				%*
		(in thousands, except %)
Central Appalachia			633.7				781.6				(147.9	)			-18.9	%
Northern Appalachia			535.6				907.1				(371.5	)			-41.0	%
Rhino Western			898.9				950.0				(51.1	)			-5.4	%
Illinois Basin			1,239.2				832.0				407.2				48.9	%
Total*			3,307.4				3,470.7				(163.3	)			-4.7	%

 

*

Calculated percentages and the rounded totals presented are based upon on actual whole ton amounts and not the rounded amounts presented in this table.

We sold approximately 3.3 million tons of coal in the year ended December 31, 2016 as compared to approximately 3.5 million tons sold for the year ended December 31, 2015. The decrease in total tons sold year-to-year was primarily due to fewer steam coal tons sold from our Northern Appalachia and Central Appalachia segments due to weak coal market conditions in these regions, partially offset by tons sold from our Pennyrile mine in our Illinois Basin segment. Tons of coal sold in our Central Appalachia segment decreased by approximately 0.1 million, or 18.9%, to approximately 0.6 million tons for the year ended December 31, 2016 from approximately 0.8 million tons for the year ended December 31, 2015. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to ongoing weak market demand for steam coal from this region. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.4 million, or 41.0%, to approximately 0.5 million tons for the year ended December 31, 2016 from approximately 0.9 million tons for the year ended December 31, 2015, as we experienced a decrease in tons sold from our Hopedale complex due to weak demand for coal from this region. Coal sales from our Rhino Western segment decreased by approximately 0.1 million, or 5.4%, to approximately 0.9 million tons for the year ended December 31, 2016 due to decreased customer demand from our Castle Valley operation. For our Illinois Basin segment, tons of coal sold increased by approximately 0.4 million, or 48.9%, to approximately 1.2 million tons for the year ended December 31, 2016 from approximately 0.8 million tons for the year ended December 31, 2015, as we increased production and sales year-to-year from our Pennyrile mine in western Kentucky to meet our contracted sales commitments.

 

 

 

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the years ended December 31, 2016 and 2015:

 

										Increase
		Year Ended December 31,								(Decrease)
Segment		2016				2015				$				%*
(in millions except per ton data and %)
Central Appalachia
Coal revenues		$	37.6			$	45.5			$	(7.9	)			-17.4	%
Freight and handling revenues			-				-				-				n/a
Other revenues			0.2				11.0				(10.8	)			-98.2	%
Total revenues		$	37.8			$	56.5			$	(18.7	)			-33.1	%
Coal revenues per ton*		$	59.26			$	58.08			$	1.18				2.0	%
Northern Appalachia
Coal revenues		$	29.6			$	52.4			$	(22.8	)			-43.5	%
Freight and handling revenues			1.9				2.8				(0.9	)			-32.1	%
Other revenues			7.3				8.1				(0.8	)			-9.9	%
Total revenues		$	38.8			$	63.3			$	(24.5	)			-38.7	%
Coal revenues per ton*		$	55.27			$	57.72			$	(2.45	)			-4.2	%
Rhino Western
Coal revenues		$	34.7			$	35.3			$	(0.6	)			-1.7	%
Freight and handling revenues			-				-				-				n/a
Other revenues			-				-				-				n/a
Total revenues		$	34.7			$	35.3			$	(0.6	)			-1.7	%
Coal revenues per ton*		$	38.56			$	37.16			$	1.40				3.8	%
Illinois Basin
Coal revenues		$	59.0			$	38.2			$	20.8				54.5	%
Freight and handling revenues			-				-				-				n/a
Other revenues			0.1				0.4				(0.3	)			-75.0	%
Total revenues		$	59.1			$	38.6			$	20.5				53.1	%
Coal revenues per ton*		$	47.63			$	45.98			$	1.65				3.6	%
Other**
Coal revenues		$	-			$	-			$	-				n/a
Freight and handling revenues			-				-				-				n/a
Other revenues			0.4				1.6				(1.2	)			-75.0	%
Total revenues		$	0.4			$	1.6			$	(1.2	)			-75.0	%
Coal revenues per ton*			n/a				n/a				n/a				n/a
Total
Coal revenues		$	160.9			$	171.4			$	(10.5	)			-6.1	%
Freight and handling revenues			1.9				2.8				(0.9	)			-32.1	%
Other revenues			8.0				21.1				(13.1	)			-62.1	%
Total revenues		$	170.8			$	195.3			$	(24.5	)			-12.5	%
Coal revenues per ton*		$	48.63			$	49.35			$	(0.72	)			-1.5	%

 

 

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
**	The Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses also do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Other category.

 

 

Our coal revenues for the year ended December 31, 2016 decreased by $10.5 million, or 6.1%, to $160.9 million from $171.4 million for the year ended December 31, 2015. The decrease in coal revenues was primarily due to fewer steam coal tons sold in Northern Appalachia and Central Appalachia, partially offset by increased sales from our Pennyrile mine in the Illinois Basin. Coal revenues per ton were $48.63 for the year ended December 31, 2016, a decrease of $0.72, or 1.5%, from $49.35 per ton for the year ended December 31, 2015. This decrease in coal revenues per ton was primarily the result of a larger mix of lower priced tons sold from Pennyrile.

 

For our Central Appalachia segment, coal revenues decreased by $7.9 million, or 17.4%, to $37.6 million for the year ended December 31, 2016 from $45.5 million for the year ended December 31, 2015 primarily due to fewer steam coal tons sold, which reflects the weak coal markets conditions for coal from this region. Coal revenues per ton for our Central Appalachia segment increased by $1.18, or 2.0%, to $59.26 per ton for the year ended December 31, 2016 as compared to $58.08 for the year ended December 31, 2015, primarily due to a higher mix of higher priced met coal tons sold compared to the prior year. Other revenues decreased for our Central Appalachia segment primarily due to the sale of our Elk Horn coal leasing business in August 2016, which required us to reclassify Elk Horn’s revenue to discontinued operations.

 

For our Northern Appalachia segment, coal revenues were $29.6 million for the year ended December 31, 2016, a decrease of $22.8 million, or 43.5%, from $52.4 million for the year ended December 31, 2015. This decrease was primarily due to fewer tons sold from our Hopedale complex in Northern Appalachia due to weak demand for coal from the Northern Appalachia region. Coal revenues per ton for our Northern Appalachia segment decreased by $2.45, or 4.2%, to $55.27 per ton for the year ended December 31, 2016 as compared to $57.72 per ton for the year ended December 31, 2015. This decrease was primarily due to the larger mix of lower priced tons being sold from our Sands Hill complex compared to higher priced tons sold from our Hopedale complex.

 

For our Rhino Western segment, coal revenues decreased by $0.6 million, or 1.8%, to $34.7 million for the year ended December 31, 2016 from $35.3 million for the year ended December 31, 2015. Coal revenues per ton for our Rhino Western segment were $38.56 for the year ended December 31, 2016, an increase of $1.40, or 3.8%, from $37.16 for the year ended December 31, 2015. The decrease in coal revenues was primarily due to a decrease in tons sold due to decreased customer demand at our Castle Valley operation. The increase in coal revenues per ton was primarily due to an increase in the contracted sales prices for steam coal sales from our Castle Valley mine for the year ended December 31, 2016 compared to the same period in 2015.

 

Coal revenues of approximately $59.0 million for the Illinois Basin increased approximately $20.8 million from $38.2 million for the year ended December 31, 2015. Coal revenues per ton for our Illinois Basin segment were $47.63 for the year ended December 31, 2016, an increase of $1.65, or 3.6%, from $45.98 for the year ended December 31, 2015. The increase in coal revenues per ton was due to higher contracted sales prices for the year ended December 31, 2016 compared to the prior year.

 

Other revenues for our Other category decreased by $1.2 million for the year ended December 31, 2016 from the year ended December 31, 2015. This decrease in revenue was primarily due to the decreased business activity in our ancillary businesses and oil and natural gas investments.

 

 

Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal and steam coal, is presented below. Our Northern Appalachia, Rhino Western, West Virginia and Illinois Basin segments currently only produce and sell steam coal.

 

										Increase
		Year Ended December 31,								(Decrease)
		2016				2015				%*
			(in thousands, except %)
Met coal tons sold			322.8				191.2				68.8	%
Steam coal tons sold			310.9				590.4				-47.3	%
Total tons sold			633.7				781.6				-18.9	%
Met coal revenue		$	21,542			$	15,672				37.5	%
Steam coal revenue		$	16,009			$	29,762				-46.2	%
Total coal revenue		$	37,551			$	45,434				-17.4	%
Met coal revenues per ton		$	66.73			$	81.97				-18.6	%
Steam coal revenues per ton		$	51.50			$	50.41				2.2	%
Total coal revenues per ton		$	59.26			$	58.13				1.9	%
Met coal tons produced			311.3				251.1				24.0	%
Steam coal tons produced			355.9				426.0				-16.5	%
Total tons produced			667.2				677.1				-1.5	%

 

 

*

Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.

 

 

Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the years ended December 31, 2016 and 2015:

 

		Year ended				Year ended				Increase/(Decrease)
Segment		December 31, 2016				December 31, 2015				$				% *
		(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	21.5			$	46.0			$	(24.5	)			(53.3	%)
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			1.7				3.0				(1.3	)			(43.3	%)
Selling, general and administrative			13.4				13.8				(0.4	)			(2.9	%)
Cost of operations per ton*		$	33.87			$	58.73			$	(24.86	)			(42.3	%)
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	24.4			$	42.1			$	(17.7	)			(42.1	%)
Freight and handling costs			1.7				2.7				(1.0	)			(35.7	%)
Depreciation, depletion and amortization			0.8				1.9				(1.1	)			(57.9	%)
Selling, general and administrative			0.1				0.2				(0.1	)			(39.5	%)
Cost of operations per ton*		$	45.55			$	46.44			$	(0.89	)			(1.9	%)
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	28.0			$	31.8			$	(3.8	)			(11.8	%)
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			1.3				1.6				(0.3	)			(18.8	%)
Selling, general and administrative			0.1				0.1				-				(7.0	%)
Cost of operations per ton*		$	31.15			$	33.43			$	(2.28	)			(6.8	%)
Illinois Basin
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	51.3			$	43.6			$	7.7				17.8	%
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			2.1				1.5				0.6				40.0	%
Selling, general and administrative			0.2				0.1				0.1				134.2	%
Cost of operations per ton*		$	41.42			$	52.39			$	(10.97	)			(20.9	%)
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	10.2			$	10.1			$	0.1				0.7	%
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			0.2				0.2				-				n/a
Selling, general and administrative			2.5				1.8				0.7				38.9	%
Cost of operations per ton**			n/a				n/a				n/a				n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	135.4			$	173.6			$	(38.2	)			(22.0	%)
Freight and handling costs			1.7				2.7				(1.0	)			(35.7	%)
Depreciation, depletion and amortization			6.1				8.2				(2.1	)			(25.6	%)
Selling, general and administrative			16.3				16.0				0.3				1.9	%
Cost of operations per ton*		$	40.95			$	50.00			$	(9.05	)			(18.1	%)

 

 

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
**	Cost of operations presented for our Other category includes costs incurred by our ancillary businesses. The activities performed by these ancillary businesses do not directly relate to coal production. As a result, per ton measurements are not presented for our Other category.

 

 

 

Cost of Operations. Total cost of operations was $135.4 million for the year ended December 31, 2016 as compared to $173.6 million for the year ended December 31, 2015. Our cost of operations per ton was $40.95 for the year ended December 31, 2016, a decrease of $9.05, or 18.1%, from the year ended December 31, 2015. Total cost of operations decreased primarily due to lower costs in Central Appalachia and Northern Appalachia, as we reduced production in these regions in response to weak market demand, partially offset by increased costs from higher production at our Pennyrile mine in the Illinois Basin. The decrease in the cost of operations on a per ton basis was primarily due to a decrease from our Pennyrile mine in the Illinois Basin as we increased and optimized production during the year ended December 31, 2016 compared to the same period in 2015, as well as the $3.9 million benefit in Northern Appalachia for the year ended December 31, 2016 from the prior service cost benefit resulting from the cancellation of the postretirement benefit plan at our Hopedale operation.

 

Our cost of operations for the Central Appalachia segment decreased by $24.5 million, or 53.3%, to $21.5 million for the year ended December 31, 2016 from $46.0 million for the year ended December 31, 2015. Total cost of operations decreased year-to-year since we decreased production during the year ended December 31, 2016 in response to weak market conditions. Our cost of operations per ton of $33.87 for the year ended December 31 2016 was a reduction of 42.3% compared to $58.73 per ton for the year ended December 31, 2015, as we produced coal from lower cost operations during the year ended December 31, 2016.

 

In our Northern Appalachia segment, our cost of operations decreased by $17.7 million, or 42.1%, to $24.4 million for the year ended December 31, 2016 from $42.1 million for the year ended December 31, 2015. Our cost of operations per ton decreased to $45.55 for the year ended December 31, 2016 from $46.44 for the year ended December 31, 2015, a decrease of $0.89 per ton, or 1.9%. The decrease in cost of operations and cost of operations per ton was primarily due to decreased production during the year ended December 31, 2016 in response to weak market conditions as well as the $3.9 million prior service cost benefit for the year ended December 31, 2016 resulting from the cancellation of the postretirement benefit plan at our Hopedale operation.

 

Cost of operations in our Rhino Western segment decreased by $3.8 million, or 11.8%, to $28.0 million for the year ended December 31, 2016 from $31.8 million for the year ended December 31, 2015. The decrease in cost of operations was primarily due to decreased tons produced and sold from our Castle Valley operation due to weak customer demand. Our cost of operations per ton decreased to $31.15 per ton for the year ended December 31, 2016 from $33.43 per ton for year ended December 31, 2015. Total cost of operations and cost of operations per ton decreased for the year ended December 31, 2016 compared to the same period in 2015 due to lower maintenance and other costs from our Castle Valley operation.

 

Cost of operations in our Illinois Basin segment was $51.3 million while cost of operations per ton was $41.42 for the year ended December 31, 2016, both of which related to our Pennyrile mining complex in western Kentucky. For the year ended December 31, 2015, cost of operations in our Illinois Basin segment was $43.6 million and cost of operations per ton was $52.39. The increase in cost of operations was primarily the result of increased production year-to-year at the Pennyrile complex, while cost of operations per ton decreased as we continued to optimize the cost structure at this mining complex.

 

Cost of operations in our Other category remained relatively flat at $10.2 million and $10.1 million for the years ended December 31, 2016 and December 31, 2015, respectively.

 

Freight and Handling. Total freight and handling cost for the year ended December 31, 2016 decreased by $1.0 million, or 35.7%, to $1.7 million from $2.7 million for the year ended December 31, 2015. This decrease was primarily due to the decrease in tons of coal sold for 2016 compared to 2015 from our Sands Hill complex that required transportation by truck to customers’ locations.

 

Depreciation, Depletion and Amortization. Total DD&A expense for the year ended December 31, 2016 was $6.1 million as compared to $8.2 million for the year ended December 31, 2015.

 

For the year ended December 31, 2016, our depreciation cost was $5.1 million as compared to $7.5 million for the year ended December 31, 2015. This decrease is primarily due to a decrease in machinery and equipment depreciation from our Central Appalachia operations as excess equipment was disposed as coal production decreased due to weakness in the steam coal markets and as equipment became fully depreciated during 2016.

 

 

 

For the year ended December 31, 2016, our depletion cost was $0.4 million as compared to $0.3 million for the year ended December 31, 2015. This decrease resulted from fewer coal tons produced from our higher depletion rate properties in our Central Appalachia segment in 2016 compared to the prior year.

 

For the year ended December 31, 2016, our amortization cost remained relatively flat at $0.6 million as compared to $0.4 million for the year ended December 31, 2015.

 

Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the year ended December 31, 2016 increased to $16.3 million as compared to $16.0 million for the year ended December 31, 2015. This increase was primarily attributable to increased corporate overhead expenses at Royal, partially offset by a $0.4 million decrease at Rhino.

 

Interest Expense. Interest expense for the year ended December 31, 2016 was $6.9 million as compared to $5.0 million for the year ended December 31, 2015, an increase of $1.9 million, or 38.0%. This increase was primarily due to higher interest rates on our senior secured credit facility and write-off of $1.5 million deferred refinancing costs resulting from amendments to our credit facility.

 

Net Income (Loss.) The following table presents net income (loss) from continuing operations by reportable segment for the years ended December 31, 2016 and 2015:

 

		Year Ended December 31,								Increase
Segment		2016				2015				(Decrease)
		(in millions)
Central Appalachia		$	(21.8	)		$	(12.9	)		$	(8.9	)
Northern Appalachia			11.2				13.4				(2.2	)
Rhino Western			2.8				0.2				2.6
Illinois Basin			0.6				(9.4	)			10.0
Other			(4.1	)			(1.4	)			(2.7	)
Total		$	(11.3	)		$	(10.1	)		$	(1.2	)

 

For the year ended December 31, 2016, total net loss was a loss of approximately $11.3 million compared to a net loss of approximately $10.1 million for the year ended December 31, 2015. For the year ended December 31, 2016, our total net loss from continuing operations was impacted by a $16.7 million asset impairment charge in our Central Appalachia segment from the impairment of the Blaze Mining royalty in West Virginia.

 

For our Central Appalachia segment, net loss from continuing operations was approximately $21.8 million for the year ended December 31, 2016, a $8.9 million larger net loss as compared to the year ended December 31, 2015. The increase in loss from continuing operations for the year ended December 31, 2016 was primarily related to the impairment of the Blaze Mining royalty, partially offset by the reduction in operating costs of $24.2 million while revenues declined $18.4 million.

 

Net income our Northern Appalachia segment decreased by $2.3 million to income $11.2 million for the year ended December 31, 2016, from net income of $13.4 million for the year ended December 31, 2015. Cost of operations declined $17.7 million while revenue declined $22.8 million, reducing gross profit.

 

Net income in our Rhino Western segment was $2.8 million for the year ended December 31, 2016, compared to net income of $0.2 million for the year ended December 31, 2015. This improvement was primarily the result of lower costs at our Castle Valley operation during the year ended December 31, 2016 compared to the prior year.

 

 

For our Illinois Basin segment, we had net income of $0.6 million for the year ended December 31, 2016 compared to a net loss of $9.4 million for the year ended December 31, 2015. This improvement was primarily the result of increased coal sales at our Pennyrile mining complex as well as lower costs per ton as we continued to optimize the operations at this mining facility.

 

For the Other category, we had a net loss of $4.1 million for the year ended December 31, 2016, which was a $2.7 million larger net loss as compared to a net loss of $1.4 million for the year ended December 31, 2015. The increase in the net loss for the year ended December 31, 2016 was primarily due to the increase in Royal corporate overhead costs.

 

Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the years ended December 31, 2016 and 2015:

 

		Year Ended December 31,								Increase
Segment		2016				2015				(Decrease)
		(in millions)
Central Appalachia		$	(1.3	)		$	(7.8	)		$	6.5
Northern Appalachia			12.3				15.8				(3.5	)
Rhino Western			4.5				2.1				2.4
Illinois Basin			3.7				(7.3	)			11.0
Other			(2.2	)			0.3				(2.5	)
Total		$	17.0			$	3.1			$	13.9

 

Adjusted EBITDA for the year ended December 31, 2016 was $17.2 million, which was a $14.1 million increase compared to the year ended December 31, 2015. Adjusted EBITDA increased due to the improvement year-to-year in our loss, due mostly to lower costs. Please read “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA from continuing operations to net income on a segment basis.

 

Reconciliation of Adjusted EBITDA to Net Income by Segment

 

The following tables present reconciliations of Adjusted EBITDA to the most directly comparable GAAP financial measures for each of the periods indicated. Adjusted EBITDA excludes the effect of certain non-cash and/or non-recurring items. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate Adjusted EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies.

 

		Central				Northern				Rhino				Illinois
Year ended December 31, 2016		Appalachia				Appalachia				Western				Basin				Other				Total
Net (loss) income from continuing		$	(21.8	)		$	11.2			$	2.8			$	0.6			$	(4.1	)		$	(11.3	)
Plus:
DD&A			1.7				0.8				1.3				2.1				0.2				6.1
Interest expense*			2.1				0.3				0.4				1.0				1.7				5.5
EBITDA from continuing operations†*		$	(18.0	)		$	12.3			$	4.5			$	3.7			$	(2.2	)		$	0.3
Plus: Non-cash asset impairment and other non-cash charges			16.7				-				-				-				-				16.7
Adjusted EBITDA†*		$	(1.3	)		$	12.3			$	4.5			$	3.7			$	(2.2	)		$	17.0

 

 

		Central				Northern				Rhino				Illinois
Year ended December 31, 2015		Appalachia				Appalachia				Western				Basin				Other				Total
Net (loss) income from continuing		$	(12.9	)		$	13.4			$	0.2			$	(9.4	)		$	(1.4	)		$	(10.1	)
Plus:
DD&A			3.0				1.9				1.6				1.5				0.2				8.2
Interest expense*			2.1				0.5				0.3				0.6				1.5				5.0
EBITDA from continuing operations†*		$	(7.8	)		$	15.8			$	2.1			$	(7.3	)		$	0.3			$	3.1
Plus: Non-cash asset impairment and other non-cash charges			-				-				-				-				-				-
Adjusted EBITDA†*		$	(7.8	)		$	15.8			$	2.1			$	(7.3	)		$	0.3			$	3.1

 

  

†		Calculated based on actual amounts and not the rounded amounts presented in this table.
*		Totals may not foot due to rounding
***		The total $16.7 million of non-cash impairment charges incurred during the year ended December 31, 2016 million related to the impairment in the West Virginia segment of the Blaze Mining royalty Please see our more detailed discussion of these asset impairment and related charges that is included earlier in this section.
		We believe that the isolation and presentation of these specific items to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of these items provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of these items provides investors with enhanced comparability to prior and future periods of our operating results.

 

Liquidity and Capital Resources

 

Liquidity

 

The principal indicators of our liquidity are our cash on hand and availability under our amended and restated credit agreement. As of December 31, 2016, our available liquidity was $13.0 million, including cash on hand of $0.1 million and $12.9 million available under our credit facility. On May 13, 2016, we entered into a Fifth Amendment of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less by December 31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintains the amount available for letters of credit at $30 million. In December 2016, we entered into a Seventh Amendment of our amended and restated credit agreement. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provided for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. For more information about our amended and restated credit agreement, please read — “Amended and Restated Credit Agreement.”

 

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and service our debt. Historically, our sources of liquidity included cash generated by our operations, borrowings under our credit agreement and issuances of equity securities. Our ability to access the capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our equity securities, prevailing commodity prices and other macroeconomic factors outside of our control. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to significantly reduce our spending and to alter our short- or long-term business plan. We may also be required to consider other options, such as selling 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.

 

 

Since the current maturity date of our credit facility is December 31, 2017, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months from the date of filing our Annual Report on Form 10-K and thus substantial doubt is raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm has 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, 2016. 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.

 

Since our credit facility has an expiration date of December 2017, we determined that our credit facility debt liability of $10.0 million at December 31, 2016 should be classified as a current liability on our consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. We are also considering alternative financing options that could result in a new long-term credit facility. However, we may be unable to complete such a transaction on terms acceptable to us or at all. If we are unable to extend the expiration date of our amended and restated credit facility, we will have to secure alternative financing to replace our credit facility by the expiration date of December 2017 in order to continue our business operations. If we are unable to extend the expiration date of our amended and restated credit facility or secure a replacement 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. Furthermore, although met coal prices and demand have improved in recent months, if weak demand and low prices for steam coal persist and if met coal prices and demand weaken, 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 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. 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. Although we believe our lenders loans are well secured under the terms of our amended and restated credit agreement, there is no assurance that the lenders would agree to any such waiver. 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.

 

We continue to take measures, including the suspension of cash distributions on Rhino’s common and subordinated units and cost and productivity improvements, to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures and meet our financial commitments and debt service obligations.

 

Cash Flows

 

Net cash provided by operating activities was $10.0 million for the year ended December 31, 2016 as compared to $13.5 million for the year ended December 31, 2015. This decrease in cash provided by operating activities was primarily the result of unfavorable working capital changes for the year ended December 31, 2016 compared to December 31, 2015. We idled the majority of our Central Appalachia mining operations in the second half of 2015 and monetized excess coal inventory, which was the primary difference in the change of working capital accounts year to year.

 

Net cash used by investing activities was $9.5 million for the year ended December 31, 2016 as compared to $2.0 million provided by investing activities for the year ended December 31, 2015. The increase in cash used by investing activities was primarily due to the investment by Royal to acquire Rhino in the year ended December 31, 2016.

 

Net cash used in financing activities was $10.7 million and $8.8 million for the years ended December 31, 2016 and December 31, 2015, respectively. Stock sales and new debt by Royal coupled with limited partner contributions kept the net cash used in financing activities relatively constant.

 

 

 

Capital Expenditures

 

Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. For example, maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain our long-term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of reserves, acquisition of equipment for a new mine or the expansion of an existing mine to the extent such expenditures are expected to expand our long-term operating capacity.

 

Actual maintenance capital expenditures for the year ended December 31, 2016 were approximately $2.5 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the year ended December 31, 2016 were approximately $5.0 million, which were primarily related to the development of our Riveredge mine on our Pennyrile property in western Kentucky. For the year ending December 31, 2017, we have budgeted $10 million to $15 million for maintenance capital expenditures. We expect a minimal amount of 2017 expansion capital expenditures since we have completed the development of the Pennyrile mine and we currently do not anticipate developing any of our other internal projects in 2017.

 

Amended and Restated Credit Agreement

 

On July 29, 2011, we executed the Amended and Restated Credit Agreement. 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. In April 2015, the Amended and Restated Credit Agreement was amended and the borrowing commitment under the facility was reduced to $100.0 million and the amount available for letters of credit was reduced to $50.0 million. As described below, in March 2016 and May 2016, the borrowing commitment under the facility was further reduced to $80.0 million and $75.0 million, respectively, and the amount available for letters of credit was reduced to $30.0 million.

 

Loans under the senior secured credit facility currently bear interest at a base rate equaling the prime rate plus an applicable margin of 3.50%. The Amended and Restated Credit Agreement also contains letter of credit fees equal to an applicable margin of 5.00% multiplied by the aggregate amount available to be drawn on the letters of credit, and a 0.15% fronting fee payable to the administrative agent. In addition, we incur a commitment fee on the unused portion of the senior secured credit facility at a rate of 1.00% per annum. Borrowings on the line of credit are collateralized by all of our unsecured assets.

 

Our Amended and Restated Credit Agreement requires us 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. As of and for the year ended December 31, 2016, we were in compliance with respect to all covenants contained in the credit agreement.

 

On March 17, 2016, we entered into the Fourth Amendment of our Amended and Restated Credit Agreement. The Fourth Amendment amended the definition of change of control in the Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of our general partner. The Fourth Amendment reduced the borrowing capacity under the credit facility to a maximum of $80 million and reduced the amount available for letters of credit to $30 million. The Fourth Amendment eliminated the option to borrow funds utilizing the LIBOR rate plus an applicable margin and established 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 eliminated the capability to make Swing Loans under the facility and eliminated our ability to pay distributions to our common or subordinated unitholders. The Fourth Amendment altered 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 us 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 us on or after the Fourth Amendment effective date (other than the Royal equity contribution discussed above), or the disposition of any assets by us. The Fourth Amendment required us to maintain minimum liquidity of $5 million and minimum EBITDA (as defined in the credit agreement), calculated as of the end of the most recent month, on a trailing twelve month basis, of $8 million. The Fourth Amendment limited the amount of our capital expenditures to $15 million, calculated as of end of the most recent month, on a trailing twelve-month basis. The Fourth Amendment required us to provide monthly financial statements and a weekly rolling thirteen-week cash flow forecast to the Administrative Agent.

 

 

On May 13, 2016, we entered into the Fifth Amendment of our Amended and Restated Credit Agreement that extended the term to July 31, 2017. Per the Fifth Amendment, the credit facility will be automatically extended to December 31, 2017 if revolving credit commitments are reduced to $55 million or less on or before July 31, 2017. The Fifth Amendment immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintained the amount available for letters of credit at $30 million. The Fifth Amendment further reduced the revolving credit commitments over time on a dollar-for-dollar basis in amounts equal to each of the following: (i) the face amount of any letter of credit that expires or whose face amount is reduced by any such dollar amount, (ii) the net proceeds received from any asset sales, (iii) the Royal scheduled capital contributions (as outline below), (iv) the net proceeds from the issuance of any equity by us up to $20.0 million (other than equity issued in exchange for any Royal contribution as outlined in the Securities Purchase Agreement or the Royal scheduled capital contributions to us as outlined below), and (v) the proceeds from the incurrence of any subordinated debt. The first $11 million of proceeds received from any equity issued by us described in clause (iv) above shall also satisfy the Royal scheduled capital contributions as outlined below. The Fifth Amendment requires Royal to contribute $2 million each quarter beginning September 30, 2016 through September 30, 2017 and $1 million on December 1, 2017, for a total of $11 million. The Fifth Amendment further reduces the revolving credit commitments as follows:

 

Date of Reduction	Reduction Amount
September 30, 2016	The lesser of (i) $2 million or (ii) the positive difference (if any) of $2 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)
December 31, 2016	The lesser of (i) $2 million or (ii) the positive difference (if any) of $4 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)
March 31, 2017	The lesser of (i) $2 million or (ii) the positive difference (if any) of $6 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)
June 30, 2017	The lesser of (i) $2 million or (ii) the positive difference (if any) of $8 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)
September 30, 2017	The lesser of (i) $2 million or (ii) the positive difference (if any) of $10 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)
December 1, 2017	The lesser of (i) $1 million or (ii) the positive difference (if any) of $11 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)

 

The Fifth Amendment requires that on or before March 31, 2017, we shall have solicited bids for the potential sale of certain non-core assets, satisfactory to the administrative agent, and provided the administrative agent, and any other lender upon its request, with a description of the solicitation process, interested parties and any potential bids. The Fifth Amendment limits any payments by us to our general partner to: (i) the usual and customary payroll and benefits of the our management team so long as our management team remains employees of our general partner, (2) the usual and customary board fees of our general partner, and (3) the usual and customary general and administrative costs and expenses of our general partner incurred in connection with the operation of its business in an amount not to exceed $0.3 million per fiscal year. The Fifth Amendment limits asset sales to a maximum of $5 million unless we receive consent from the lenders. The Fifth Amendment altered the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve-month basis, as follows:

 

Period	Ratio
For the month ending April 30, 2016, through the month ending May 31, 2016	7.50 to 1.00
For the month ending June 30, 2016, through the month ending August 31, 2016	7.25 to 1.00
For the month ending September 30, 2016, through the month ending November 30, 2016	7.00 to 1.00
For the month ending December 31, 2016, through the month ending March 31, 2017	6.75 to 1.00
For the month ending April 30, 2017, through the month ending June 30, 2017	6.25 to 1.00
For the month ending July 31, 2017, through the month ending November 30, 2017	6.0 to 1.00
For the month ending December 31, 2017	5.50 to 1.00

 

 

The leverage ratios above shall be reduced by 0.50 to 1.00 for every $10 million of aggregate proceeds received by us from: (i) the issuance of our equity (excluding any Royal capital contributions) and/or (ii) the proceeds received from the sale of assets, provided that the leverage ratio shall not be reduced below 3.50 to 1.00. The Fifth Amendment removes the $5.0 million minimum liquidity requirement and requires us to have any deposit, securities or investment accounts with a member of the lending group.

 

In July 2016, we entered into the Sixth Amendment of our amended and restated senior secured credit facility that permitted the sale of Elk Horn that was discussed earlier. The Sixth Amendment reduced the maximum commitment amount allowed under the credit facility based on the initial cash proceeds of $10.5 million that were received for the Elk Horn sale. The Sixth Amendment further reduced the maximum commitment amount allowed under the credit facility for the additional $1.5 million to be received from the Elk Horn sale by $375,000 each quarterly period beginning September 30, 2016 through June 30, 2017.

 

In December, 2016, we entered into a Seventh Amendment, which allows for the Series A preferred units as outlined in the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, which is further discussed in “Recent Developments”. The Seventh Amendment immediately reduces the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. The Seventh Amendment alters the maximum leverage ratio to 4.0 to 1.0 effective December 31, 2016 through May 31, 2017 and 3.5 to 1.0 from June 30, 2017 through December 31, 2017. The maximum leverage ratio shall be reduced by 0.50 to 1.0 for every $10.0 million of net cash proceeds, in the aggregate, received after the Seventh Amendment date from (i) the issuance of any equity by us and/or (ii) the disposition of any assets in excess of $2.0 million in the aggregate, provided, however, that in no event will the maximum leverage ratio be reduced below 3.0 to 1.0. The Seventh Amendment alters the minimum consolidated EBITDA figure, as calculated on a rolling twelve months basis, to $12.5 million from December 31, 2016 through May 31, 2017 and $15.0 million from June 30, 2017 through December 31, 2017. The Seventh Amendment alters the maximum capital expenditures allowed, as calculated on a rolling twelve months basis, to $20.0 million through the expiration of the credit facility. A condition precedent to the effectiveness of the Seventh Amendment was the receipt of the $13.0 million of cash proceeds received by us from the issuance of the Series A preferred units pursuant to the Preferred Unit Agreement, which we used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contributions as outlined in the previous amendments to our credit agreement.

 

At December 31, 2016, $10.0 million was outstanding under the facility at a variable interest rate of PRIME plus 3.50% (7.25% at December 31, 2016). In addition, we had outstanding letters of credit of approximately $26.1 million at a fixed interest rate of 5.00% at December 31, 2016. Based upon a maximum borrowing capacity of 4.00 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), we had not used $12.9 million of the borrowing availability at December 31, 2016. During the year ended December 31, 2016, we had average borrowings outstanding of approximately $38.4 million under our credit agreement.

 

Off-Balance Sheet Arrangements

 

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

 

Federal and state laws require us to secure certain long-term obligations related to mine closure and reclamation costs. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of our credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank letters of credit in an amount of up to 25% of the aggregate bond liability. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

 

 

As of December 31, 2016, we had $26.1 million in letters of credit outstanding, of which $20.7 million served as collateral for approximately $48.9 million in our surety bonds outstanding that secure the performance of our reclamation obligations.

 

Contractual Obligations

 

The following lists our contractual obligations as of December 31, 2016.

 

		Payments Due by Period
		Total				Less than 1 Year				1-3 Years				4-5 Years				More than 5 Years
		(in thousands)
Debt obligations			12,040			$	12,040			$	-			$	-			$	-
Asset retirement obligations			27,420				917				4,816				2,293				19,394
Operating lease obligations (a)			2,681				2,533				148				-				-
Diesel Fuel obligations			2,034				2,034				-				-				-
Advance royalties (b)			17,171				1,640				3,280				3,415				8,836
Total		$	61,346			$	19,164			$	8,244			$	5,708			$	28,230

 

(a) Some of our surface mining equipment and a coal handling and loading facility are categorized as operating leases.

(b) We have obligations on various coal and land leases to prepay certain amounts, which are recoupable in future years when mining occurs.

 

Critical Accounting Policies and Estimates

 

Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates and judgments on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Nevertheless, actual results may differ from the estimates used and judgments made. Note 2 to the consolidated financial statements included elsewhere in this report provides a summary of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity.

 

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. Gains or losses arising from sales or retirements are included in current operations.

 

 

 

On March 30, 2005, the Financial Accounting Standards Board (FASB) ratified the consensus reached by the Emerging Issues Task Force, or EITF, on accounting for stripping costs in the mining industry. This accounting guidance applies to 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. Under the guidance, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. We have recorded stripping costs for all of our surface mines incurred during the production phase as variable production costs that are included in the cost of inventory produced. We define a surface mine as a location where we utilize 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, we define 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. We capitalize only the development cost of the first pit at a mine site that may include multiple pits.

 

Asset Impairments

 

We follow the accounting guidance on the impairment or disposal of property, plant and equipment, 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, we must determine the fair value for the assets in question in accordance with the applicable fair value accounting guidance. Once the fair value is determined, the appropriate impairment loss must be recorded as the difference between the carrying amount of the assets and their respective fair values. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. 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 asset carrying values will not be recoverable during a shorter mine life, a provision for such impairment is recognized.

 

We performed a comprehensive review of our current coal mining operation as well as potential future development projects as of December 31, 2016 to ascertain any potential impairment losses. Based on the impairment analysis, we concluded that none of the coal properties, mine development costs or other coal mining equipment and related facilities were impaired at December 31, 2016, except for the Blaze Mining royalty. For the year ended December 31, 2016, the Company recorded a $16.7 million asset impairment related to the Blaze Mining royalty .

 

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. We have recorded the asset retirement costs in Coal properties.

 

We estimate our future cost requirements for reclamation of land where we have conducted surface and underground mining operations, based on our 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 or exit costs.

 

We expense 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, we review our end of mine reclamation and closure liability and make 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, 2016 were calculated with discount rates that ranged from 7.0% to 9.12%. 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%. The discount rates changed from previous years 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 2016 and 2015.

 

Workers’ Compensation and Pneumoconiosis (“black lung”) Benefits

 

Certain of our 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. We currently utilize an insurance program and state workers’ compensation fund participation to secure our 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.

 

Our 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 our black lung benefit liability are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and interest rates.

 

In addition, our 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 our workers’ compensation liability are based on numerous assumptions including claim development patterns, mortality, medical costs and interest rates.

 

Revenue Recognition

 

Most of our revenues are generated under supply contracts with electric utilities, industrial companies or other coal-related organizations, primarily in the 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 supply contract. Under the typical terms of these contracts, 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 are deferred and recognized in revenue as coal is shipped and title has passed.

 

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 limestone sales, coal handling and processing, rebates and rental income. With respect to other revenues recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and do 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.

 

Derivative Financial Instruments

 

We occasionally use diesel fuel contracts to manage the risk of fluctuations in the cost of diesel fuel. Our diesel fuel contracts meet the requirements for the normal purchase normal sale, or NPNS, exception prescribed by the accounting guidance on derivatives and hedging, based on the terms of the contracts and management’s intent and ability to take physical delivery of the diesel fuel.

 

Recent Accounting Pronouncements

 

Refer to Item 8. Note 2 of the notes to the consolidated financial statements for a discussion of recent accounting pronouncements, which is incorporated herein by reference. There are no known future impacts or material changes or trends of new accounting guidance beyond the disclosures provided in Note 2.

 

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk and interest rate risk.

 

Commodity Price Risk

 

We manage our commodity price risk for coal sales through the use of supply contracts. As of December 31, 2016, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

 

		Tons				Number of
Year		(in thousands)				customers
2017			3,669				14
2018			701				5

 

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

 

In addition, we manage the commodity price exposure associated with the diesel fuel and explosives used in our mining operations through the use of forward contracts with our suppliers. We are also subject to price volatility for steel products used for roof support in our underground mines, which is managed through negotiations with our suppliers since there is not an active forward contract market for steel products.

 

A hypothetical increase of $0.10 per gallon for diesel fuel would have increased net loss by $0.2 million for the year ended December 31, 2016. A hypothetical increase of 10% in steel prices would have increased net loss by $0.8 million for the year ended December 31, 2016. A hypothetical increase of 10% in explosives prices would have increased net loss by $0.2 million for the year ended December 31, 2016.

 

Interest Rate Risk

 

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $0.3 million for the year ended December 31, 2016.

 

Item 8. Financial Statements and Supplementary Data.

 

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-1 through F-43 of this report and are incorporated herein by reference.

 

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

 

(a) Resignation of Paritz & Company, P.A.

 

	(1)	Effective August 11, 2016, we received notification from Paritz & Company, P.A. (“Paritz”) that they would be unable to continue as the Company’s principal independent registered public accounting firm. The board of directors does not have a separate audit committee and approved the resignation of Paritz.
	(2)	The report of Paritz on the Company’s financial statements for the fiscal years ended August 31, 2015 did not contain an adverse opinion or disclaimer of opinion, nor was it modified as to uncertainty, audit scope or accounting principles, except that Paritz’s report for those fiscal year includes an explanatory paragraph and note stating, among other things, that we have had incurred a loss since inception, had a net accumulated deficit and may be unable to raise further equity, which raised substantial doubt about our ability to continue as a going concern.

 

 

(3)

During the fiscal year ended August 31, 2015 and during the subsequent period through the date of Paritz’s termination, there were no disagreements between us and Paritz, whether or not resolved, on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which if not resolved to the satisfaction of Paritz, would have caused Paritz to make reference thereto in its report on our audited financial statements. In connection with the audits of the fiscal years ended August 31, 2015 and the subsequent period through August 11, 2016, there have been no “reportable events” (as defined in Item 304(a)(1)(v) of Regulation S-K).

 

(b) Engagement of Brown Edwards

 

	(1)	Effective August 11, 2016, we engaged Brown Edwards & Company, LLP (“Brown”) as our independent registered public accounting firm. The engagement was approved by the board of directors, which also serves the role of audit committee.
	(2)	In connection with our appointment of Brown as our independent registered accounting firm, we had not consulted Brown on any matter relating to the application of accounting principles to a specific transaction, either completed or contemplated, or the type of audit opinion that might be rendered on our financial statements. Brown also serves as the Partnership’s independent registered public accounting firm.

 

Item 9A. Controls and Procedures.

 

(a)

Disclosure Controls and Procedures.

 

Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our disclosure controls and procedures were not effective as of December 31, 2016 at the reasonable assurance level. For purposes of this section, the term “disclosure controls and procedures” means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

 

(b)

Management’s Report on Internal Control over Financial Reporting.

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed under the supervision of our CEO and CFO, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

Under the supervision and with the participation of our management, including the CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting based upon the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework). Based on our evaluation under this framework, our management concluded that our internal control over financial reporting was not effective as of December 31, 2016 in the following areas:

 

Segregation of Duties: We do not have sufficient controls over financial reporting due to a lack of segregation of duties (which was a continuation of what had existed as of August 31, 2015, as reported in the 2015 Form 10-K). Specifically:

 

	1	There are not formal controls over our cash receipts and disbursements; individuals with control over cash also have significant roles with us, and compensating controls are not adequate to fully reduce this control deficiency.
	2	Individuals who have responsibility for recording transactions are also responsible for reconciliations and the financial close process. Our limited number of personnel in turn limits the distribution of review and reconciliation responsibilities.

 

Financial Close, Consolidation and Reporting: We do not have effective internal controls over its financial close, consolidation and reporting process. During 2016, beginning with the acquisition of controlling interest in Rhino Resource Partners, LP, our financial reporting complexities increased significantly without a corresponding increase in our resources dedicated to maintenance of a control structure and the preparation of financial information to be included in its public filings. We are evaluating various plans to restructure our financial closing process, including engaging additional personnel experienced in financial reporting and evaluating the time commitment and responsibilities of those currently assigned such responsibilities.

 

(c)

Attestation Report of the Registered Public Accounting Firm.

 

Our financial statements have been audited by Brown Edwards & Company, LLP, an independent registered public accounting firm, which was engaged on August 11, 2016 to audit our financial statements as a smaller reporting company. This is the first fiscal year in which we became an accelerated filer. Brown Edwards has not been engaged to audit our internal controls over financial reporting.

 

 

(d)

Changes in Internal Control Over Financial Reporting.

 

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

Item 9B. Other Information.

 

None.

 

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance.

 

Executive Officers and Directors

 

The following table shows information for our executive officers and directors from January 1, 2016 to December 31, 2016, and certain executive officers of the Partnership from March 17, 2016 to December 31, 2016:

 

Name		Age (as of 12/31/2016)		Position With Our General Partner
William Tuorto		47		Chairman of the Board of Directors and Chief Executive Office of Royal, and Chairman of the Board of Directors of Rhino
Brian Hughs		39		Vice President and Director of Royal, and Director of Rhino
Ronald Phillips		50		Vice President of Royal and Director of Rhino
Douglas Holsted		56		Chief Financial Officer of Royal, and Director of Rhino
Richard A. Boone*		62		President, Chief Executive Officer and Director of Rhino
Joseph E. Funk(1)*		56		Former President, Chief Executive Officer and Director of Rhino
Wendell S. Morris*		49		Vice President and Chief Financial Officer of Rhino
Reford C. Hunt*		43		Senior Vice President of Business Development of Rhino
Whitney C. Kegley*		41		Vice President, Secretary and General Counsel of Rhino
Brian T. Aug*		45		Vice President of Sales of Rhino
Ian Ganzer(2)		32		Former Chief Operating Officer of Royal, and Director of Rhino

 

(1) Mr. Funk resigned as an officer and director of Rhino effective as of December 30, 2016.

 

(2) Mr. Ganzer submitted his resignation as our officer and director, and as a director of Rhino as of September 13, 2016.

 

*	Officers of Rhino

 

William Tuorto. Mr. Tuorto has served as our Chairman and Chief Executive Officer since March 6, 2015. Mr. Tuorto has served as the Chairman of the board of directors of the Partnership since March 17, 2016. Mr. Tuorto has been providing legal, financial, and consulting services to public companies for over 19 years. Privately, Mr. Tuorto is an investor and entrepreneur, with holdings in a wide-range portfolio of energy, technology, real estate and hospitality. Mr. Tuorto was awarded a Bachelor of Arts degree from The Citadel in 1991, graduating with honors, and distinguished nominee of the Fulbright Fellowship and Rhodes Scholarship. Mr. Tuorto received his Juris Doctor from the University of South Carolina School of Law in 1995. Mr. Tuorto was selected to serve as a director due to his in-depth business knowledge and investment experience.

 

Brian Hughs. Mr. Hughs has served as our Vice President and a director since October 13, 2015. Mr. Hughs has served as a director of our general partner since March 17, 2016. Mr. Hughs has been in the private sector as a business owner and entrepreneur since 2001. Through Mr. Hughs’ familial involvement in the exploration and production of oil and gas in northern Texas, he brings specialized knowledge and expertise in this field of prospective investments. Mr. Hughs was selected to serve as a director due to his in-depth business knowledge and investment experience.

 

 

Ronald Phillips. Mr. Phillips has served as our President since October 13, 2015. Mr. Phillips has also served as a director of the Partnership since March 17, 2016. Mr. Phillips and previously served as Vice President at World Business Lenders, a private lending institution based in New York City. Mr. Phillips previously ran the DKR Capital Event Driven Fund in Stamford, Connecticut. Mr. Phillips received his Bachelor of Arts from Brown University in 1989 and his Juris Doctor from Stanford Law School in 1992. Mr. Phillips was selected to serve as a director due to his in-depth business knowledge and investment experience.

 

Douglas Holsted. Mr. Holsted has served as our Chief Financial Officer since June 8, 2015. Mr. Holsted has served as a director of the Partnership since March 17, 2016. Mr. Holsted is the owner of Cox, Holsted & Associates, PC, of Oklahoma City, Oklahoma. He brings more than 25 years’ experience in the public sector, overseeing all audit, review, tax and SEC compliance and business evaluations for Royal. Mr. Holsted received his BS in accounting from the University of Central Oklahoma and a Master of Taxation from DePaul University. Mr. Holsted was selected to serve as a director due to his in-depth business knowledge and financial experience.

 

Richard A. Boone. Mr. Boone has served as President and Chief Executive Officer of our general partner since December 30, 2016. Prior to December 2016, Mr. Boone served as our President since September 2016 and served as Executive Vice President and Chief Financial Officer since June 2014. Prior to June 2014, Mr. Boone served as Senior Vice President and Chief Financial Officer of our general partner since May 2010, and as Senior Vice President and Chief Financial Officer of Rhino Energy LLC since February 2005. Prior to joining Rhino Energy LLC, he served as Vice President and Corporate Controller of PinnOak Resources, LLC, a coal producer serving the steel making industry, since 2003. Prior to joining PinnOak Resources, LLC, he served as Vice President, Treasurer and Corporate Controller of Horizon Natural Resources Company, a producer of steam and metallurgical coal, since 1998. In total, Mr. Boone has approximately 35 years of experience in the coal industry.

 

Wendell S. Morris. Mr. Morris has served as our general partner’s Vice President and Chief Financial Officer since September 2016. From June 2015 to September 2016, Mr. Morris served as our general partner’s Vice President of Finance and prior to June 2015, Mr. Morris served as our general partner’s Vice President of External Reporting and Investor Relations. Prior to joining Rhino Energy LLC, Mr. Morris was employed by Lexmark International, Inc. where he held various financial and accounting positions.

 

Reford C. Hunt. Mr. Hunt has served as our general partner’s Senior Vice President of Business Development since August 2014. From May 2010 to August 2014, Mr. Hunt served as our general partner’s Vice President of Technical Services. Since April 2005, Mr. Hunt has served in various capacities with Rhino Energy LLC and its subsidiaries, including as Chief Engineer and Director of Operations. Mr. Hunt currently serves as Vice President of Technical Services of Rhino Energy LLC, a position he has held since August 2008, as Vice President of Rhino Energy WV LLC and McClane Canyon Mining LLC since September 2009 and as Vice President of Castle Valley Mining LLC since August 2010. Prior to joining Rhino Energy LLC, Mr. Hunt was employed by Sidney Coal Company, a subsidiary of Massey Energy Company, from 1997 to 2005. During his time at Sidney Coal Company as a Mining Engineer, he oversaw planning, engineering, and construction for various mining and preparation operations. In total, Mr. Hunt has approximately 18 years of experience in the coal industry.

 

Whitney C. Kegley. Ms. Kegley has served as our general partner’s Vice President, Secretary and General Counsel since July 2012. Prior to joining our general partner, and beginning in April 2012, Ms. Kegley served as a partner with the law firm of Dinsmore & Shohl, LLP in their Lexington, KY office. Ms. Kegley concentrated her practice on mergers and acquisitions and general corporate law with an emphasis on mineral and energy law. From March 2009 to April 2012, Ms. Kegley was a member in the Lexington, KY office of McBrayer, McGinnis, Leslie & Kirkland, PLLC, where she concentrated on mergers and acquisitions and general corporate law with an emphasis on mineral and energy law. From August 1999 to March 2009, Ms. Kegley was employed by the law firm of Frost Brown Todd LLC where she held various positions.

 

Brian T. Aug. Mr. Aug has served as our general partner’s Vice President of Sales since August 2013. From April 2011 to August 2013, Mr. Aug served as Director of Sales and Marketing for Rhino Energy LLC. Prior to joining Rhino Energy LLC, he was Vice President of Marketing and Trading Analysis for Greenstar Global Energy, a US based corporation focused on the selling of US coals into India. From 1994 until 2010 he worked for Duke Energy Ohio, a Midwest utility with coal and natural gas power generation. The last 10 years of his career at Duke Energy Ohio was spent as Director of Fuels.

 

 

Director Independence

 

None of the members of our board of directors are independent as defined under the independence standards established by the NYSE and the Exchange Act.

 

Meetings; Committees of the Board of Directors

 

Our board of directors held no formal meetings during the year ended December 31, 2016.

 

We do not currently have an executive committee. We do not have a separately-designated standing audit committee. The entire Board of Directors performs the functions of an audit committee, but no written charter governs the actions of the Board when performing the functions of what would generally be performed by an audit committee. The Board approves the selection of our independent accountants and meets and interacts with the independent accountants to discuss issues related to financial reporting. In addition, the Board reviews the scope and results of the audit with the independent accountants, reviews with management and the independent accountants our annual operating results, considers the adequacy of our internal accounting procedures and considers other auditing and accounting matters including fees to be paid to the independent auditor and the performance of the independent auditor.

 

Our Board of Directors does not maintain a nominating committee. As a result, no written charter governs the director nomination process. The size of our Board does not require a separate nominating committee.

 

When evaluating director nominees, our directors consider the following factors:

 

●	The appropriate size of our Board of Directors;
●	Our needs with respect to the particular talents and experience of our directors;
●	The knowledge, skills and experience of nominees, including experience in finance, administration or public service, in light of prevailing business conditions and the knowledge, skills and experience already possessed by other members of the Board;
●	Experience in political affairs;
●	Experience with accounting rules and practices; and
●	The desire to balance the benefit of continuity with the periodic injection of the fresh perspective provided by new Board members.

 

Our goal is to assemble a Board that brings together a variety of perspectives and skills derived from high quality business and professional experience. In doing so, the Board will also consider candidates with appropriate non-business backgrounds.

 

Other than the foregoing, there are no stated minimum criteria for director nominees, although the Board may also consider such other factors as it may deem are in our best interests as well as our stockholders. In addition, the Board identifies nominees by first evaluating the current members of the Board willing to continue in service. Current members of the Board with skills and experience that are relevant to our business and who are willing to continue in service are considered for re-nomination. If any member of the Board does not wish to continue in service or if the Board decides not to re-nominate a member for re-election, the Board then identifies the desired skills and experience of a new nominee in light of the criteria above. Current members of the Board are polled for suggestions as to individuals meeting the criteria described above. The Board may also engage in research to identify qualified individuals. To date, we have not engaged third parties to identify or evaluate or assist in identifying potential nominees, although we reserve the right in the future to retain a third party search firm, if necessary. The Board does not typically consider shareholder nominees because it believes that its current nomination process is sufficient to identify directors who serve our best interests.

 

 

Executive Sessions of Non-Management Directors; Procedure for Contacting the Board of Directors

 

We do not have any non-management directors, and therefore there have been no meetings of our board of directors without any members of management present.

 

We have not established a formal process for interested parties to contact our board of directors directly. However, contact information for our executive officers is published on our website at www.royalenergy.us, or in writing to Royal Energy Resources, Inc., 56 Broad Street, Suite 2, Charleston, South Carolina 29401, attention Chief Executive Officer. Information may be submitted confidentially and anonymously, although we may be obligated by law to disclose the information or identity of the person providing the information in connection with government or private legal actions and in certain other circumstances.

 

Role of Board in Risk Oversight Process

 

Management is responsible for the day-to-day management of risk and for identifying our risk exposures and communicating such exposures to our board. Our board is responsible for designing, implementing and overseeing our risk management processes. The board does not have a standing risk management committee, but administers this function directly through the board as a whole. The whole board considers strategic risks and opportunities and receives reports from its officers regarding risk oversight in their areas of responsibility as necessary. We believe our board’s leadership structure facilitates the division of risk management oversight responsibilities and enhances the board’s efficiency in fulfilling its oversight function with respect to different areas of our business risks and our risk mitigation practices.

 

Compensation Committee Interlocks and Insider Participation

 

William L. Tuorto and Brian Hughs were the only members of our board of directors during the fiscal year ended December 31, 2016, and each was also an officer of us during that period. Mr. Hughs does not have a relationship with us requiring disclosure by us pursuant to Item 404 of Regulation S-K. However, Mr. Tuorto had the following relationship with us during the year ending December 31, 2016 requiring disclosure by us:

 

On March 6, 2015, we borrowed $203,593 from E-Starts Money Co. (“E-Starts”) pursuant to a demand promissory date, which bears interest at six percent per annum. We used the proceeds to repay all of our indebtedness at the time. On June 11, 2015, we borrowed an additional $200,000 from E-Starts Money Co. pursuant to a non-interest bearing demand promissory note. On September 22, 2016, we borrowed $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note and on December 8, 2016, we borrowed an additional $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note. The total amount owed to E-Starts at December 31, 2016 was $503,593, plus accrued interest. Mr. Tuorto controls E-Starts.

 

No executive officer of us served as a member of (i) the compensation committee of another entity of which one of the executive officers of such entity served on our compensation committee (or board committee performing equivalent functions) or (ii) the board of directors of another entity of which one of the executive officers of such entity served on our board, during the fiscal year ended December 31, 2016.

 

Code of Ethics

 

Our Board of Directors has not adopted a Code of Business Conduct and Ethics.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

Section 16(a) of the Exchange Act requires directors, executive officer and persons who beneficially own more than 10% of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. Based upon a review of the copies of the forms furnished to us and written representations from certain reporting persons, we believe that, during the year ended December 31, 2016, none of our executive officers, directors or beneficial owners of more than 10% of any class of registered equity security failed to file on a timely basis any such report, except as described below.

 

William L. Tuorto: Mr. Tuorto filed Form 4’s on January 21, 2016, February 1, 2016 and March 4, 2016 each of which reported multiple sales of common stock in open market transactions, some of which occurred more than four days before the Form 4’s were filed. Mr. Tuorto filed a Form 4 on October 11, 2016 reporting open market purchases of common stock from August 8, 2016 to September 13, 2016, which trades occurred more than four days before the Form 4 was filed. Mr. Tuorto also failed to file a Form 4 reporting the receipt of 11,608 shares of common stock on February 17, 2016 in payment of accrued compensation, but reported the transaction on a Form 5 filed in 2017 after the deadline therefor.

 

Brian Hughs: Mr. Hughs failed to file a Form 4 reporting the receipt of 11,608 shares of common stock on February 17, 2016 in payment of accrued compensation, as well as open market sales of common stock from February 9, 2016 to April 1, 2016 in 22 transactions. Mr. Hughs filed a Form 5 reporting these transactions in 2017 after the deadline therefor.

 

Ronald Phillips: Mr. Phillips filed a Form 4 on May 16, 2016 reporting the sale of 700 shares of common stock, which report was filed one day late. Mr. Phillips failed to file a Form 4 reporting four sales of common stock from May 20, 2016 to May 31, 2016, but reported the transactions on a Form 5 filed in 2017 after the deadline therefor. Mr. Phillips failed to file a Form 4 reporting the receipt of 4,878 shares of common stock on February 17, 2016 in payment of accrued compensation, but reported the transaction on a Form 5 filed in 2017 after the deadline therefor.

 

Item 11. Executive Compensation

 

Introduction

 

On March 17, 2016, we acquired control of the Partnership when we purchased the general partner of the General Partner, and a majority of the outstanding common and subordinated units of the Partnership. The general partner of the Partnership has the sole responsibility for conducting the Partnership’s business and for managing its operations, and its board of directors and officers make decisions on the Partnership’s behalf. The compensation committee of the board of directors of the general partner determines the compensation of the directors and officers of the general partner, including its named executive officers. The compensation payable to the officers of the general partner is paid by the general partner and reimbursed by the Partnership us on a dollar-for-dollar basis.

 

For the fiscal year ending December 31, 2016, our named executive officers were:

 

●	William Tuorto—Chairman and Chief Executive Officer, and Executive Chairman and Director of the Partnership;
●	Brian Hughs – Vice President and Director, and Director of the Partnership
●	Douglas C. Holsted – Chief Financial Officer
●	Richard A. Boone—President, Chief Executive Officer and Director of the Partnership;
●	Joseph E. Funk—Former President, Chief Executive Officer and Director of the Partnership; and
●	Reford C. Hunt— Senior Vice President of Business Development of the Partnership.

 

 

With respect to the compensation disclosures and the tables that follow, these individuals are referred to as the “named executive officers.”

 

Changes to Named Executive Officers

 

On March 6, 2015, Jacob Roth resigned as our Chief Executive Officer and Chief Financial Officer, and Mr. Tuorto was appointed Chief Executive Officer and Interim Chief Financial Officer.

 

On September 13, 2016, Ian Ganzer resigned as our Chief Operating Officer.

 

On December 30, 2016, Mr. Funk resigned as the Partnership’s Chief Executive Officer and agreed to continue employment with the Partnership through March 31, 2017 as a special advisor. Mr. Boone was named Chief Executive Officer effective January 1, 2017.

 

Summary Compensation Table

 

The following table sets forth the cash and other compensation earned by each of our named executive officers for the years ended December 31, 2016 and 2015. With respect to named executive officers employed by the Partnership, the following table only reflects their compensation from March 17, 2016 to December 31, 2016, the period in which the Partnership was majority owned by us.

 

Name and Principal Position		Year		Salary ($)				Bonus ($)(1)				Non-Equity Incentive Plan ($)(2)				Stock/Unit Awards ($)(3)				All Other Compensation ($)(4)				Total ($)
William Tuorto		2016			491,814				187,500				-				250,000				25,600				954,914
Chairman and Chief Executive of Royal, and Executive Chairman and Director of Rhino		2015			75,269				150,000				-				-				-				225,269-
Richard A. Boone		2016			249,981				50,000				-				125,000				8,282				433,263
President, Chief Executive Officer and Director of Rhino		2015			-				-				-				-				-				-
Reford C. Hunt		2016			225,077				-				-				-				8,514				233,591
Senior Vice President of Business Development of Rhino		2015			-				-				-				-				-				-
Joseph E. Funk		2016			292,233				200,000				150,000				-				3,522				645,755
Former President and Chief Executive Officer of Rhino		2015			-				-				-				-				-				-
Brian Hughs		2016			354,314																15,000				369,314
Vice President and Director of Royal, and Director of Rhino		2015			75,269				150,000																225,269
Douglas C. Holsted		2016			-				-				-				-				-				-
Chief Financial Officer of Royal		2015			-				-				-				-				50,000				50,000
Jacob Roth		2016			-				-				-				-				-				-
Chief Executive Officer and Chief Financial Officer of Royal		2015			-				-				-				-				-				-

 

	(1)	For fiscal 2015, bonuses for Messrs. Tuorto and Hughs were paid in shares of our common stock at its market value on the date of issuance. For fiscal 2016, bonuses for all officers other than Mr. Funk were paid by the Partnership, and reflect the annual cash bonus awarded to each of the named executive officers per the terms of their employment agreements, which are described further below. With respect to Mr. Funk, the amount represents a portion of the guaranteed payments that he was entitled to receive upon his resignation, as described more fully below.
	(2)	The non-equity compensation amount for Mr. Funk consists of $150,000 paid by the Partnership in August 2016 in connection with the sale of our Elk Horn coal leasing business.
	(3)	The amounts reported in the “Unit Awards” column reflect the aggregate grant date fair value of phantom unit awards granted under the Rhino Long-Term Incentive Plan (the “LTIP”), computed in accordance with FASB ASC Topic 718. See Note 2 to our consolidated financial statements for additional detail regarding assumptions underlying the value of these equity awards. All phantom unit awards granted during the 2016 year were fully vested on the date of grant.

 

 

 

	(4)	Amounts reflect, as applicable with respect to the named executive officers and as provided in the supplemental table below, the use of a company provided automobile and employer contributions to the 401(k) Plan. The value of automobile use is calculated as the monthly lease payment paid by us on behalf of the executive multiplied by the monthly percentage of personal use of the automobile by the executive. With respect to Messrs. Tuorto and Hughs only, amounts reflected include $15,000 of director fees paid by the Partnership. With respect to Mr. Holsted, amounts paid in fiscal 2015 reflect accounting fees paid to an accounting firm in which Mr. Holsted is a partner.
	(5)	Compensation for Messrs. Boone, Hunt and Funk only includes their compensation from March 17, 2017 to December 31, 2016, the period of time that the Partnership was our subsidiary in fiscal 2016.
	(6)	Compensation for Messrs. Tuorto, Hughs, Holsted and Roth for fiscal 2015 includes their compensation from January 1, 2015 to December 2015.

 

“Other compensation” derived by certain named executive officers from the Partnership is listed below:

 

Name		Automobile Use				Employer Contribution to Rhino 401(k) Plan
William Tuorto		$	-			$	10,600
Richard A. Boone			1,476				6,806
Reford C. Hunt			869				7,645
Joseph E. Funk			579				2,943

 

Narrative Discussion of Summary Compensation Table

 

Compensation Philosophy and Objectives

 

We employ a compensation philosophy that emphasizes pay for performance and reflects what the current market dictates. The executive compensation program applicable to the named executive officers is designed to provide a total compensation package that allows us to attract, retain and motivate the executives necessary to manage our business. Our general philosophy and program is guided by several key principles:

 

	●	designing competitive total compensation programs to enhance our ability to attract and retain knowledgeable and experienced senior management level employees;
	●	motivating employees to deliver outstanding financial performance and meet or exceed general and specific business, operational, and individual objectives; and
	●	setting compensation and incentive levels relevant to the market in which the employee provides service.

 

Our executive compensation program is also designed to ensure that a portion of the total compensation made available to the named executive officers is determined by increases in equity value, thereby assuring an alignment of interests between our senior management level employees and our shareholders

 

By accomplishing these objectives, we hope to optimize long-term shareholder value.

 

Compensation Setting Process

 

We do not have a formal compensation committee because we do not active operations other than the Partnership, which has its own compensation committee.

 

The Partnership’s compensation committee seeks to provide a total compensation package designed to drive performance and reward contributions in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies that we require. In the future, the Partnership’s compensation committee may examine the compensation practices of our peer companies and may also review compensation data from the coal industry generally to the extent the competition for executive talent is broader than a group of selected peer companies. To date, the Partnership’s compensation committee has not made any decisions regarding possible benchmarking. In addition, the compensation committee may review and, in certain cases, participate in, various relevant compensation surveys and consult with compensation consultants with respect to determining compensation for the named executive officers. We anticipate that the Partnership’s compensation committee may consider relevant surveys in determining appropriate pay levels in the future. We expect that the Partnership’s President and Chief Executive Officer will provide periodic recommendations to the compensation committee regarding the compensation of the other named executive officers. The Partnership’s compensation committee reviews the compensation structure for the named executive officers of our general partner on an annual basis. During 2016, the compensation committee modified the compensation for certain of the Partnership’s named executive officers, as described under “—Elements of Compensation—Employment Agreements” below.

 

 

Elements of Compensation

 

The principal elements of compensation for our named executive officers are:

 

	●	base salary;
	●	bonus awards;
	●	long-term equity based incentive awards; and
	●	nondiscriminatory welfare and retirement benefits.

 

We believe that a material amount of executive compensation should be tied to our performance, and that a significant portion of the total prospective compensation of each named executive officer should be tied to measurable financial and operational objectives. These objectives may include absolute performance or performance relative to a peer group. During periods when performance meets or exceeds established objectives, the named executive officers should be paid at or above targeted levels, respectively. When our performance does not meet key objectives, incentive award payments, if any, should be less than such targeted levels.

 

The Partnership’s compensation committee seeks to balance awards based on short-term annual results with awards intended to compensate its executives based on the Partnership’s long-term viability and success. We believe that awards under its long-term incentive plan (the “LTIP”) should be structured to further incentivize the named executive officers to perform their duties in a way that will enhance the Partnership’s long-term success.

 

The Partnership’s compensation committee determines the mix of compensation, comprised of both among short-term and long-term compensation and cash and non-cash compensation, included in the compensation packages for each of its named executive officers. We believe that the mix of base salary, bonus awards, awards under the LTIP and the other benefits that are available to the Partnership’s named executive officers effectively accomplish our overall compensation objectives. We believe the elements of compensation provided by the Partnership create competitive compensation opportunities to align and drive employee performance in support of its business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by the Partnership.

 

We follow a similar philosophy with respect to our named executive officers who are not employed by the Partnership. Royal focuses on the acquisition of natural resources assets, including coal, oil, gas and renewable energy, which we seek to acquire at distressed pricing in today’s fragmented energy markets. As a consequence, our board of directors determines the mix of compensation for its named executive officers designed to attract and incentivize high quality individuals who have the necessary skill sets and connections to locate and consummate additional acquisitions in the natural resources markets.

 

 

 

Employment Agreements

 

We and the Partnership have entered into employment agreements with each of the named executive officers. Below is a summary of the employment agreements entered into by us and the Partnership:

 

Royal Energy Resources, Inc.

 

William L. Tuorto. We entered into an employment agreement with Mr. Tuorto dated October 13, 2015 which has the following terms and conditions:

 

Position		Chairman and Chief Executive Officer
Term		36 months
Annual Salary		$350,000
Signing Bonus		$150,000, payable in shares of common stock
Benefits		Health insurance, vacation and participation in any retirement plans.
Change of Control Bonus		20% of Company’s outstanding common and preferred stock in the event of a change of control
Covenants		Confidentiality, non-solicitation of employees and customers

 

Brian Hughs. We entered into an employment agreement with Mr. Hughs dated October 13, 2015 which has the following terms and conditions:

 

Position		Director and Vice President
Term		36 months
Annual Salary		$350,000
Signing Bonus		$150,000, payable in shares of common stock
Benefits		Health insurance, vacation and participation in any retirement plans.
Change of Control Bonus		20% of Company’s outstanding common and preferred stock in the event of a change of control
Covenants		Confidentiality, non-solicitation of employees and customers

 

Douglas C. Holsted. We do not have an employment agreement with Mr. Holsted, our chief financial officer. We compensate his accounting firm on an hourly basis for time he devotes to Company matters. We also paid his accounting firm a non-refundable retainer of $50,000 in fiscal 2015. 

 

Rhino Resource Partners, LP

 

The Partnership’s employment agreements typically provide for a three-year term, which may be terminated earlier in accordance with the terms of the applicable agreement or extended by mutual agreement of the parties. Although our annual bonus program is ultimately a discretionary bonus program, the named executive officers’ employment agreements set forth guidelines and general target amounts for each executive. The Partnership entered into amendments of certain of the named executive officers’ existing employment agreements and entered into new agreements with the named executive officers during the 2016 year. Therefore, the descriptions below focus on the status of the applicable agreements as in effect on December 31, 2016.

 

Effective December 30, 2016, the Partnership entered into an employment agreement with Mr. Tuorto as its Executive Chairman. Mr. Tuorto’s employment agreement provides for an employment term that ends on December 31, 2020 (unless earlier terminated as provided in the agreement or by the mutual agreement of the parties) and an annual base salary of $300,000 per year, which shall be evaluated annually for potential increases. Mr. Tuorto’s employment agreement also provides that he is eligible to receive an annual mandatory bonus of 50% of his annual base salary as well as an annual discretionary bonus of up to 100% of his annual base salary.

 

Effective December 30, 2016, the Partnership entered into an employment agreement with Mr. Boone in connection with his appointment as President and Chief Executive Officer. Mr. Boone’s employment agreement provides for an employment term that ends on December 31, 2018 (unless earlier terminated as provided in the agreement or by the mutual agreement of the parties) and an annual base salary of $300,000 per year, which shall be evaluated annually for potential increases. Mr. Boone’s employment agreement also entitles him to receive an annual mandatory bonus of 10% of his annual base salary as well as an annual discretionary bonus of up to 100% of his annual base salary.

 

 

 

Effective November 16, 2016, the Partnership entered into an amended and restated employment agreement with Mr. Hunt, which is substantially similar to his prior agreement. The amendment and restatement of Mr. Hunt’s employment agreement extends his employment term to December 31, 2018, but otherwise does not materially alter the terms of his prior agreement. Similar to the terms of his prior agreement, Mr. Hunt is entitled under his amended and restated employment agreement to receive an annual discretionary bonus of up to 40% of his annual base salary.

 

The named executive officers of the Partnership are also eligible to participate in our employee benefit programs made available to similarly situated employees. Pursuant to their respective employment agreements, we provide Messrs. Tuorto, Boone and Hunt with automobiles suitable for their duties and responsibilities to us.

 

The severance and change in control benefits provided by the employment agreements with the named executive officers are described below in the section titled “—Potential Payments Upon Termination or Change in Control—Employment Agreements.” The employment agreements also contain certain confidentiality, noncompetition, and other restrictive covenants, which are also described in the section titled “—Potential Payments Upon Termination or Change in Control—Employment Agreement.”

 

Unit and Phantom Unit Awards

 

Certain named executives of the Partnership received discretionary awards of fully vested Rhino units in 2016. Certain named executives received discretionary awards of phantom units in 2015 in respect of fiscal 2014 performance. These phantom unit awards were designed to vest in equal annual installments over a 36-month period (i.e., approximately 33.3% vest at each annual anniversary of the date of grant), provided the named executive officer remained an employee continuously from the date of grant through the applicable vesting date. The phantom units were designed to become fully vested upon a change in control or in the event that the named executive officer’s employment was terminated due to disability or death. In addition, if the named executive officer’s employment was terminated by the Partnership without cause or by the executive for good reason, the vesting of those phantom units scheduled to vest in the 12 month period following such termination would have been accelerated to the officer’s termination date. While a named executive officer holds unvested phantom units, he is entitled to receive DER credits that will be paid in cash upon vesting of the associated phantom units (and will be forfeited at the same time the associated phantom units are forfeited). Each of the unvested phantom units held by the named executive officers during the 2016 became accelerated in connection with our acquisition of the Partnership’s general partner in March 2016.

 

Outstanding Equity Awards at Fiscal Year End

 

Neither we nor the Partnership had any outstanding equity awards as of December 31, 2016.

 

Potential Payments Upon Termination or Change in Control

 

We and the Partnership have employment agreements with each of the named executive officers employed by us that contain provisions regarding payments to be made to such individuals upon an involuntary termination of their employment by us without “cause” or their resignation for “good reason.” The employment agreements are described in greater detail below and in the section above titled “—Compensation Discussion and Analysis—Elements of Compensation—Employment Agreements.”

 

Employment Agreements

 

Royal Energy Resources, Inc.

 

Under our employment agreements with Messrs. Tuorto, Hughs and Phillips, if the employment of the executive is terminated by us for “for cause,” or by the executive voluntarily without “good reason,” then the executive, as applicable, will be entitled to receive his earned but unpaid base salary, payment with respect to accrued but unpaid vacation days, all benefits accrued and vested under any of our benefit plans, and reimbursement for any properly incurred business expenses (collectively, the “accrued obligations”).

 

In addition to the foregoing, in the event the employment of Messrs. Tuorto, and Hughs is terminated by us without “cause,” by the executive for “good reason,” or as a result of a “change of control,” Messrs. Tuorto and Hughs shall receive (a) severance payments equal to three years base salary, (b) medical coverage to the same extent as it provides to other executive officers for the lesser of two years or the date the officer receives medical coverage through a different employer, and (c) any unvested options, warrants, restricted stock awards or contingent stock rights shall vest.

 

 

 

Messrs. Tuorto, Hughs, and Phillips are subject to certain confidentiality and non-solicitation provisions contained in their employment agreements. The confidentiality covenants expire two years after the officer’s employment terminates, unless the confidential information is a trade secret under applicable law, in which case the obligation runs in perpetuity. Messrs. Tuorto, Hughs, and Phillips are also subject to non-solicitation provisions that prevent from soliciting any employees or independent contractors of us to terminate their services relationship, and prevent them from soliciting any customer of us to terminate their relationship with us or in any way reduce the amount of business they do with us. The non-solicitation of employee covenant expires two years after the officer’s employment with us, and the non-solicitation of customers covenant expires five years after the officer’s employment with us.

 

For purposes of the employment agreements with Messrs. Tuorto, Hughs, and Phillips, the terms listed below have been defined as follows:

 

	●	“for cause” means the officer (a) fails or refuses in any material respect to perform any duties, consistent with his position or those which may reasonably be assigned to him by the Board or materially violates company policy or procedure; (b) is grossly negligent in the performance of his duties hereunder; (c) commits of any act of fraud, willful misappropriation of funds, embezzlement or dishonesty with respect to the Company; (d) Is convicted of a felony or other criminal violation, which, in the reasonable judgment of the Company, could materially impair the Company from substantially meeting its business objectives; (e) Engages in any other intentional misconduct adversely affecting the business or affairs of the Company in a material manner; or (f) dies or is disabled for three consecutive months in any calendar year to such an extent that the Executive is unable to perform substantially all of his essential duties for that time.
	●	“for good cause” means (a) any removal of the executive from his position without his being appointed to a comparable or higher position in the Company; (b) the assignment to the Executive of duties materially inconsistent with the status of a person with his title, and the Company fails to rescind such assignment within thirty (30) days following receipt of written notice to the Board of Directors of the Company from executive; (c) any requirement that the executive perform his duties from any location other than Charleston, South Carolina.

 

Rhino Resource Partners, LP

 

Under the Partnership’s employment agreements with Messrs. Tuorto, Boone and Hunt, if the employment of the executive is terminated by us for “cause,” by the executive voluntarily without “good reason,” or due to the executive’s “disability,” then the executive, as applicable, will be entitled to receive his earned but unpaid base salary, payment with respect to accrued but unpaid vacation days, all benefits accrued and vested under any of our benefit plans, and reimbursement for any properly incurred business expenses (collectively, the “accrued obligations”). In addition to the foregoing, in the event the employment of Messrs. Tuorto or Boone is terminated by the Partnership without “cause” or by the executive for “good reason,” Messrs. Tuorto and Boone shall receive their base salary for the period from termination through the expiration of their respective employment agreements, subject to the executive’s timely execution and delivery (and non-revocation) of a release agreement for our benefit. In the event of the death of Mr. Tuorto or Boone, their estate will be entitled to receive the accrued obligations and a pro-rated annual discretionary bonus.

 

Messrs. Tuorto and Boone are subject to certain confidentiality, non-compete and non-solicitation provisions contained in their employment agreements. The confidentiality covenants are perpetual, while the non-compete and non-solicitation covenants apply during the term of their employment agreements and for one year (two years for non-solicitation) following Messrs. Tuorto’s and Boone’s termination for any reason. Mr. Tuorto’s employment agreement acknowledges his position and employment with Royal and specifically excepts his non-compete provision as it relates to Royal and its affiliates.

 

For purposes of the employment agreements with Messrs. Tuorto and Boone, the terms listed below have been defined as follows:

 

●

“cause” means (a) failure of the executive to perform substantially his duties (other than a failure due to a “disability”) within ten days after written notice from us, (b) executive’s conviction of, or plea of guilty or no contest to a misdemeanor involving dishonesty or moral turpitude or any felony, (c) executive engaging in any illegal conduct, gross misconduct, or other material breach of the employment agreement that is materially and demonstratively injurious to us or (d) executive engaging in any act of dishonesty or fraud involving us or any of our affiliates.

 

 

	●	“disability” means the inability of executive to perform his normal duties as a result of a physical or mental injury or ailment for any consecutive 45 day period or for 90 days (whether or not consecutive) during any 365 day period.
	●	“good reason” means, without the executive’s express written consent, (a) the assignment to the executive of duties inconsistent in any material respect with those of the executive’s position (including status, office, title, and reporting requirements), or any other diminution in any material respect in such position, authority, duties or responsibilities, (b) a reduction in base salary, (c) a reduction in the executive’s welfare, qualified retirement plan or paid time off benefits, other than a reduction as a result of a general change in any such plan or (d) any purported termination of the executive’s employment under the employment agreement other than for “cause,” death or “disability”. The executive must give notice of the event alleged to constitute “good reason” within six months of its occurrence and we have 30 days upon receipt of the notice to cure the alleged “good reason” event.

 

Under the employment agreement with Mr. Hunt, if his employment is terminated by the Partnership without “cause” or if Mr. Hunt resigns for “good reason”, which such term has the same meaning as described above with respect to the employment agreements with Messrs. Tuorto and Boone, Mr. Hunt is entitled to receive a lump sum payment equal to twelve months’ worth of his base salary and continued family health insurance, at the same premium cost as was in effect on the date of termination, until the earlier of twelve months or the date he becomes covered under a new employer’s plan, subject to the executive’s timely execution and delivery (and non-revocation) of a release agreement for our benefit. Mr. Hunt is subject to certain confidentiality, non-compete and non-solicitation provisions contained in his employment agreement. The confidentiality covenants are perpetual, while the non-compete covenants apply during the terms of his employment agreements and for one year following termination of employment. The non-solicitation period runs until the end of the six month period following the end of the applicable non-compete period. In the event of the death of Mr. Hunt, his estate will be entitled to receive the accrued obligations and a pro-rated annual discretionary bonus.

 

For purposes of the agreements with Mr. Hunt, “cause” means (a) the commission by executive of an act of dishonesty or fraud against us, (b) a breach of the executive’s obligations under the employment agreement and failure to cure such breach within ten days after written notice from us, (c) executive is indicted for or convicted of a crime involving moral turpitude or (d) executive materially fails or neglects to diligently perform his duties and “disability”.

 

The Partnership entered into an amended employment arrangement with Mr. Funk in August 2016 in connection with the announcement that he would be transitioning out of his role as Chief Executive Officer of the Partnership following the sale of its Elk Horn coal leasing business. In the event that the sale had not occurred, the amendment to his original employment agreement described below would not have become effective. The amended agreement provided that in exchange for all compensation under his previous EBITDA-based bonus arrangement and for agreeing to shorten his employment agreement, Mr. Funk would receive total compensation paid on or prior to December 31, 2016 of $465,000. The payment consisted of $150,000 in cash relating directly to the sale, and $115,000 in salary payments. The remaining $200,000 was to be paid in our common units (based on a common unit price of $2.35, the closing price on August 22, 2016) or cash, at our option, with an adequate price guarantee to ensure the total cash received by Mr. Funk to not be less than $200,000. The Partnership paid this amount to Mr. Funk in the form of cash, and he received a $200,000 payment on December 23, 2016.

 

In connection with Mr. Funk’s continuation of services with us as a special advisor following his resignation as an executive officer, the Partnership will provide him with compensation at a rate of $30,000 per month through March 31, 2017. Should the Partnership terminate Mr. Funk’s services prior to March 31, 2017, Mr. Funk will be entitled to a termination payment of $15,000 cash paid immediately. Mr. Funk’s amended agreement allows him to enter into an employment and or consulting agreement with Elk Horn, and releases him from any noncompetition obligations that were contained in Mr. Funk’s previous amended employment agreement.

 

LTIP Phantom Unit Awards

 

Messrs. Boone and Hunt have periodically held awards of phantom units as previously described in the section above titled “—Narrative Discussion of Summary Compensation Table—Phantom Unit Awards,” although as of December 31, 2016 none of the Partnership’s named executive officers held outstanding phantom unit awards.

 

The Partnership’s phantom units are typically designed to accelerate vesting in full upon a “change of control” or the named executive officer’s termination due to death or “disability.” In addition, upon a termination of the executive by the Partnership without cause or by the executive for a good reason, the vesting of those phantom units scheduled to vest in the 12-month period following such termination will be accelerated to such termination date. For this purpose, “good reason” and “cause” have the meanings set forth in the respective employment agreements of the named executive officers described above. A “change of control” will be deemed to have occurred if: (i) any person or group, our general partner or an affiliate of either, becomes the owner of more than 50% of the voting power of the voting securities of either the Partnership or its general partner; or (ii) upon the sale or other disposition by either us or our general partner of all or substantially all of its assets, whether in a single or series of related transactions, to one or more parties, our general partner or an affiliate of either. A “disability” is any illness or injury for which the named executive officer will be entitled to benefits under the long-term disability plan of our general partner.

 

 

Director Compensation

 

We currently do not pay any compensation to our directors. However, we anticipate developing a board compensation policy that is consistent with that provided to board members of other companies within our industry, in order to attract qualified candidates to our board.

 

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

 

The following table sets forth certain information, as of March 20, 2017, with respect to the beneficial ownership of our common stock by (i) all of our directors, (ii) each of our executive officers named in the Summary Compensation Table, (iii) all of our directors and named executive officers as a group, and (iv) all persons known to us to be the beneficial owner of more than five percent (5%) of any class of our voting securities.

 

		Common Stock								Series A Preferred Stock								Total Votes
Name and Address of Beneficial Owner		Amount and Nature of Beneficial Ownership				Percent of Class (1)				Amount and Nature of Beneficial Ownership				Percent of Class (1)				Aggregate No. of Votes (1)				% of Total Votes (1)
William L. Tuorto (2)(5)			8,010,884				46.6	%			51,000				100.0	%			28,183,517				75.4	%
William King and Paulette King Trust 10925 US Highway 60 Canadian, TX 79014			1,361,429				7.9	%			-				0.0	%			1,361,429				3.6	%
DWCF, Ltd. 3988 FM 2933 McKinney, TX 75071			1,191,440				6.9	%			-				0.0	%			1,191,440				3.2	%
Brian Hughs (3)(5)			909,810				5.3	%			-				0.0	%			909,810				2.4	%
Douglas C. Holsted (4)(5)			48,397				0.3	%			-				0.0	%			48,397				0.1	%
Ronald Phillips (5)			2,848				0	%			-				0.0	%			2,848				0	%
All Officers and Directors as a Group			8,971,939				52.2	%			51,000				100.0	%			29,144,572				78.0	%

 

(1)	Based upon 17,184,095 shares of common stock issued and outstanding as of March 20, 2017, each of which is entitled to one vote per share, and 51,000 shares of Series A Preferred Stock issued and outstanding as of March 30, 2017, which are entitled to 54% of the votes on any matter upon which shareholders are entitled to vote. Total votes are 37,356,728.
(2)	Mr. Tuorto’s ownership of common stock consists of 822,324 shares owned outright, 7,188,560 shares owned by E-Starts Money Co., a corporation owned by Mr. Tuorto, and 51,000 shares which he has the right to acquire upon the conversion of shares of Series A Preferred Stock owned by him.

 

 

(3)	Mr. Hughs’ ownership consists of 909,810 shares of common stock owned outright.
(4)	Mr. Holsted’s ownership consists of 48,397 shares of common stock owned by Wastech, Inc., which he has the shared power to vote and dispose of by virtue of being an officer and director of Wastech, Inc.
(5)	The address for Messrs. Tuorto, Holsted, Hughs and Phillips is 56 Broad Street, Suite 2, Charleston, SC 29401.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

The following table summarizes certain information as of December 31, 2016, with respect to compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance:

 

Plan category		Number of securities to be issued upon exercise of outstanding options, warrants and rights				Weighted average exercise price of outstanding options, warrants and rights				Number of securities remaining available for future issuance
Royal 2015 Employee, Consultant and Advisor Stock Compensation Plan (1)			—				—
Royal 2015 Stock Option Plan (1)			—				—				876,309
Rhino Lon-term Incentive Plan (2)			—				n/a	(2)			12,996
			—				—				876,309

 

	(1)	The Royal Energy Resources, Inc. 2015 Employee, Consultant and Advisor Stock Compensation Plan and the Royal Energy Resources 2015 Stock Option Plan (“Plans”) were filed on July 31, 2015 and reserves 1,000,000 shares for Awards under each Plan. The Company’s Compensation Committee is designated to administer the Plans at the direction of the Board of Directors.
	(2)	Adopted by board of directors of the partnership’s in connection with its IPO. To date, only phantom and restricted and unrestricted units have been granted under the Long-Term Incentive Plan. For more information relating to the Partnership’s Long-Term Incentive Plan and the unit awards granted thereunder, please see Note 18 of the consolidated financial statements included elsewhere in this annual report.

 

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

 

Transactions Involving Royal Only

 

Transactions Involving Jacob Roth

 

Prior to March 6, 2015, Jacob Roth was chief executive officer and principal shareholder.

 

From time to time, Mr. Roth made loans and advances to us. Due to related party at August 31, 2014 amounted to $8,342.

 

Effective January 31, 2015, we entered into a Subsidiaries Option Agreement with Mr. Roth. Under the Subsidiaries Option Agreement, we conveyed all of our assets to two subsidiaries, to the extent any assets were not already owned by the subsidiaries. The Subsidiaries Option Agreement also granted Mr. Roth an option to acquire the subsidiaries for 49,000 shares of Series A Preferred Stock owned by Mr. Roth. The Subsidiaries Option Agreement also granted us a put option to acquire 49,000 shares of Series A Preferred Stock owned by Mr. Roth in consideration for the subsidiaries. Both options could be exercised at any time within 45 days after closing of the stock purchase agreement among Mr. Roth, E-Starts Money Co. and William Tuorto. On April 20, 2015, we exercised our option under the Subsidiaries Option Agreement, which resulted in us conveying the subsidiaries to Mr. Roth in return for the cancellation of 49,000 shares of Series A Preferred Stock.

 

On March 6, 2015, E-Starts Money Co. (“E-Starts”) acquired an aggregate of 7,188,560 shares of our common stock from two holders. At the same time, William Tuorto acquired 810,316 shares of common stock from Mr. Roth, and 51,000 shares of Mr. Roth’s Series A Preferred Stock. Mr. Tuorto controls E-Starts. As a result, Mr. Tuorto became the beneficial owner of 7,998.876 shares of common stock (representing 92.3% of the outstanding common stock at that time) and 51% of the outstanding shares of Series A Preferred Stock. In connection with these transactions: (i) Frimet Taub resigned as a director and from all positions as an officer, employee, or independent contractor of us; (ii) Mr. Tuorto was appointed to the board seat vacated by Ms. Taub; (iii) Mr. Roth resigned as chairman of the board and Mr. Tuorto was appointed chairman of the board; (iv) Mr. Roth resigned as the Chief Executive Officer and Chief Financial Officer, and any other position as an officer, employee or independent contractor of us, and Mr. Tuorto was appointed as the Chief Executive Officer, Interim Chief Financial Officer, Secretary and Treasurer; and (v) Mr. Roth resigned as a director of us, provided that his resignation was not effective until the close of business on the 10th day after we distributed an information statement to its shareholders in accordance with SEC Rule 14f-1.

 

 

Transactions since Mr. Roth’s Resignation

 

E-Starts Money Co. Loans

 

On March 6, 2015, we borrowed $203,593 from E-Starts pursuant to a demand promissory date, which bears interest at six percent per annum. We used the proceeds to repay all of our indebtedness at the time.

 

On June 11, 2015, we borrowed an additional $200,000 from E-Starts Money Co. pursuant to a non-interest bearing demand promissory note. We used the proceeds to fund the signing bonus of Ian Ganzer’s Employment Agreement with us, as well as additional costs associated with the Blue Grove and GS Energy Agreements.

 

On September 22, 2016, we borrowed $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note and on December 8, 2016, we borrowed an additional $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note. The total amount owed to E-Starts at December 31, 2016 and December 31, 2015 was $503,593 and $403,593 respectively, plus accrued interest.

 

Blaze Minerals, LLC Acquisition

 

On April 17, 2015, we closed on the acquisition of all of the membership units of Blaze Minerals, LLC (“Blaze”) from Wastech, Inc. for 2,803,621 shares of common stock. One of the officers and directors of Wastech is the father of Mr. Tuorto. Douglas C. Holsted, our Chief Financial Officer, is also a Director of Wastech.

 

Wellston Transactions

 

On May 14, 2015, we entered into an Option Agreement to acquire substantially all of the assets of Wellston Coal, LLC (“Wellston”) for 500,000 shares of our common stock. The Option Agreement originally terminated on September 1, 2015, but was later extended to December 31, 2016. Wellston owned approximately 1,600 acres of surface and 2,200 acres of mineral rights in McDowell County, West Virginia (the “Wellston Property”). We planned to close on the acquisition of the Wellston Property upon satisfactory completion of due diligence. Pursuant to the Option Agreement, pending the closing of the Wellston Property, we agreed to loan Wellston up to $500,000 from time to time. The loan was pursuant to a Promissory Note bearing interest at 12% per annum, due and payable at the expiration of the Option Agreement, and collateralized by a Deed of Trust on the Wellston Property. We ultimately loaned Wellston $53,000. Our President and Secretary, Ronald Phillips, owns a minority interest in Wellston, and is the manager of Wellston. On September 13, 2016, Wellston sold its assets to an unrelated third party, and we received a royalty of $1 per ton on the first 250,000 tons of coal mined from the property in consideration for a release of our lien on Wellston’s assets, which satisfied the loan to Wellston in full.

 

Blue Grove/GS Energy Transactions

 

On June 10, 2015, we acquired Blue Grove in exchange for 350,000 shares of our common stock. Blue Grove was owned 50% by Ian Ganzer, our chief operating officer, and 50% by Gary Ganzer, Ian Ganzer’s father (the “Members”). Simultaneous with our acquisition of Blue Grove, Blue Grove entered into an operator agreement with GS Energy, LLC, under which Blue Grove has an exclusive right to mine the coal properties of GS Energy for a two year period. During the term of the Operator Agreement, Blue Grove is entitled to all revenues from the sale of coal mined from GS Energy’s properties, and is responsible for all costs associated with the mining of the properties or the properties themselves, including operating costs, lease, rental or royalty payments, insurance and bonding costs, property taxes, licensing costs, etc. Simultaneous with the acquisition of Blue Grove, Blue Grove also entered into a Management Agreement with Black Oak Resources, LLC (“Black Oak”), a company owned by the Members. Under the Management Agreement, Blue Grove subcontracted all of its responsibilities under the Management Agreement with GS Energy to Black Oak. In consideration, Black Oak was entitled to 75% of all net profits generated by the mining of the coal properties of GS Energy. Subsequently, the agreement with Black Oak was amended to provide that Black Oak was entitled to 100% of the first $400,000 and 50% of the next $1,000,000, for a maximum of $900,000 of net profits generated by the mining of the coal properties of GS Energy.

 

 

The Members have an option to purchase the membership interests in Blue Grove from us. If exercised between ten and sixteen months after closing, the exercise price of the option is $50,000 less any dividends received on the shares of common stock issued in the acquisition, plus 90% of the shares issued to acquire Blue Grove. If exercised between sixteen and twenty-four months after closing, the exercise price of the option is 80% of the shares issued to acquire Blue Grove. The call option will terminate when (i) the parties agree it has terminated, (ii) when the Company pays the Members at least $1,900,000 to acquire their shares of common stock, or (iii) when a comparable option granted to the Members with respect to common stock issued to them to acquire GS Energy is terminated. We also have an option to sell the Blue Grove membership interests back to the Members. If exercised between ten and sixteen months after closing, the exercise price of our option is 90% of the common stock issued to the Members to acquire Blue Grove. If exercised between sixteen and twenty-four months after closing, the exercise price of our option is 80% of the common stock issued to the Members to acquire Blue Grove.

 

On December 23, 2015, the Company and the Members entered into an Amendment to Securities Exchange Agreement (“Amendment”) originally entered into on June 8, 2015. Pursuant to the Amendment, the consideration for the acquisition of Blue Grove was reduced from 350,000 shares of our common stock to 10,000 shares.

 

 On June 10, 2015, we also entered into a Securities Purchase Agreement to acquire GS Energy for shares of common stock with a market value of $9,600,000 provided that we would be required to issue a minimum of 1,250,000 shares of our common stock and not more than a maximum of 1,750,000 shares. Closing under the Securities Exchange Agreement was subject to the successful completion of a financial audit of GS Energy and due diligence. GS Energy owns and leases approximately 6,000 net acres of coal and coalbed methane mineral rights and a surface coal mine in McDowell County, West Virginia. In December 2015, the Securities Exchange Agreement to acquire GS Energy was voluntarily terminated by the parties. We are in further negotiations to acquire GS Energy.

 

Miscellaneous Amounts Due Related Parties

 

E-Starts, in addition to the four notes described above, advanced money to us for use in paying certain of our obligations, and is owed accrued interest on one of the notes described above. In addition, we have advanced funds to GS Energy, LLC and Gary and Ian Ganzer, the owners of GS Energy, LLC, from time to time. The details of the due to related party account are summarized as follows:

 

		December 31, 2016				December 31, 2015
		(thousands)
Due to E-Starts Money Co
Expense advances		$	11			$	11
Accrued interest			22				10
			33				21
Due to GS Energy, LLC			18				18
Due to Gary and Ian Ganzer			20				-
		$	71			$	39

 

Transactions Involving Rhino 

 

Acquisition of Control of Rhino

 

On January 21, 2016, a definitive agreement was completed between us and Wexford Capital, LP, and certain of its affiliates (collectively, “Wexford”) under which we acquired 676,912 common units from Wexford. Pursuant to the definitive agreement, on March 17, 2016, we acquired all of the issued and outstanding membership interests of Rhino GP LLC, the Partnership’s general partner, as well as 945,525 of the Partnership’s issued and outstanding subordinated units from Wexford. The general partner owns the general partner interest in the Partnership as well as our incentive distribution rights. On March 21, 2016, we acquired 6,000,000 common units in the Partnership in a private placement.

 

 

Subsequent to acquiring control of the Partnership, we appointed William Tuorto, Douglas Holsted, Ronald Phillips, Ian Ganzer and Brian Hughs, each of whom is an officer and/or director of us, as directors of the general partner. Mr. Ganzer resigned as a director of the Partnership in September 13, 2016.

 

Prior to the consummation of the sale of our general partner by Wexford, principals of Wexford Capital, including Mark D. Zand, Philip Braunstein, Arthur H. Amron and Kenneth A. Rubin, each a director of our general partner, owned membership interests in our general partner.

 

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. Such terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms which could have been obtained from unaffiliated third parties.

 

Registration Rights

 

Under the Partnership’s partnership agreement, as amended and restated, it has agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by its general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of the general partner. The Partnership is obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

 

Securities Purchase Agreement

 

On March 21, 2016, we entered into a Securities Purchase Agreement with the Partnership under which we purchased 6,000,000 of common units of the Partnership in a private placement at $1.50 per common unit for an aggregate purchase price of $9.0 million. We paid $2.0 million in cash and delivered a Promissory Note payable to the Partnership in the amount of $7.0 million (the “Rhino Promissory Note”). On May 13, 2016 and September 30, 2016, we paid $3.0 million and $2.0 million, respectively, on the Rhino Promissory Note. The final installment on the Rhino Promissory Note of $2.0 million was due on or before December 31, 2016. However, on December 30, 2016, we modified the Securities Purchase Agreement with the Partnership to extend the due date of the final $2.0 million payment to December 31, 2018. Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.” 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 the final installment, the Partnership has the option to rescind our purchase of 1,333,333 common units and the applicable installment will not be payable (the “Rescission Right”). If the Partnership fails to exercise the Rescission Right, the Partnership has the option to repurchase 1,333,333 of our common units at $3.00 per common unit from us. The Repurchase Option terminates on December 31, 2017. Our obligation to pay any installment of the Rhino Promissory Note is subject to certain conditions, including that the Partnership 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 installment due date, Royal has the right to cancel the remaining unpaid balance of the Rhino Promissory Note in exchange for the surrender of such number of common units equal to the principal balance of the Rhino Promissory Note divided by $1.50.

 

 

Pursuant to the Securities Purchase Agreement, on March 21, 2016, we and the Partnership entered into a registration rights agreement. The registration rights agreement grants us piggyback registration rights under certain circumstances with respect to the common units issued to us pursuant to the Securities Purchase Agreement.

 

Option Agreement

 

On December 30, 2016, we entered into the Option Agreement with the Partnership, Rhino Holdings, and the Partnership’s general partner. Upon execution of the Option Agreement, the Partnership received the Call Option from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy that is owned by investment partnerships managed by Yorktown, which currently represent approximately 97% of the outstanding common stock of Armstrong Energy. Armstrong Energy, Inc. is a coal producing company with approximately 554 million tons of proven and probable reserves and six mines located in the Illinois Basin in western Kentucky as of September 30, 2016. The Option Agreement stipulates that the Partnership can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting the Partnership the Call Option, the Partnership issued the Call Option Premium Units to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement stipulates the Partnership can exercise the Call Option and purchase the common stock of Armstrong Energy in exchange for a number of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings owning 51% of the fully diluted common units of the Partnership. The purchase of Armstrong Energy through the exercise of the Call Option would also require us to transfer a 51% ownership interest in the general partner of the Partnership to Rhino Holdings. The Partnership’s ability to exercise the Call Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the amendment of our revolving credit facility to permit the acquisition of Armstrong Energy. The percentage ownership of Armstrong Energy represented by the Armstrong Shares as of the date the Call Option is exercised is subject to dilution based upon the terms under which Armstrong Energy restructures its indebtedness, the terms of which have not been determined yet.

 

The Option Agreement also contains the Put Option granted by the Partnership to Rhino Holdings whereby Rhino Holdings has the right, but not the obligation, to cause the Partnership to purchase substantially all of the outstanding common stock of Armstrong Energy from Rhino Holdings under the same terms and conditions discussed above for the Call Option. The exercise of the Put Option is dependent upon (i) the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the termination and repayment of any outstanding balance under our revolving credit facility. In the event either the Partnership or Rhino GP fail to perform their obligations in the event Rhino Holdings exercises the Put Option, then Rhino Holdings and the Partnership each have the right to terminate the Option Agreement, in which event no party thereto shall have any liability to any other party under the Option Agreement, although Rhino Holdings shall be allowed to retain the Call Option Premium Units.

 

The Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the Seventh Amendment (defined below) and the GP Amendment (defined below). The Partnership has entered into a non-disclosure agreement with Armstrong Energy under which it has inspection rights with regard to the books, records and operations of Armstrong Energy, and the Option Agreement provides that those rights shall continue until the Call Option or Put Option are exercised or expire. Upon the request by Rhino Holdings, the Partnership will also enter into a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding common units.

 

Pursuant to the Option Agreement, the Second Amended and Restated Limited Liability Company Agreement of the Partnership’s general partner was amended. Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of the general partner as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director. Rhino Holdings has the right to appoint two members to the board of directors of the general partner for as long as it continues to own 20% of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent to any delegation of authority to any committee of the board of the general partner. Upon the exercise of the Call Option or the Put Option, the Second Amended and Restated Limited Liability Company Agreement of our general partner, as amended, will be further amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors and that the remaining director will be the chief executive officer of the general partner unless agreed otherwise.

 

The Option Agreement superseded and terminated the equity exchange agreement entered into on September 30, 2016 by and among us, Rhino Holdings, an entity wholly owned by certain investment partnerships managed by Yorktown, and the general partner.

 

Series A Preferred Unit Purchase Agreement

 

On December 30, 2016, the Partnership entered into the Series A Preferred Unit Purchase Agreement with Weston, an entity wholly owned by certain investment partnerships managed by Yorktown, and us. Under the Preferred Unit Agreement, Weston and us agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred units representing limited partner interests in the Partnership at a price of $10.00 per Series A preferred unit. The Series A preferred units have the preferences, rights and obligations set forth in the Fourth Amended and Restated Agreement of Limited Partnership, which is described below. In exchange for the Series A preferred units, Weston and us paid cash of $11.0 million and $2.0 million, respectively, and Weston assigned to the Partnership a promissory note in the principal amount of $2.0 million due by us to Weston dated September 30, 2016 (the “Weston Promissory Note”). Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”

 

 

The Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for as long as the Series A preferred units are outstanding, we will cause CAM Mining, one of the Partnership’s subsidiaries, to conduct its business in the ordinary course consistent with past practice and use reasonable best efforts to maintain and preserve intact its current organization, business and franchise and to preserve the rights, franchises, goodwill and relationships of its employees, customers, lenders, suppliers, regulators and others having business relationships with CAM Mining.

 

The Preferred Unit Agreement stipulates that upon the request of the holder of the majority of the Partnership’s common units following their conversion from Series A preferred units, as outlined in our partnership agreement, the Partnership will enter into a registration rights agreement with such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights.

 

On January 27, 2017, we sold 100,000 of our Series A preferred units to Weston and the other 100,000 Series A preferred units to another third party.

 

Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note

 

On December 30, 2016, we and the Partnership entered into a letter agreement whereby the parties agreed to extend the maturity dates of the Weston Promissory Note and the final installment payment of the Rhino Promissory Note to December 31, 2018. The letter agreement further provides that the aggregate $4.0 million balance of the Weston Promissory Note and Rhino Promissory Note may be converted at our option into a number of shares of our common stock equal to the outstanding balance multiplied by seventy-five percent (75%) of the volume-weighted average closing price of our common stock for the 90 days preceding the date of conversion (“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50.

 

Sturgeon Acquisitions LLC

 

In September 2014, the Partnership made an initial investment of $5.0 million in a new joint venture, 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 recorded our proportionate portion of the operating (loss)/income for this investment during 2016 and 2015 of approximately ($0.2) million and $0.3 million, respectively.

 

Review, Approval and Ratification of Related Party Transactions

 

The board of directors has responsibility for establishing and maintaining guidelines relating to any related party transactions between us and any of our officers or directors. We do not currently have any written guidelines for the board of directors which will set forth the requirements for review and approval of any related party transactions, but we plan to adopt such guidelines once we add independent board members.

 

Director Independence

 

Our common stock is currently quoted on the OTCQB.  Since the OTCQB does not have its own rules for director independence, we use the definition of independence established by the NYSE Amex (formerly the American Stock Exchange).  Under applicable NYSE Amex rules, a director will only qualify as an “independent director” if, in the opinion of our Board, that person does not have a relationship which would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.

 

We periodically review the independence of each director. Pursuant to this review, our directors and officers, on an annual basis, are required to complete and forward to the Corporate Secretary a detailed questionnaire to determine if there are any transactions or relationships between any of the directors or officers (including immediate family and affiliates) and us. If any transactions or relationships exist, we then consider whether such transactions or relationships are inconsistent with a determination that the director is independent. As this time, we do not have any independent directors.

 

Conflicts Relating to Officers and Directors

 

To date, we do not believe that there are any conflicts of interest involving our officers or directors, other than as disclosed above. With respect to transactions involving real or apparent conflicts of interest, we have not adopted any formal policies or procedures. In the absence of any formal policies and procedures regarding conflicts, we intend to follow the provisions of Delaware corporate law regarding conflicts, which generally requires that: (i) the fact of the relationship or interest giving rise to the potential conflict be disclosed or known to the directors who authorize or approve the transaction prior to such authorization or approval, (ii) the transaction be approved by a majority of our disinterested outside directors, and (iii) the transaction be fair and reasonable to us at the time it is authorized or approved by our directors.

 

 

Item 14. Principal Accounting Fees and Services.

 

The following table presents fees for professional services provided by Brown Edwards & Company, L.L.P. and Paritz & Company, P.A. for the fiscal years December 31, 2016 and August 31, 2015, respectively:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Audit fees		$	615			$	29
Audit related fees			-				-
Tax fees (1)			-				-
Total		$	615			$	29

 

(1)

“Tax fees” are related to general tax advisory services.

 

PART IV

 

Item 15. Exhibits, Financial Statement Schedules.

 

(a)(1) Financial Statements

 

See “Index to the Consolidated Financial Statements” set forth on Page F-1.

 

(2) Financial Statement Schedules

 

All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

 

 

(3) Exhibits

 

EXHIBIT LIST

 

Exhibit  Number		Description		Filer
2.1**		Membership Transfer Agreement between Rhino Eastern JV Holding Company LLC, Rhino Energy WV LLC, and Rhino Eastern LLC dated December 31, 2014 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-34892) filed on January 7, 2015)		Rhino
2.2**		Membership Interest Purchase Agreement, dated August 22, 2016, by and among Rhino Energy LLC and Elk Horn Coal Acquisition LLC (incorporated by reference to Exhibit 2.2 of the Quarterly Report on Form 10-Q (File No. 001-34892), filed on November 10, 2016)		Rhino
2.3		Securities Exchange Agreement dated effective April 13, 2015 by and between Royal Energy Resources, Inc. and Wastech, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K (File No. 000-52547) filed April 21, 2015)		Royal
3.1		Amended and Restated Certificate of Incorporation dated July 29, 2016 (incorporated by reference from the Current Report on Form 8-K (File No. 000-52547) filed on July 29, 2016)		Royal
3.2		Amended and Restated Bylaws dated July 29, 2016 (incorporated by reference from the Current Report on Form 8-K (File No. 000-52547) filed on July 29, 2016)		Royal
3.3*		Certificate of Amendment to Certificate of Incorporation of Royal Energy Resources, Inc. dated March 13, 2017.		Royal
3.4		Certificate of Limited Partnership of Rhino Resource Partners LP, incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on May 5, 2010		Rhino
3.5		Fourth Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated as of December 30, 2016 (incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K (File No. 000-52547) filed on January 6, 2017)		Royal
4.1		Registration Rights Agreement, dated as of October 5, 2010, by and between Rhino Resource Partners LP and Rhino Energy Holdings LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 8, 2010)		Rhino
4.2		Registration Rights Agreement, dated as of March 21, 2016, by and between Rhino Resource Partners LP and Royal Energy Resources, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on March 23, 2016)		Rhino
10.1†		Rhino Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 2010)		Rhino
10.2†		Form of Long-Term Incentive Plan Grant Agreement—Phantom Units with DERs (incorporated by reference to Exhibit 10.12 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010)		Rhino

 

 

Exhibit   Number		Description		Filer
10.3†		Form of Long-Term Incentive Plan Grant Agreement—Unit Awards and Restricted Units (Directors who are not Principals of Wexford) (incorporated by reference to Exhibit 10.22 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010)		Rhino
10.4†		Form of Long-Term Incentive Plan Grant Agreement—Unit Awards and Restricted Units (Directors who are Principals of Wexford) (incorporated by reference to Exhibit 10.23 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010)		Rhino
10.5†		Amended and Restated Employment Agreement of Joseph E. Funk effective as of November 14, 2014 (incorporated by reference to Exhibit 10.5 of the 2015 Annual Report on Form 10-K (File No. 001-34892), filed on March 25, 2016)		Rhino
10.6†		Amended and Restated Employment Agreement of Richard A. Boone effective December 30, 2016 (incorporated by reference to Exhibit 10.6 of the 2016 Annual Report on Form 10-K (File No. 001-34892), filed on March 24, 2017)		Rhino
10.7†		Amended and Restated Employment Agreement of Reford C. Hunt effective September 1, 2014 (incorporated by reference to Exhibit 10.7 of the 2016 Annual Report on Form 10-K (File No. 001-34892), filed on March 24, 2017)		Rhino
10.8		Amended and Restated Credit Agreement, dated July 29, 2011 by and among Rhino Energy LLC, 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 guarantors and lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current report on Form 8-K (File No. 001-34892), filed on August 4, 2011)		Rhino
10.9		First Amendment to Amended and Restated Credit Agreement, dated April 18, 2013 by and among Rhino Energy LLC, 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 guarantors and lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current report on Form 8-K (File No. 001-34892), filed on April 19, 2013)		Rhino
10.10		Second Amendment to Amended and Restated Credit Agreement, dated March 19, 2014 by and among Rhino Energy LLC, 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 guarantors and lenders party thereto (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8-K (File No. 001-34892), filed on March 25, 2014)		Rhino
10.11		Third Amendment to Amended and Restated Credit Agreement, dated April 28, 2015 by and among Rhino Energy LLC, 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 guarantors and lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on April 30, 2015)		Rhino

 

 

Exhibit   Number		Description		Filer
10.12		Purchase and Sale Agreement with Gulfport Energy Corporation dated March 19, 2014 (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on March 25, 2014)		Rhino
10.13		Fourth Amendment to Amended and Restated Credit Agreement, dated March 17, 2016 by and among Rhino Energy LLC, 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 guarantors and lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on March 23, 2016)		Rhino
10.14		Securities Purchase Agreement dated March 21, 2016 by and between Rhino Resource Partners LP and Royal Energy Resources, Inc., incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 000-52547), filed on March 23, 2016		Royal
10.15		Fifth Amendment to Amended and Restated Credit Agreement, dated May 13, 2016 by and among Rhino Energy LLC, 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 guarantors and lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on May 16, 2016)		Rhino
10.16		Sixth Amendment and Consent to Amended and Restated Credit Agreement, dated as of July 19, 2016, by and among Rhino Energy LLC, PNC Bank, National Association, as Administrative Agent, and the guarantors and lenders party thereto (incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q (File No. 001-34892), filed November 10, 2016)		Rhino
10.17		Amended and Restated Employment Agreement of W. Scott Morris, effective September 1, 2016 (incorporated by reference to Exhibit 10.4 of the Quarterly Report on Form 10-Q (File No. 001-34892), filed on November 10, 2016)		Rhino
10.18		Letter Agreement between Rhino Resource Partners LP and Joseph E. Funk, dated as of August 22, 2016 (incorporated by reference to Exhibit 10.5 of the Quarterly Report on Form 10-Q (File No. 001-34892), filed on November 10, 2016)		Rhino
10.19		Option Agreement, dated as of December 30, 2016, by and among Rhino Resource Partners Holdings LLC, Rhino Resource Partners LP, Rhino GP LLC, and Royal Energy Resources, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 000-52547) filed on January 6, 2017		Royal
10.20		Series A Preferred Unit Purchase Agreement, dated as of December 30, 2016, by and among Rhino Resource Partners LP, Weston Energy LLC and Royal Energy Resources, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 000-52547) filed on January 6, 2017		Royal

 

 

Exhibit   Number		Description		Filer
10.21		Seventh Amendment to Amended and Restated Credit Agreement, dated December 30, 2016 by and among Rhino Energy LLC, 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 guarantors and lenders party thereto (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (File No. 000-52547) filed on January 6, 2017)		Royal
10.22		Letter Agreement, dated December 30, 2016, by and between Rhino Resource Partners LP and Royal Energy Resources, Inc. (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K (File No. 000-52547) filed on January 6, 2017)		Royal
10.23		Operator Agreement between Blue Grove Coal, LLC and GS Energy, LLC (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K (File No. 000-52547) filed November 30, 2015)		Royal
10.24		Management Agreement between Blue Grove Coal, LLC and Black Oak Resources, LLC (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K (File No. 000-52547) filed November 30, 2015)		Royal
10.25†		Employment Agreement between Royal Energy Resources, Inc. and William L. Tuorto (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K (File No. 000-52547) filed November 30, 2015)		Royal
10.26†		Employment Agreement between Royal Energy Resources, Inc. and Brian Hughs (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K (File No. 000-52547) filed November 30, 2015)		Royal
10.27†		Employment Agreement between Royal Energy Resources, Inc. and Ronald Phillips (incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K (File No. 000-52547) filed November 30, 2015)		Royal
10.28†		2015 Stock Option Plan (incorporated by reference to Exhibit 10.1 the Form S-8 (File No. 333-206024) filed on July 31, 2015)		Royal
10.29†		2015 Employee, Consultant and Advisor Stock Compensation Plan (incorporated by reference to Exhibit 10.2 the Form S-8 (File No. 333-206024) filed on July 31, 2015)		Royal
10.30†*		Amendment to Employment Agreement between Royal Energy Resources, Inc. and Ronald Phillips dated March 1, 2016		Royal
21.1*		List of Subsidiaries of Royal Energy Resources, Inc.		Royal
23.1*		Consent of GZTY CPA GROUP LLC		Royal
23.2*		Consent of Paritz & Company, P.A.		Royal
23.3*		Consent of Brown, Edwards and Company L.L.P.		Royal
23.4*		Consent of Marshall Miller and Associates, Inc.		Royal
31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)		Royal

 

 

Exhibit Number		Description		Filer
31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)		Royal
32.1*		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)		Royal
32.2*		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)		Royal
95.1*		Mine Health and Safety Disclosure pursuant to §1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act for the year ended December 31, 2016 and the three months ended December 31, 2016		Royal
101.INS*		XBRL Instance Document		Royal
101.SCH*		XBRL Taxonomy Extension Schema Document		Royal
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document		Royal
101.DEF*		XBRL Taxonomy Definition Linkbase Document		Royal
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document		Royal
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document		Royal

 

 

*	Filed or furnished herewith, as applicable.
†	Management contract or compensatory plan or arrangement required to be filed as an exhibit to this 10-K pursuant to Item 15(b).
**	Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S K. The registrant undertakes to furnish supplementally copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission.

 

 

Item 16. Form 10-K Summary.

 

Not applicable.

 

 

SIGNATURES

 

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

 

	ROYAL ENERGY RESOURCES, INC.
	By:	/s/ WILLIAM L. TUORTO
		William L. Tuorto
		Chief Executive Officer and Director

 

Date: April 3, 2017

 

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

 

Signature		Title		Date
/s/ William L. Tuorto		Chief Executive Officer and Director (Principal Executive Officer)		April 3, 2017
William L. Tuorto
/s/ Douglas C. Holsted		Chief Financial Officer (Principal Financial and Accounting Officer)		April 3, 2017
Douglas C. Holsted
/s/ Brian Hughs		Director		April 3, 2017
Brian Hughs

 

 

INDEX TO FINANCIAL STATEMENTS

 

ROYAL ENERGY RESOURCES, INC.
Reports of Independent Registered Public Accounting Firms	F-1
Consolidated Balance Sheets as of December 31, 2016 and August 31, 2015	F-4
Consolidated Statements of Operations and Comprehensive Income for the Year Ended December 31, 2016, the four months ended December 31, 2015, and the Years Ended August 31, 2015 and 2014	F-5
Consolidated Statements of Stockholder’s Equity (Deficit) for the Year Ended December 31, 2016, the four months ended December 31, 2015, and the Years Ended August 31, 2015 and 2014	F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, the four months ended December 31, 2015, and the Years Ended August 31, 2015 and 2014	F-7
Notes to Consolidated Financial Statements	F-9

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of

Royal Energy Resources, Inc.

Charleston, South Carolina

 

We have audited the accompanying consolidated balance sheet of Royal Energy Resources, Inc. and Subsidiaries as of December 31, 2016, and the related consolidated statements of operations and comprehensive income, stockholders’ equity (deficit) and cash flows for the year then ended and the consolidated statements of operations and comprehensive income and cash flows for the four-month period ended December 31, 2015. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. The financial statements of the Company as of August 31, 2015 and 2014 were audited by other auditors whose reports dated March 25, 2016, and November 27, 2015, respectively, expressed unqualified opinions on those statements but included an emphasis of a matter paragraph related to the Company’s ability to continue as a going concern.

 

We conducted our audit 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 audit includes 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Royal Energy Resources, Inc. and Subsidiaries as of December 31, 2016, and the consolidated results of their operations and cash flows for the year ended December 31, 2016 and the four-month period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements include the financial position and results of Rhino Resource Partners, LP (“Rhino”), which are significant to the consolidated financial statements. As described in Note 3, Rhino was acquired in 2016, and certain of the provisional values assigned to acquired assets and liabilities are subject to changes as valuations are finalized in the first quarter of 2017. Such revisions may significantly impact the carrying values of assets, liabilities and the results of operations.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, beyond the operations of Rhino, the Company has not established sources of revenues sufficient to fund the development of its business, or to pay projected operating expenses and commitments for the next year. Also as discussed in Note 1, the classification of Rhino’s credit facility balance as a current liability has resulted in a working capital deficit. These factors raise substantial doubt that the Company will be able to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ BROWN, EDWARDS and COMPANY L.L.P.
certified public accountants
513 State Street Bristol, VA
March 31, 2017

 

 

Paritz & Company, P.A.	15 Warren Street, Suite 25
	Hackensack, New Jersey 07601
	(201)342-7753
	Fax: (201) 342-7598

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and
Stockholders of Royal Energy Resources, Inc.

 

We have audited the accompanying consolidated balance sheet of Royal Energy Resources, Inc. as of August 31, 2015, and the related consolidated statement of operations, stockholders’ equity, and cash flows for the year ended August 31, 2015. Royal Energy Resource’s management is responsible for these financial statements. Our responsibility is to express an opinion on these consolidated 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. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit 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, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Royal Energy Resources, Inc. as of August 31, 2015, and the results of its operations and its cash flows for the year ended August 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

 

The consolidated financial statements referred to above have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has not established sources of revenues sufficient to fund the development of its business, or to pay projected operating expenses and commitments for the next year. The Company has accumulated a net loss of $5,010,502 since inception through August 31, 2015, and incurred a loss of $502,169 for the year ended August 31, 2015. These factors, among others, raise substantial doubt that the Company will be able to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ Paritz & Company, P.A.
Hackensack, NJ
November 24, 2015

 

 

GZTY CPA Group, LLC

52 Bridge Street

Metuchen, NJ 08840

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors

 

Royal Energy Resources, Inc.

 

(formerly World Marketing, Inc.)

 

We have audited the accompanying balance sheet of Royal Energy Resources, Inc. as of August 31, 2014 and the related statements of operations, cash flows and the statement of stockholders’ deficit for the year ended August 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

 

We conducted our audit in accordance with 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Royal Energy Resources, Inc., as of August 31, 2014, and the results of its operations and its cash flows for the year ended August 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

 

The financial statements referred to above have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has no established source of revenue and is dependent on its ability to raise capital from shareholders or other sources to sustain operations. These factors among other matters as set forth in Note 2, raise substantial doubt that the Company will be able to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ GZTY CPA Group LLC
Metuchen New Jersey
December 8 2014

 

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(in thousands)

 

		December 31, 2016				August 31, 2015
Assets
CURRENT ASSETS
Cash and cash equivalents		$	86			$	4,180
Accounts receivable, less allowance for bad debts of $0 and $13, respectively			13,893				31
Inventories			8,050				-
Notes receivable and accrued interest - related party			-				43
Advance royalties, current portion			898				-
Prepaid expenses and other assets			8,461				1
Total current assets			31,388				4,255
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs			69,684				7,066
Less accumulated depreciation, depletion and amortization			(4,572	)			-
Net property, plant and equipment			65,112				7,066
Advance royalties, net of current portion			7,652				-
Investment in unconsolidated affiliates			5,121				-
Intangible purchase option			21,750				-
Goodwill			7,594				-
Intangible assets, less accumulated amortization of $68 and $91, respectively			33				779
Other non-current assets			27,591				250
TOTAL ASSETS		$	166,242			$	12,350
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable		$	10,447			$	73
Accrued expenses and other			11,405				56
Notes payable - Related party			504				404
Current portion of long-term debt			12,040				-
Current portion of asset retirement obligations			917				-
Related party advances and accrued interest payable			71				34
Total current liabilities			35,384				567
NON-CURRENT LIABILITIES:
Asset retirement obligations, net of current portion			26,503				-
Other non-current liabilities			39,073				-
Total non-current liabilities			65,576				-
Total liabilities			100,960				567
COMMITMENTS AND CONTINGENCIES (NOTE 20)
STOCKHOLDERS' EQUITY
Preferred stock: $0.00001 par value; authorized 10,000,000 shares; 51,000 issued and outstanding at December 31, 2016 and August 31, 2015			-				-
Common stock: $0.00001 par value; authorized 500,000,000 shares; 17,212,278 shares and 13,850,230 shares issued and outstanding at December 31, 2016, and August 31, 2015, respectively			1				1
Additional paid-in capital			47,295				16,793
Stock subscription receivable			(213	)			-
Accumulated other comprehensive income			874				-
Accumulated deficit			(20,579	)			(5,011	)
Total stockholders’ equity owned by common shareholders			27,378				11,783
Non-controlling interest			37,904				-
Total stockholders' equity			65,282				11,783
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY		$	166,242			$	12,350

 

See accompanying notes to consolidated financial statements.

 

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income

Year ended December 31, 2016, Four months ended December 31, 2015 and years ended August 31, 2015 and 2014

(in thousands)

 

						Four
		Year ended				Months ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
REVENUES:
Coal sales		$	130,739			$	-			$	281			$	-
Freight and handling revenues			1,338				-				-				-
Other revenues			6,492				-				-				-
Total revenues			138,569				-				281				-
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			111,634				-				283				-
Freight and handling costs			1,268				-				-				-
Depreciation, depletion and amortization			4,503				145				91				-
Asset impairment			16,746				-				-				-
Selling, general and administrative expense (exclusive of depreciation, depletion and amortization shown separately above)			14,142				808				394				797
Total costs and expenses			148,293				953				768				797
INCOME (LOSS) FROM OPERATIONS			(9,724	)			(953	)			(487	)			(797	)
INTEREST AND OTHER EXPENSE/(INCOME:)
Interest expense
Other			4,285				-				-				-
Related party			12				4				6				21
Interest income
Other			(1	)			(1	)			-				-
Related party			(6	)			(2	)			(1	)			-
Equity in net loss/(income) of unconsolidated affiliates, net			183				-				-				-
Loss on commodities trading			-				-				10				(1	)
Loss on forfeiture of deposit			-				250				-				-
Total other expense (income)			4,473				251				15				20
NET LOSS FROM CONTINUING OPERATIONS			(14,197	)			(1,204	)			(502	)			(817	)
INCOME FROM DISCONTINUED OPERATIONS			650				-				-				-
NET LOSS BEFORE NON-CONTROLLING INTEREST			(13,547	)			(1,204	)			(502	)			(817	)
Less net earnings attributable to non-controlling interest			817				-				-				-
NET LOSS ATTRIBUTABLE TO COMPANY'S STOCKHOLDERS			(14,364	)			(1,204	)			(502	)			(817	)
OTHER COMPREHENSIVE LOSS:
Fair market value adjustment for available-for-sale investment			1,614				-				-				-
Less comprehensive earnings attributable to non-controlling interest			740				-				-				-
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	(13,490	)		$	(1,204	)		$	(502	)		$	(817	)
Net income (loss) per share, basic and diluted
Continuing operations		$	(0.97	)		$	(0.08	)		$	(0.05	)		$	(0.16	)
Discontinued operations		$	0.04			$	-			$	-			$	-
		$	(0.93	)		$	(0.08	)		$	(0.05	)		$	(0.16	)
Weighted average shares outstanding, basic and diluted			14,527,495				14,794,212				10,335,741				5,060,675

 

See accompanying notes to consolidated financial statements.

 

 

Royal Energy Resources, Inc. and Subsidiaries

Consolidated Statements of Stockholders' Equity (Deficit)

Year ended December 31, 2016, Four months ended December 31, 2015 and years ended August 31, 2015 and 2014 

(in thousands, except shares)

 

																										Accumulated
		Preferred stock								Common stock								Additional Paid In				Non-Controlling				Other Comprehensive				Treasury				Stock Subscription				Accumulated
		Shares				Amount				Shares				Amount				Capital				Interest				Income (Loss)				Stock				Receivable				Deficit				Total
Balance, August 31, 2013			100,000			$	-				179,609			$	1			$	3,513			$	-			$	-			$	-			$	-			$	(3,692	)		$	(178	)
Treasury stock acquired			-				-				(5,292	)			-				-				-				-				(3	)			-				-				(3	)
Common stock issued for:																																											-
Consulting contract			-				-				800,000				-				320				-				-				-				-				-				320
Amounts due related party and compensation			-				-				6,700,000				-				502				-				-				-				-				-				502
Loan extension fee			-				-				275,000				-				21				-				-				-				-				-				21
Loan principal			-				-				300,000				-				22				-				-				-				-				-				22
Net loss			-				-				-				-				-				-				-				-				-				(817	)			(817	)
Balance, August 31, 2014			100,000			$	-				8,249,317			$	1			$	4,378			$	-			$	-			$	(3	)		$	-			$	(4,509	)		$	(133	)
Sell treasury stock			-				-				5,292				-				(2	)			-				-				3				-				-				1
Common stock issued for:																																											-
Consulting contract			-				-				410,000				-				41				-				-				-				-				-				41
Acquisition of Blaze Minerals			-				-				2,803,621				-				7,009				-				-				-				-				-				7,009
Acquisition of Blue Grove			-				-				350,000				-				875				-				-				-				-				-				875
Cash			-				-				2,032,000				-				4,505				-				-				-				-				-				4,505
Retire preferred stock			(49,000	)			-				-				-				(13	)			-				-				-				-				-				(13	)
Net loss			-				-				-				-				-				-				-				-				-				(502	)			(502	)
Balance August 31, 2015			51,000				-				13,850,230				1				16,793				-				-				-				-				(5,011	)			11,783
Common stock issued for:																																											-
Cash			-				-				1,218,000				-				3,045				-				-				-				-				-				3,045
Services			-				-				95,597				-				500				-				-				-				-				-				500
Modification of Blue Grove transaction			-				-				(340,000	)			-				(534	)			-				-				-				-				-				(534	)
Net loss			-				-				-				-				-				-				-				-				-				(1,204	)			(1,204	)
Balance December 31, 2015			51,000				-				14,823,827				1				19,804				-				-				-				-				(6,215	)			13,590
Common stock issued for:
Cash			-				-				112,500				-				900				-				-				-				-				-				900
Services			-				-				28,094				-				283				-				-				-				-				-				283
Acquisition of Blaze Mining royalty			-				-				1,750,000				-				21,263				-				-				-				-				-				21,263
Conversion of convertible notes payable							-				447,857				-				2,462				-				-								-
Stock subscription receivable			-				-				50,000				-				213				-				-				-				(213	)							-
Mark-to-market investment			-				-				-				-				-				740				874				-				-				-				1,614
Initial valuation of non-controlling interest			-				-				-				-				-				3,524				-				-				-				-				3,524
Change in proportion of non-controlling interest			-				-				-				-				2,370				(2,370	)			-				-				-				-
New units issued by subsidiary			-				-				-				-				-				35,193				-				-				-				-				35,192
Net loss			-				-				-				-				-				817				-				-				-				(14,364	)			(13,547	)
Balance December 31, 2016			51,000			$	-				17,212,278			$	1			$	47,295			$	37,904			$	874			$	-			$	(213	)		$	(20,579	)		$	65,282

 

See accompanying notes to consolidated financial statements.

 

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Year Ended December 31, 2016, Four Months Ended December 31, 2015, and Years Ended August 31, 2015 and 2014

(in thousands)

 

						Four
		Year ended				Months ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(13,547	)		$	(1,204	)		$	(502	)		$	(817	)
Adjustment to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization			4,915				145				91				-
Accretion of asset retirement obligations			1,131				-				-				-
Amortization of deferred revenue			(1,174	)			-				-				-
Amortization of advance royalties			818				-				-				-
Amortization of debt issuance costs			975				-				-				-
Loss on retirement of advance royalties			44				-				-				-
Loss on sale of marketable securities			-				-				10				-
Loss (gain) on sale/disposal of assets, net			(593	)			-				-				-
Loss on forfeiture of deposit							250
Equity-based compensation			791				375				41				341
Equity-based compensation - former related party			-				-				-				402
Equity in loss of unconsolidated affiliates			144				-				-				-
Distributions from unconsolidated affiliate			300				-				-				-
Accrued interest income - related party			(6	)			(2	)			(1	)			-
Accrued interest expense - related party			12				4				6				-
Provision (recovery) of bad debts			49				-				13				-
Asset impairment			16,746				-				-				-
Change in assets and liablities:			-				-				-				-
Accounts receivable			(3,123	)			-				(44	)			-
Inventories			(1,290	)			-				-				-
Advance royalties			(721	)			-				-				-
Prepaid expenses and other assets			229				-				(1	)			-
Accounts payable			1,801				231				16				48
Accounts payable - related party			20				-				-				-
Accrued expenses and other liabilities			(147	)			90				-				-
Asset retirement obligations			(822	)			-				-				-
Net cash provided by (used in) operations			6,552				(111	)			(371	)			(26	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in Rhino Resource Partners, LP			(4,500	)			-				-				-
Investment in Blaze Mining royalty			150				-				-				-
Note receivable - related party			-				-				(43	)			-
Cash acquired in acquisitions			619				-				6				-
Treasury stock transactions			-				-				1				(3	)
Marketable securities			-				-				9				(20	)
Deposit			-				-				(250	)			-
Advances to related party			-				(10	)			-				-
Proceeds from sale of Elk Horn			11,100				-				-				-
Other			35				-				-				-
Additions to property, plant and equipment			(5,075	)			-				-				(2	)
Net cash (used in) investing activities			2,329				(10	)			(277	)			(25	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit			101,050				-				-				-
Repayments on line of credit			(132,509	)			-				-				-
Payments on debt issuance costs			(1,594	)			-				-				-
Loan proceeds			4,000				-				-				18
Non-controlling interest			10,960				-				-				-
Proceeds of related party loans			100				-				404				-
Advances from related parties, net			-				-				2				1
Proceeds from issuance of common stock			900				3,045				4,505				-
Repayment of notes payable and long-term debt			(1,156	)			-				(83	)			-
Proceeds from issuance of convertible notes			2,350				-				-				-
Net cash provided by (used in) financing activities			(15,899	)			3,045				4,828				19
Net increase (decrease) in cash and cash equivalents			(7,018	)			2,924				4,180				(32	)
Cash, beginning of period			7,104				4,180				-				32
Cash, end of period		$	86			$	7,104			$	4,180			$	-

 

See accompanying notes to consolidated financial statements.

 

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows, Continued

Year ended December 31, 2016, Four months ended December 31, 2015 and years ended August 31, 2015 and 2014

(in thousands)

 

						Four
		Year ended				Months ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
Supplemental cash flow information
Cash paid for interest		$	3,800			$	-			$	3			$	-
Cash paid for income taxes		$	-			$	-			$	-			$	-
Non-cash investing and financing activities
Common stock issued as part of acquisition of coal royalty interests		$	21,263			$	-			$	-			$	-
Rhino units issued to non-controlling interest in exchange for intangible purchase option			21,750				-				-				-
Property and equipment additions in accounts payable			1,100				-				-				-
Value of LTIP units issued			600				-				-				-
Common stock issued for convertible notes payable and accrued interest			2,462				-				-				-
Issuance of common stock in payment of accrued compensation			-				17				-				-
Issuance of common stock for prepaid consulting fees			-				133				-				-
Common stock issued for Blaze Minerals mineral interests			-				-				7,009				-
Liabilities assumed in acquisition of Blaze Minerals mineral interests			-				-				57				-
Preferred stock acquired in exchange for former subsidiaries			-				-				13				-
Common stock issued for:
Acquisition of Blue Grove Coal, LLC			-				-				875				-
Amount due related party			-				-				-				101
Loan principal			-				-				-				23
Accounts payable and accrued expenses assumed by related party			-				-				-				72
Loan principal assumed by related party			-				-				-				8
Consulting agreement cancelled			-				-				-				43

 

See accompanying notes to consolidated financial statements.

 

 

ROYAL ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2016, AUGUST 31, 2015 AND 2014

AND THE FOUR MONTHS ENDED DECEMBER 31, 2015

 

1. ORGANIZATION AND BASIS OF PRESENTATION

 

Basis of Presentation and Principles of Consolidation—The accompanying consolidated financial statements include the accounts of Royal Energy Resources, Inc. (“Royal”) and its wholly owned subsidiaries, Rhino GP LLC (“Rhino GP”), Blaze Minerals, LLC (“Blaze Minerals”), a West Virginia limited liability company and Blue Grove Coal, LLC (“Blue Grove”), a West Virginia limited liability company and its majority owned subsidiary Rhino Resource Partners, LP (“Rhino”)(the “Partnership”)(OTCQB:RHNO), a Delaware limited partnership (collectively the “Company”). Rhino GP is the general partner of Rhino.

 

Intercompany transactions and balances have been eliminated in consolidation.

 

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 statements for the period from September 1, 2014 to December 31, 2014, in accordance with Rule 13a-10(c). The audit of this period is included herein.

 

Organization and nature of business

 

Royal is a Delaware corporation which was incorporated on March 22, 1999, under the name Webmarketing, Inc. On July 7, 2004, the Company revived its charter and changed its name to World Marketing, Inc. In December 2007 the Company changed its name to Royal Energy Resources, Inc. Since 2007, the Company pursued gold, silver, copper and rare earth metal mining concessions in Romania and mining leases in the United States. Commencing in January 2015, the Company began a series of transactions to sell all of its existing assets, undergo a change in ownership control and management and repurpose itself as a North American energy recovery company, planning to purchase a group of synergistic, long-lived energy assets, but taking advantage of favorable valuations for mergers and acquisitions in the current energy markets. On April 13, 2015, the Company executed an agreement for the first acquisition in furtherance of its change in principal operations.

 

Blaze Minerals is the owner of 40,976 net acres of coal and coalbed methane mineral interest in 22 counties across West Virginia.

 

Blue Grove is a licensed mine operator based in McDowell County, West Virginia and is currently under contract to operate a mine owned by GS Energy, LLC.

 

Rhino was formed on April 19, 2010 to acquire Rhino Energy LLC (the “Operating Company”). 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 sales are made to domestic utilities and other coal-related organizations in the United States.

 

Royal Energy Resources, Inc. Acquisition of Rhino

 

On January 21, 2016, a definitive agreement (“Definitive Agreement”) was completed between Royal and Wexford Capital whereby Royal acquired 676,911 issued and outstanding common units of Rhino from Wexford Capital 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 the General Partner, as well as 945,525 issued and outstanding subordinated units of Rhino from Wexford Capital for $1.0 million.

 

On March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of the General Partner as well as the 945,525 issued and outstanding subordinated units from Wexford Capital. Royal obtained control of, and a majority limited partner interest, in Rhino with the completion of this transaction.

 

 

On March 21, 2016, Royal and Rhino entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant to which Rhino issued 6,000,000 common units to Royal in a private placement at $1.50 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 Rhino in the amount of $7.0 million (the “Rhino Promissory Note”). The promissory note was 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.

 

As a result of these transactions, Rhino became a majority owned subsidiary of Royal. See Note 3.

 

Option Agreement

 

On December 30, 2016, Rhino entered into an option agreement (the “Option Agreement”) with Royal, Rhino Resources Partners Holdings, LLC (“Rhino Holdings”), an entity wholly owned by certain investment partnerships managed by Yorktown Partners LLC (“Yorktown”), and Rhino GP. Upon execution of the Option Agreement, Rhino received an option (the “Call Option”) from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy, Inc. (“Armstrong Energy”) that is currently owned by investment partnerships managed by Yorktown, which currently represents approximately 97% of the outstanding common stock of Armstrong Energy. The Option Agreement stipulates that Rhino can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting Rhino the Call Option, Rhino issued 5.0 million common units, representing limited partner interests in the Partnership (the “Call Option Premium Units”) to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement stipulates Rhino can exercise the Call Option and purchase the common stock of Armstrong Energy in exchange for a number of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings owning 51% of the fully diluted common units of Rhino. The purchase of Armstrong Energy through the exercise of the Call Option would also require Royal to transfer a 51% ownership interest in the Rhino GP to Rhino Holdings. Rhino’s ability to exercise the Call Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the amendment of Rhino’s revolving credit facility to permit the acquisition of Armstrong Energy. The percentage ownership of Armstrong Energy represented by the Armstrong Shares as of the date the Call Option is exercised is subject to dilution based upon the terms under which Armstrong Energy restructures its indebtedness, the terms of which have not been determined yet.

 

The Option Agreement also contains an option (the “Put Option”) granted by Rhino to Rhino Holdings whereby Rhino Holdings has the right, but not the obligation, to cause Rhino to purchase substantially all of the outstanding common stock of Armstrong Energy from Rhino Holdings under the same terms and conditions discussed above for the Call Option. The exercise of the Put Option is dependent upon (i) the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the termination and repayment of any outstanding balance under Rhino’s revolving credit facility. In the event either the Partnership or Rhino GP fail to perform their obligations in the event Rhino Holdings exercises the Put Option, then Rhino Holdings and the Partnership each have the right to terminate the Option Agreement, in which event no party thereto shall have any liability to any other party under the Option Agreement, although Rhino Holdings shall be allowed to retain the Call Option Premium Units.

 

Rhino Series A Preferred Unit Purchase Agreement

 

On December 30, 2016, Rhino entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Unit Agreement”) with Weston Energy LLC (“Weston”), an entity wholly owned by certain investment partnerships managed by Yorktown, and Royal. Under the Preferred Unit Agreement, Weston and Royal agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred units representing limited partner interests in the Partnership (“Series A Preferred Units”) at a price of $10.00 per Series A preferred unit. The Series A preferred units have the preferences, rights and obligations set forth in the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, Weston and Royal paid cash of $11.0 million and $2.0 million, respectively, to the Partnership and Weston assigned to the Partnership a $2.0 million note receivable from Royal originally dated September 30, 2016 (the “Weston Promissory Note”).

 

 

The Preferred Unit Agreement contains customary representations, warrants and covenants, which include among other things, that, for as long as the Series A preferred units are outstanding, the Partnership will cause CAM Mining, LLC (“CAM Mining”), which comprises the partnership’s Central Appalachia segment, to conduct its business in the ordinary course consistent with past practice and use reasonable best efforts to maintain and preserve intact its current organization, business and franchise and to preserve the rights, franchises, goodwill and relationships of its employees, customers, lenders, suppliers, regulators and others having business relationships with CAM Mining.

 

The Preferred Unit Agreement stipulates that upon the request of the holder of the majority of the Partnership’s common units following their conversion from Series A preferred units, as outlined in the Amended and Restated Partnership Agreement, the Partnership will enter into a registration rights agreement with such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights.

 

Fourth Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP

 

On December 30, 2016, the General Partner entered into the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (“Amended and Restated Partnership Agreement”) to create, authorize and issue the Series A Preferred Units.

 

The Series A preferred units are a new class of equity security that rank senior to all classes or series of equity securities of the Partnership with respect to distribution rights and rights upon liquidation. The holders of the Series A preferred units shall be entitled to receive annual distributions equal to the greater of (i) 50% of the CAM Mining free cash flow (as defined below) and (ii) an amount equal to the number of outstanding Series A preferred units multiplied by $0.80. “CAM Mining free cash flow” is defined in the Amended and Restated Partnership Agreement as (i) the total revenue of the Partnership’s Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for the Partnership’s Central Appalachia business segment, minus (iii) an amount equal to $6.50, multiplied by the aggregate number of met coal and steam coal tons sold by the Partnership from its Central Appalachia business segment. If the Partnership fails to pay any or all of the distributions in respect of the Series A preferred units, such deficiency will accrue until paid in full and the Partnership will not be permitted to pay any distributions on its partnership interests that rank junior to the Series A preferred units, including its common units. The Series A preferred units will be liquidated in accordance with their capital accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances of their capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.

 

 

The Series A preferred units will vote on an as-converted basis with the common units, and the Partnership will be restricted from taking certain actions without the consent of the holders of a majority of the Series A preferred units, including: (i) the issuance of additional Series A preferred units, or securities that rank senior or equal to the Series A preferred units; (ii) the sale or transfer of CAM Mining or a material portion of its assets; (iii) the repurchase of common units, or the issuance of rights or warrants to holders of common units entitling them to purchase common units at less than fair market value; (iv) consummation of a spin off; (v) the incurrence, assumption or guaranty indebtedness for borrowed money in excess of $50.0 million except indebtedness relating to entities or assets that are acquired by the Partnership or its affiliates that is in existence at the time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of the Partnership’s Central Appalachia business segment, subject to certain exceptions.

 

The Partnership will have the option to convert the outstanding Series A Preferred Units at any time on or after the time at which the amount of aggregate distributions paid in respect of each Series A Preferred Unit exceeds $10.00 per unit. Each Series A preferred unit will convert into a number of common units equal to the quotient (the “Series A Conversion Ratio”) of (i) the sum of $10.00 and any unpaid distributions in respect of such Series A Preferred Unit divided by (ii) 75% of the volume-weighted average closing price of the common units for the preceding 90 trading days (the “VWAP”); provided however, that the VWAP will be capped at a minimum of $2.00 and a maximum of $10.00. On December 31, 2021, all outstanding Series A preferred units will convert into common units at the then applicable Series A Conversion Ratio.

 

Debt Classification— The Company evaluated the Partnership’s amended and restated senior secured credit facility at December 31, 2016 to determine whether this debt liability should be classified as a long-term or current liability on the Company’s consolidated balance sheet. On May 13, 2016, the Partnership entered into a fifth amendment (the “Fifth Amendment”) of its amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. As of December 31, 2016, the Partnership has met the requirements to extend the maturity date of the credit facility to December 31, 2017. Since the credit facility has an expiration date of December 2017, the Partnership determined that its credit facility debt liability of $10.0 million at December 31, 2016 should be classified as a current liability on its consolidated balance sheet. The classification of the credit facility balance as a current liability raises substantial doubt of the Company’s ability to continue as a going concern for the next twelve months. The Company is considering alternative financing options that could result in a new long-term credit facility. Since the credit facility has an expiration date of December 31, 2017, the Company will have to secure alternative financing to replace its credit facility by the expiration date of December 31, 2017 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 Company be unable to continue as a going concern.

 

Discontinued Operations - The Company’s majority owned subsidiary, Rhino, sold its Elk Horn operation in August 2016. The Company valued the Elk Horn assets at their sale value and recognized no gain or loss on the sale. Discontinued operations includes the earnings from operations since the acquisition date.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

 

Trade Receivables and Concentrations of Credit Risk. See Note 20 for discussion of major customers. The Company does not require collateral or other security on accounts receivable. The credit risk is controlled through credit approvals and monitoring procedures.

 

Cash and Cash Equivalents. The Company 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 Company 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 Company 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 Company has ceased mining or has made a decision not to mine on such property.

 

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 Company assumes zero salvage values for the majority of 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 Company defines a surface mine as a location where the Company 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 Company 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 Company capitalizes only the development cost of the first pit at a mine site that may include multiple pits.

 

Asset Impairments for Coal Properties, Mine Development Costs and Other Coal Mining Equipment and Related Facilities. The Company 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 Company 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.

 

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, 2016 since the Company classified its credit facility balance as a current liability.

 

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 Company has recorded the asset retirement costs for its mining operations in coal properties.

 

 

The Company 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 Company 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 Company 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, 2016 were calculated with discount rates that ranged from 7.0% to 9.1%. The discount rates may change 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 2016.

 

Revenue Recognition. Most of the Company’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.

 

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. With respect to other revenues recognized in situations unrelated to the shipment of coal, the Company 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 collectability is reasonably assured. Advance payments received are deferred and recognized in revenue when earned.

 

Equity-Based Compensation. The Company applies the provisions of ASC Topic 718 to account for any stock/unit awards granted to employees, directors or consultants. 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. Royal has granted stock awards to officers and consultants and Rhino GP has granted restricted units to directors and certain employees of Rhino GP and Rhino that contain only a service condition. The fair value of each stock grant and each restricted unit award was calculated using the closing price of Rhino’s common units on the date of grant.

 

Expense related to unit awards is recorded in the selling, general and administrative line of the Company’s consolidated statements of operations and comprehensive income.

 

Derivative Financial Instruments. On occasion, the Company has used diesel fuel contracts to manage the risk of fluctuations in the cost of diesel fuel. The 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 Company had one diesel fuel contract as of December 31, 2016 to purchase approximately 1.0 million gallons of diesel fuel at fixed prices through December 2017.

 

 

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 Company’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Company 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 Company’s proportionate share of the investees’ net income or losses after the date of investment. Any losses from the Company’s equity method investment are absorbed by the Company based upon its proportionate ownership percentage. If losses are incurred that exceed the Company’s investment in the equity method entity, then the Company 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.

 

Income Taxes. The Company uses the asset and liability method of accounting for income taxes in accordance with ASC Topic 740 “Income Taxes.” Under this method, income tax expense is recognized for the amount of: (i) taxes payable or refundable for the current year and (ii) deferred tax consequences of temporary differences resulting from matters that have been recognized in an entity’s financial statements or tax returns. Deferred taxes and liabilities are measured using enacted tax rates or expected tax rates to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is provided to reduce the deferred tax assets reported if, based on the weight of the available positive and negative evidence, it is more likely than not some portion or all of the deferred tax assets will not be realized.

 

ASC Topic 740-10-30 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC Topic 740-10-40 provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We have no material uncertain tax positions for any of the reporting periods presented.

 

Loss Contingencies. In accordance with the guidance on accounting for contingencies, the Company 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 Company discloses information concerning loss contingencies for which an unfavorable outcome is probable. See Note 19, “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 Company is currently evaluating the requirements of this new accounting guidance.

 

 

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 provides guidance on management’s responsibility in evaluating whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early adoption permitted. The adoption of ASU 2014-15 did not have a material impact on the Company’s consolidated financial statements.

 

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 has not had a material impact on the Company’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. 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 did not have a material impact on the Company’s financial statements.

 

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 requires that lessees recognize all leases (other than leases with a term of twelve months or less) on the balance sheet as lease liabilities, based upon the present value of the lease payments, with corresponding right of use assets. ASU 2016-02 also makes targeted changes to other aspects of current guidance, including identifying a lease and lease classification criteria as well as the lessor accounting model, including guidance on separating components of a contract and consideration in the contract. The amendments in ASU 2016-02 will be effective for the Company on January 1, 2019 and will require modified retrospective application as of the beginning of the earliest period presented in the financial statements. Early application is permitted. The Company is currently evaluating this guidance.

 

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 provides guidance on eight cash flow issues, including debt prepayment or debt extinguishment costs. ASU 2016-15 requires that cash payments related to debt prepayments or debt extinguishments, excluding accrued interest, be classified as a financing activity rather than an operating activity even when the effects enter into the determination of net income. The amendments in ASU 2016-15 will be effective on January 1, 2018 and must be applied retrospectively. Early application is permitted. The Company is currently evaluating this guidance.

 

In October 2016, the FASB issued ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties that are Under Common Control.” ASU 2016-17 amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. ASU 2016-17 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The adoption of ASU 2016-17 is not expected to have a material impact on the Company’s financial statements.

 

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805).” ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company is currently evaluating this guidance.

 

 

3. ACQUISITIONS

 

Acquisition of Blaze Minerals, LLC

 

On April 13, 2015 the Company entered into a Securities Exchange Agreement with Wastech, Inc. (“Wastech”), under which the Company acquired all of the issued and outstanding membership units of Blaze Minerals, LLC (“Blaze Minerals”). Blaze Minerals owns 40,976 net acres of coal and coalbed methane mineral rights in 22 counties in West Virginia (the “Mineral Rights”). The Company acquired Blaze Minerals by the issuance of 2,803,621 shares of common stock. The shares were valued at $7 million based upon a per share value of $2.50 per share, which was the price at which the Company issued its common stock in a private placement at the time. The assets acquired and liabilities assumed as part of the acquisition were recognized at their fair values at the acquisition date as follows:

 

		(thousands)
Mineral rights		$	7,066
Liabilities assumed			57
Common stock issued		$	7,009

 

Acquisition of Blue Grove Coal, LLC

 

On June 10, 2015, the Company, via a Securities Exchange Agreement, completed the acquisition of Blue Grove Coal, LLC (“Blue Grove”) in exchange for 350,000 shares of its common stock from Ian and Gary Ganzer (the “Members”). Simultaneous with the Company’s acquisition of Blue Grove, Blue Grove entered into an Operator Agreement with GS Energy, LLC, under which Blue Grove has an exclusive right to mine the coal properties of GS Energy for a two year period. During the term of the Operator Agreement, Blue Grove is entitled to all revenues from the sale of coal mined from GS Energy’s properties, and is responsible for all costs associated with the mining of the properties or the properties themselves, including operating costs, lease, rental or royalty payments, insurance and bonding costs, property taxes, licensing costs, etc. Simultaneous with the acquisition of Blue Grove, Blue Grove also entered into a Management Agreement with Black Oak Resources, LLC (“Black Oak”), a company owned by the Members. Under the Management Agreement, Blue Grove subcontracted all of its responsibilities under the Operator Agreement with GS Energy to Black Oak. In consideration, Black Oak is entitled to 75% of all net profits generated by the mining of the coal properties of GS Energy. Subsequently, the agreement with Black Oak was amended to provide that Black Oak was entitled to 100% of the first $400,000 and 50% of the next $1,000,000, for a maximum of $900,000 of net profits generated by the mining of the coal properties of GS Energy.

 

The assets acquired as part of the acquisition were recognized at their fair values at the acquisition date as follows:

 

		(thousands)
Cash		$	5
Intangible assets			870
Common stock issued		$	875

 

On December 23, 2015, the Company and the Members entered into an Amendment to Securities Exchange Agreement (“Amendment”) originally entered into on June 10, 2015 under which the Company acquired all of the membership interests of Blue Grove in exchange for 350,000 shares of the Company’s common stock. Pursuant to the Amendment, the consideration for the acquisition of Blue Grove was reduced from 350,000 shares of the Company’s common stock to 10,000 shares.

 

 

The Company reduced additional paid-in capital by $533,821 and the investment in Blue Grove by the same amount when the shares were returned to be cancelled. This left a value of $101,300 assigned to the intangible asset to be amortized over its remaining life.

 

Acquisition of Rhino GP, LLC and Rhino Resource Partners, LLC

 

On January 21, 2016 Royal entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Wexford Capital, LLC (“Wexford”), under which Royal agreed to purchase, and Wexford agreed to sell, a controlling interest in Rhino in two separate transactions. Pursuant to the Purchase Agreement, Royal purchased 676,912 common units of Rhino from three holders for total consideration of $3,500,000. The common units purchased by Royal represented approximately 40.0% of the issued and outstanding common units of Rhino and 23.1% of the total outstanding common units and subordinated units. The subordinated units are convertible into common units on a one for one basis upon the occurrence of certain conditions.

 

At a second closing held on March 17, 2016, Royal purchased all of the membership interest of Rhino GP, and 945,526 subordinated units of Rhino from two holders thereof, for aggregate consideration of $1,000,000. The subordinated units purchased by Royal represented approximately 76.5% of the issued and outstanding subordinated units of Rhino, and when combined with the common units already owned by Royal, resulted in Royal owning approximately 55.4% of the outstanding Units of Rhino. Rhino GP is the general partner of Rhino, and in that capacity controls Rhino.

 

On March 21, 2016, Royal entered into a Securities Purchase Agreement (the “SPA”) with Rhino, under which Royal purchased 6,000,000 newly issued common units of Rhino for $1.50 per common unit, for a total investment in Rhino of $9,000,000. Closing under the SPA occurred on March 22, 2016. Royal paid the purchase by making a cash payment of $2,000,000 and by issuing a promissory note in the amount of $7,000,000 to Rhino, which was payable without interest on the following schedule: $3,000,000 on or before July 31, 2016; $2,000,000 on or before September 30, 2016; and $2,000,000 on or before December 31, 2016. On May 13, 2016 and September 30, 2016, Royal paid the Partnership $3.0 million and $2.0 million, respectively, for the promissory note installments that were due July 31, 2016 and September 30, 2016, respectively. The installment due December 31, 2016 was extended until December 31, 2018.

 

Rhino has the right to rescind the note installments due on December 31, 2018 before such installment is paid in the event the disinterested members of Rhino’s board conclude that Rhino does not need the capital that would be provided by the installment. If Rhino elects to rescind the installment, Royal will be obligated to return for cancellation 1,333,334 common units. In the event Rhino fails to exercise its rescission rights as to the installments due on December 31, 2018, Rhino will have an option to repurchase the common units represented by those installments at a price of $3.00 per common unit, which option may only be exercised in full and in cash as to the installment on or before December 31, 2017.

 

 

Royal has the right to cancel any installment and return the common units represented by the installment to Rhino for cancellation in the event certain conditions are not true as of the time any installment of the note is due. Such conditions are that all representations and warranties in the SPA remain true and correct, Rhino has entered into an agreement to extend its Credit Facility to December 31, 2017, and that Rhino is not then in default under the Credit Facility.

 

The promissory note is secured by a first lien on 1,333,334 of the common units issued under the SPA. The installment due on July 31, 2016 was with full recourse to the Company, and the installment due on September 30, 2016 was nonrecourse to Royal. The installment due on December 31, 2016 is nonrecourse to Royal, and Rhino’s only recourse is to cancel the common units in the event of nonpayment of the promissory note, which has been extended until December 31, 2018.

 

On April 13, 2016, Royal acquired 114,814 subordinated units for $115 in cash. After issuing other new units during the period, the Company’s ownership became 84.5% of the common units and 85.8% of the subordinated units for a combined ownership of 84.6% until December 30, 32016.

 

Rhino’s common units currently trade on the OTCQB Marketplace under the symbol “RHNO.” Rhino’s common units previously traded on the NYSE until December 17, 2015, when the NYSE suspended trading after Rhino failed to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for its common units.

 

Rhino is a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. Rhino produces, processes and sells high quality coal of various steam and metallurgical grades. Rhino markets its steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for its metallurgical coal are primarily steel and coke producers who use its coal to produce coke, which is used as a raw material in the steel manufacturing process. Rhino’s business includes investments in oilfield services for independent oil and natural gas producers and land-based drilling contractors in North America. The investments provide completion and production services, including pressure pumping, pressure control, flowback and equipment rental services, and also produce and sell natural sand for hydraulic fracturing.

  

Rhino has a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2015, Rhino controlled an estimated 363.6 million tons of proven and probable coal reserves, consisting of an estimated 310.1 million tons of steam coal and an estimated 53.5 million tons of metallurgical coal. In addition, as of December 31, 2015, Rhino controlled an estimated 436.8 million tons of non-reserve coal deposits. In August 2016, Rhino sold their Elk Horn coal leasing business, as described further below, which controlled, as of December 31, 2015, an estimated 100.1 million tons of proven and probable coal reserves and an estimated 197.5 million tons of non-reserve coal deposits.

 

At December 31, 2016, the Company’s investment in Rhino consists of $13,500,215 in cash and $2,000,000 in notes payable. The acquisition was completed in three steps as described above. The coal properties and the related asset retirement obligation have been determined by an appraiser. The original provisional assets and liabilities have been adjusted as described below as information became available. The Company will engage an appraiser to value the remaining assets and liabilities acquired, at which time the value will be assigned to specific assets and liabilities. The appraisal will be completed within the one year measurement period.

 

The following table summarizes the assets and liabilities reported by Rhino, acquired by the Company on March 17, 2016 and included in the Company’s consolidated financial statements at December 31, 2016. The non-controlling interest in Rhino was valued based on the trading price of their units on the closing date.

 

 

Royal Energy Resources

Acquisition of Rhino Resource Partners, LP

(thousands) 

 

		Original								Revised
		Provisional								Provisional
		Amounts				Revisions				Amounts
Assets:
Current assets		$	23,390	E		$	1,319
				G		$	(1,592	)		$	23,117
Property, plant and equipment		$	77,800	B		$	(13,800	)
				C		$	690
				H		$	2,122			$	66,812
Other non-current assets		$	42,686	A		$	(2,639	)		$	40,047
Total identifiable assets		$	143,876							$	129,976
Liabilities:
Current liabilities		$	64,473	D		$	(1,663	)		$	62,810
Long-term debt less current portion		$	2,536							$	2,536
Asset retirement obligations, net of current portion		$	27,108							$	27,108
Other non-current liabilities		$	44,098	F		$	(7,006	)		$	37,092
Total liabilities		$	138,215							$	129,546
Net identifiable assets		$	5,661							$	430
Goodwill		$	2,363	A		$	2,639			$	7,594
				B		$	13,800
				C		$	(690	)
				D		$	(1,663	)
				E		$	(1,319	)
				F		$	(7,006	)
				G		$	1,592
				H		$	(2,122	)
		$	8,024							$	8,024
Non-controlling shareholders		$	3,524							$	3,524
Total consideration paid		$	4,500							$	4,500

  

The columns above present the original estimates of the fair value of acquired assets and liabilities, and subsequent adjustments to those estimates.

 

A - Asset impairments subsequent to 3/17/16 that should have had no value

B - Loss on assets of discontinued operations that should have been adjusted to fair value at 3/17/16.

C - Gain on sales and disposals of assets subsequent to the acquisition should have been part of the original asset valuation

D - The gain from debt extinguishment should have been part of the original liability valuation

E - Inventory step up

F - Repurchase obligation

G - Unamortized loan costs

H - Property corrections

 

Operating results for the Company, as if the acquisition of Rhino occurred at the beginning of each period, for the years ended December 31, 2016 and 2015 are as follows.

 

		Year ended December 31,
		2016				2015
		(in thousands)
Revenues		$	170,780			$	195,313
Comprehensive (loss)		$	(12,207	)		$	(10,074	)
Net loss per share, basic and fully diluted		$	(0.84	)		$	(0.81	)

 

 

Blaze Mining Company, LLC Option Termination and Royalty Agreement

 

On May 29, 2015, the Company entered into an Option Agreement with Blaze Energy Corp. (“Blaze Energy”) to acquire all of the membership units of Blaze Mining Company, LLC (“Blaze Mining”), which is a wholly-owned subsidiary of Blaze Energy. Under the Option Agreement, as amended, the Company had the right to complete the purchase through March 31, 2016 by the issuance of 1,272,858 shares of the Company’s common stock and payment of $250,000 in cash. Blaze Mining controlled operations for and had the right to acquire 100% ownership of Alpheus Coal Impoundment reclamation site in McDowell County, West Virginia under a contract with Gary Partners, LLC, which owned the property. On February 22, 2016, the Company facilitated a series of transactions wherein: (i) Blaze Mining and Blaze Energy entered into an Asset Purchase Agreement to acquire substantially all of the assets of Gary Partners, LLC; (ii) Blaze Mining entered into an Assignment Agreement to assign its rights under the Asset Purchase Agreement to a third party; and (iii) the Company and Blaze Energy entered into an Option Termination Agreement, as amended, whereby the following royalties granted to Blaze Mining under the Assignment Agreement were assigned to the Company: a $1.25 per ton royalty on raw coal or coal refuse mined or removed from the property, and a $1.75 per ton royalty on processed or refined coal or coal refuse mined or removed from the property (the “Royalties”). Pursuant to the Option Termination Agreement, the parties thereby agreed to terminate the Option Agreement by the issuance of 1,750,000 shares of the Company’s common stock to Blaze Energy in consideration for the payment by Blaze Energy of $350,000 to the Company and the assignment by Blaze Mining of the Royalties to the Company. The transactions closed on March 22, 2016.

 

Pursuant to an Advisory Agreement with East Coast Management Group, LLC (“ECMG”), the Company agreed to compensate ECMG $200,000 in cash; $0.175 of the $1.25 royalty on raw coal or coal refuse; and $0.25 of the $1.75 royalty on processed or refined coal for its services in facilitating the Option Termination Agreement.

 

The transaction was initially valued based on the trading price of the Company’s common stock on March 22, 2016 as follows. See Note 5.

 

		(thousands)
Royalty interests		$	21,113
Cash received			350
Cash paid			(200	)
Common stock issued		$	21,263

 

 

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

 

Prepaid expenses and other current assets as of December 31, 2016 and 2015 and August 31, 2015, consisted of the following:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Other prepaid expenses		$	761			$	1
Debt issuance costs—net			981				-
Prepaid insurance			1,432				-
Prepaid leases			77				-
Supply inventory			614				-
Deposits			164				-
Available-for-sale investment			3,532				-
Note receivable-current portion			900				-
Total		$	8,461			$	1

 

Debt issuance costs were included in Prepaid expenses and other current assets for the year ended December 31, 2016 since the credit facility balance was classified as a current liability. See Note 11 for further information on the amendments to the amended and restated senior secured credit facility.

 

5. PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, including coal properties and mine development and construction costs, as of December 31, 2016 and 2015 and August 31, 2015 are summarized as follows:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Coal properties, mining and other equipment			69,684				7,066
Total			69,684				7,066
Less accumulated depreciation, depletion and amortization			(4,572	)			-
		$	65,112			$	7,066

 

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, 2016, the four months ended December 31, 2015 and the years ended December 31, 2015 and 2014 was as follows:

 

		December 31,								August 31,				August 31,
		2016				2015				2015				2014
		(in thousands)
Depreciation and amortization expense for coal properties, mining and other equipment and mine development costs			4,572				-				-				-
Amortization expense for intangible assets			67				145				91				-
Amortization expense for asset retirement costs			(136	)			-				-				-
		$	4,503			$	145			$	91			$	-

 

 

Asset Impairments-2016

 

The Company performed a comprehensive review of our current coal mining operations as well as potential future development projects for the year ended December 31, 2016 to ascertain any potential impairment losses. Based on the impairment analysis, the Company concluded that none of the coal properties, mine development costs or other coal mining equipment and related facilities was impaired at December 31, 2016, except for the Blaze Mining royalty As production from this property had not begin at December 31, 2016, the Company engaged a third-party engineer to provide an estimate of fair value. The specialist valued the royalty interests at $4.4 million. Accordingly, the Company recorded an asset impairment loss of $16.7 million in the fourth quarter of 2016.

 

6. 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 no longer amortized but instead tested for impairment at least annually.

 

Goodwill in the provisional amount of $7.6 million arose from the Company’s purchase of Rhino. See Note 3.

 

As discussed in Note 1, Rhino and Rhino Holdings executed an Option Agreement in December 2016 where Rhino received a Call Option from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy. In exchange for Rhino Holdings granting the Call Option, Rhino issued 5.0 million common units to Rhino Holdings upon the execution of the Option Agreement. The Call Option was valued at $21.8 million based upon the closing price of the Partnership’s publicly traded common units on the date the Option Agreement was executed.

 

Intangible assets as of December 31, 2016 and August 31, 2015 consist of the following:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Blue Grove contract rights			101				870
Accumulated amortization			(68	)			(91	)
		$	33			$	779

 

The contract intangible asset has a useful life of two years and is amortized over the useful life on a straight-line basis. See Note 3 for modification of purchase agreement.

 

7. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

 

Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, the Company’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Company 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 Company’s proportionate share of the investees’ net income or losses after the date of investment. Any losses from the Company’s equity method investments are absorbed by the Company based upon its proportionate ownership percentage. If losses are incurred that exceed the Company’s investment in the equity method entity, then the Company 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.

 

 

As of December 31, 2016 and 2015, Rhino has recorded its investment in Mammoth of $1.9 million as a short-term asset, which Rhino has classified as available-for-sale. In October 2016, Rhino contributed its limited partner interests in Mammoth to Mammoth Energy Services, Inc. in exchange for 234,300 shares of common stock of Mammoth Energy Services, Inc. Rhino recorded a fair market value adjustment of $1.6 million for the available-for-sale investment based on the market value of the shares at December 31, 2016, which was recorded in Other Comprehensive Income.

 

In September 2014, Rhino made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC (“Sturgeon”), with affiliates of Wexford Capital and Gulfport. The Company accounts for the investment in this joint venture and results of operations under the equity method based upon its ownership percentage. The Company recorded its proportionate share of the operating loss for this investment for the year ended December 31, 2016 of approximately $0.2 million. The Company has recorded its investment in Sturgeon on the Investment in unconsolidated affiliates line of the Company’s consolidated balance sheet and in the Other category for segment reporting purposes.

 

8. OTHER NON-CURRENT ASSETS

 

Other non-current assets as of December 31, 2016 and August 31, 2015 consisted of the following:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Deposits and other			218				250
Non-current receivable			27,157				-
Deferred expenses			216				-
		$	27,591			$	250

 

As of December 31 2016, the non-current receivable balance of $27.2 million consisted of the amount due from workers’ compensation and black lung insurance providers for potential claims that are the primary responsibility of the Company’s, but are covered under Rhino’s insurance policies. See Note 15 for discussion of the $27.2 million that is also recorded in other non-current workers’ compensation liabilities.

 

  

9. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

 

Accrued expenses and other current liabilities as of December 31, 2016 and 2015 and August 31, 2015 consisted of the following:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Payroll, bonus and vacation expense			1,721				17
Non-income taxes			2,669				29
Royalty expenses			1,617				-
Accrued interest			601				-
Health claims			630				-
Workers' compensation & pneumoconiosis			2,450				-
Accrued insured litigation claims			277				-
Other			867				10
Due Rhino GP			573				-
		$	11,405			$	56

 

The $0.3 million accrued for insured litigation claims as of December 31, 2016 consists of probable and estimable litigation claims that are the primary obligation of the Company. This amount is also due from the Company’s insurance providers and is included in accounts receivable, net of allowance for doubtful accounts on the consolidated balance sheet. The Company 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 results of operations or cash flows.

 

10. NOTES PAYABLE – RELATED PARTY

 

Related party notes payable consist of the following at December 31, 2016 and August 31, 2015.

 

		December 31, 2016				August 31, 2015
		(in thousands)
Demand note payable dated March 6, 2015; owed E-Starts Money Co., a related party; interest at 6% per annum		$	204			$	204
Demand note payable dated June 11, 2015; owed E-Starts Money Co., a related party; non-interest bearing			200				200
Demand note payable dated September 22, 2016; owed E-Starts Money Co., a related party; non-interest bearing			50				-
Demand note payable dated December 8, 2016; owed E-Starts Money Co., a related party; non-interest bearing			50				-
		$	504			$	404

 

The related party notes payable have accrued interest of $22 thousand at December 31, 2016 and $6 thousand at August 31, 2015. Related party interest expense amounted to $12, $4 and $6 for the year ended December 31, 2016, for the four months ended December 31, 2015 and for the year ended August 31, 2015 and zero for the year ended August 31, 2014.

 

 

11. DEBT

 

Debt as of December 31, 2016 and August 31, 2015 consisted of the following:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Senior secured credit facility with PNC Bank, N.A.		$	10,040			$	-
Note payable to Weston Energy dated December 30, 2016; interest at 8% per annum; due January 15, 2017			2,000				-
Total notes payable		$	12,040			$	-

 

On March 17, 2016, the Operating Company, as borrower, and Rhino and certain of Rhino’s subsidiaries, as guarantors, entered into a fourth amendment (the “Fourth Amendment”) of the Amended and Restated Credit Agreement. The Fourth Amendment amended the definition of change of control in the Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of Rhino’s general partner. The Fourth Amendment also eliminated 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 balance on March 17, 2016 was $41,783.

 

On May 13, 2016, Rhino entered into the Fifth Amendment of the Amended and Restated Credit Agreement, which extended the term to July 31, 2017.

 

In July 2016, Rhino entered into a sixth amendment (the “Sixth Amendment”) of the amended and restated senior secured credit facility that permitted the sale of Elk Horn that was discussed earlier. The Sixth Amendment further reduced the maximum commitment amount allowed under the credit facility for the additional $1.5 million that is to be received from the Elk Horn sale by $375,000 each quarterly period beginning September 30, 2016 through June 30, 2017.

 

In December, 2016, Rhino entered into a seventh amendment of the amended and restated credit agreement (the “Seventh Amendment”). The Seventh Amendment allows for the Series A preferred units as outlined in the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduced the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. The Seventh Amendment altered the maximum leverage ratio to 4.0 to 1.0 effective December 31, 2016 through May 31, 2017 and 3.5 to 1.0 from June 30, 2017 through December 31, 2017. The maximum leverage ratio shall be reduced by 0.50 to 1.0 for every $10.0 million of net cash proceeds, in the aggregate, received after the Seventh Amendment date from (i) the issuance of any equity by Rhino and/or (ii) the disposition of any assets in excess of $2.0 million in the aggregate, provided, however, that in no event will the maximum leverage ratio be reduced below 3.0 to 1.0. The Seventh Amendment alters the minimum consolidated EBITDA figure, as calculated on a rolling twelve months basis, to $12.5 million from December 31, 2016 through May 31, 2017 and $15.0 million from June 30, 2017 through December 31, 2017. The Seventh Amendment alters the maximum capital expenditures allowed, as calculated on a rolling twelve months basis, to $20.0 million through the expiration of the credit facility. A condition precedent to the effectiveness of the Seventh Amendment is the receipt of the $13.0 million of cash proceeds received by Rhino from the issuance of the Series A preferred units pursuant to the Preferred Unit Agreement, which will be used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contribution, which was a requirement of prior amendments to the credit agreement.

 

 

At December 31, 2016, the Operating Company had borrowed $10.0 million at a variable interest rate of PRIME plus 3.50% (7.25% at December 31, 2016). In addition, the Operating Company had outstanding letters of credit of $26.1 million at a fixed interest rate of 5.00% at December 31, 2016. Based upon a maximum borrowing capacity of 4.00 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $12.9 million of the borrowing availability at December 31, 2016.

 

Weston Energy - Short-term note payable dated December 30, 2016 and due January 15, 2017 with interest at 8% per annum.

 

The Company did not capitalize any interest costs during the year ended December 31, 2016.

 

12. ASSET RETIREMENT OBLIGATIONS

 

The changes in asset retirement obligations for the year ended December 31, 2016, the four months ended December 31, 2015 and the years ended August 31, 2015 and 2014 are as follows:

 

						Four months
		Year ended				Ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
		(in thousands)
Balance at beginning of period, including current portion		$	-			$	-			$	-				0
Acquired			28,200				-				-				0
Accretion expense			1,105				-				-				0
Adjustments to the liability from annual recosting and other			(1,685	)											0
Liabilities settled			(200	)											0
Balance at end of period			27,420				-				-				0
Less current portion			(917	)			-				-				0
Non-current portion		$	26,503			$	-			$	-				0

 

 

13. INCOME TAXES

 

The income tax provision (benefit) consists of the following:

 

						Four months
		Year ended				ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
		(in thousands)
Federal:
Current		$	-			$	-			$	-			$	-
Deferred			(6,053,200	)			(436,400	)			(170,700	)			(277,700	)
State and local:			-
Current
Deferred			(712,200	)			(51,300	)			(20,100	)			(32,700	)
Change in valuation allowance			6,765,400				487,700				190,800				310,400
Income tax expense		$	-			$	-			$	-			$	-

 

The expected tax benefit based on the statutory rate is reconciled with actual tax benefit as follows:

 

						Four months
		Year ended				ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
U.S. federal statutory rate			-34.0	%			-34.0	%			-34.0	%			-34.0	%
State income tax, net of federal benefit			-4.0	%			-4.0	%			-4.0	%			-4.0	%
Increase (decrease) in valuation allowance			38.0	%			38.0	%			38.0	%			38.0	%
Income tax provision (benefit)			0.0	%			0.0	%			0.0	%			0.0	%

 

 

Deferred tax assets consist of the effects of temporary differences attributable to the following:

 

		December 31, 2016				August 31, 2015
Deferred tax assets:		(in thousands)
Net operating losses		$	1,332,600			$	178,500
Bad debt allowance			-				4,900
Asset impairment			6,363,500				-
Investment in public limited partnership			(375,100	)			-
Accrued expenses			94,100				8,600
Deferred tax assets			7,415,100				192,000
Valuation allowance			(7,415,100	)			(192,000	)
Deferred tax assets, net of valuation allowance		$	-			$	-

 

Due to the changes in ownership of the Company in connection with the change in control and related transactions in March 2015, approximately $55,000 in existing net operating loss carryforwards (computed in accordance with IRS section 382) are available to reduce future taxable income. These NOLs begin to expire in 2019. In addition, losses incurred from the date of the merger to August 31, 2015 aggregating approximately $415,000 are also available to reduce future taxable income. In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based on the assessment, management has established a full valuation allowance against all of the deferred tax assets for every period because it is more likely than not that all of the deferred tax assets will not be realized.

 

A reconciliation of the changes in valuation allowance for the year ended August 31, 2015 is as follows:

 

Balance at August 31, 2014		$	1,533,200
Current year addition			190,800
Effect of change in control			(1,532,000	)
Balance at August 31, 2015		$	192,000

 

14. STOCKHOLDERS’ EQUITY

 

The authorized capital stock of the Company consists of 500,000,000 shares of Common Stock, par value $0.00001 per share, and 10,000,000 shares of Preferred Stock, par value $0.00001 per share. In March 2017, the Company filed an amendment to its Certificate of Incorporation to reduce the authorized shares of Common Stock to 25,000,000 shares and to reduce the authorized shares of Preferred Stock to 5,000,000 shares.

 

 

Series A preferred stock

 

The Company’s Board is authorized, without further stockholder approval, to issue Preferred Stock in one or more series from time to time and fix or alter the designations, relative rights, priorities, preferences, qualifications, limitations and restrictions of the shares of each series.

 

The Board has authorized one series of Preferred Stock, which is known as the “Series A Preferred Stock,” for 100,000 shares. The certificate of designation of the Series A Preferred Stock provides: the holders of Series A Preferred Stock shall be entitled to receive dividends when, as and if declared by the Board of Directors of the Company; participates with common stock upon liquidation; convertible into one share of common stock; and has voting rights such that the Series A Preferred Stock shall have an aggregate voting right for 54% of the total shares entitled to vote.

 

At December 31, 2016 and August 31, 2015, 51,000 shares of Series A Preferred Stock were issued and outstanding.

 

Common stock

 

In October 2012, the Company amended its charter to authorize issuance of up to 500,000,000 shares of common stock with a par value of $0.00001. At December 31, 2016, 17,212,278 shares were issued and outstanding. At August 31, 2015, 13,850,230 shares were issued and outstanding.

 

During the year ended December 31, 2016, the Company issued shares of common stock in the following transactions:

 

	●	On February 5, 2016, the Company issued 37,500 shares in exchange for $300,000 in cash.
	●	On February 17, 2016, the Company issued 11,608 shares each to William Tuorto and Brian Hughs, executive officers, in exchange for accrued compensation in the amount of $125,832 each.
	●	On March 1, 2016, the Company issued 4,878 shares to Ronald Phillips, President, in exchange for a $50,000 bonus pursuant to his employment contract.
	●	On March 22, 2016, the Company issued 1,750,000 restricted shares in exchange for the Blaze Mining royalties. (See Note 3).
	●	On April 13, 2016, the Company issued 62,500 shares in exchange for $500,000 in cash.
	●	On May 17, 2016, the Company issued 12,500 shares in exchange for $100,000 in cash.
	●	On October 10, 2016, the Company issued 50,000 shares to East Hill Investment, Ltd. pursuant to a securities purchase agreement in exchange for a note in the amount of $212,500.
	●	On December 6, 2016, the Company issued a total of 447,857 shares in exchange for convertible notes payable in the amount of $2,350,000 and related accrued interest of $112,671. The majority of the convertible notes were originally issued in April 2016.

 

 

During the four months ended December 31, 2015, the Company issued shares of common stock in the following transactions:

 

	●	Between September 14, 2015 and October 9, 2015, the Company issued 1,218,000 shares of common stock for cash proceeds of $3,045,000 pursuant to a private offering.
	●	On October 22, 2015, the Company issued 95,597 shares of its common stock, valued at $500,000, as compensation under employment agreements with officers. Of this amount, $350,000 was in payment of bonuses pursuant to employment agreements. The remaining $150,000 was pursuant to a two-year employment agreement originally executed on June 10, 2015, of which $16,667 was accrued at August 31, 2015 and $133,333 was recorded as a prepaid expense to be amortized over the life of the agreement. During the four months ended December 31, 2015, $25,000 was amortized to expense. During 2016, $72,917 was amortized to expense.
	●	On December 23, 2015, the Company amended the Blue Grove acquisition agreement (Note 3) and the consideration for the purchase was reduced from 350,000 shares of the Company’s common stock to 10,000 shares.

 

During the year ended August 31, 2015, the Company issued shares of common stock in the following transactions:

 

	●	On December 12, 2014, the Company issued 410,000 shares of common stock to a consultant in exchange for $41,000 in services.
	●	On March 9, 2015, the Company issued 250,000 shares of common stock for cash proceeds of $50,000.
	●	On April 17, 2015, the Company issued 2,803,621 shares of common stock to acquire Blaze Minerals. The shares were valued at $2.50 share, based upon the price for which the Company sold its common stock in a private placement. See Note 4.
	●	On June 10, 2015, the Company issued 350,000 shares of common stock to acquire Blue Grove.
	●	Between June 12, 2015 and August 31, 2015, the Company issued 1,782,000 shares of common stock for cash proceeds of $4,455,000 pursuant to a private offering.

 

Stock subscription receivable

 

On October 4, 2016, the Company entered into a securities purchase agreement with East Hill Investments, Ltd. (“East Hill”), a British Virgin Islands company. The agreement provided that the Company would sell 1,000,000 shares of its common stock, par value $0.00001, to East Hill for an aggregate purchase price of $4,250,000. The transaction was to be completed in a series of transactions for 25,000 to 50,000 shares each. The initial transaction was on October 4, 2016 in the amount of $212,500 for which the Company received a note originally due October 19, 2016 and extended to November 30, 2016. During the first quarter of 2017, both parties agreed to cancel the transaction and the shares were returned to the Company to be cancelled.

 

 

15. OTHER NON-CURRENT LIABILITIES

 

Other non-current liabilities consist of the following at December 31, 2016 and August 31, 2015.

 

		December 31, 2016				August 31, 2015
		(in thousands)
Workers' compensation and black lung claims		$	41,523			$	-
Less current portion			(2,450	)			-
Non-current obligations		$	39,073			$	-

 

WORKERS’ COMPENSATION AND BLACK LUNG

 

Certain of the Company’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 Company 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 Company’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 Company’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 Company’s liability for traumatic workers’ compensation injury claims is the estimated present value of current workers’ compensation benefits, based on actuarial estimates, which 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, 2016 and for workers’ compensation was 2.0% at December 31, 2016.

 

The uninsured black lung and workers’ compensation expenses for the year ended December 31, 2016, the four months ended December 31, 2015 and the years ended August 31, 2015 and 2014 are as follows:

 

						Four months
		Year ended				ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
		(in thousands)
Black lung benefits:
Service cost		$	(401	)		$	-			$	-				-
Interest cost			287												-
Actuarial loss/(gain)			-				-				-				-
Total black lung			(114	)			-				-				-
Workers' compensation expense			3,177				-				-				-
Total expense		$	2,949			$	-			$	-				-

 

 

The changes in the black lung benefit liability for the year ended December 31, 2016, the four months ended December 31, 2015 and the years ended August 31, 2015 and 2014 are as follows:

 

						Four months
		Year ended				ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
		(in thousands)
Benefit obligations assumed on acquisition		$	9,196			$	-			$	-				-
Service cost			(401	)											-
Interest cost			287				-				-				-
Actuarial loss (gain)			-				-				-				-
Benefits and expenses paid			(300	)			-				-				-
Total changes		$	8,782			$	-			$	-				-

 

The classification of the amounts recognized for the workers’ compensation and black lung benefits liability as of December 31, 2016 and August 31, 2015 are as follows:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Black lung claims		$	8,782			$	-
Insured black lung and workers' compensation claims			27,157				-
Workers' compensation claims			5,584				-
Total obligations			41,523				-
Less current portion			(2,450	)			-
Non-current obligations		$	39,073			$	-

 

The balance for insured black lung and workers’ compensation claims as of December 31, 2016 consisted of $27.2 million. This is a primary obligation of the Company, but is also due from the Company’s insurance providers and is included in Note 8 as non-current receivables. The Company 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 results of operations or cash flows.

 

16. RELATED PARTY TRANSACTIONS

 

On March 6, 2015, the Company borrowed $203,593 from E-Starts Money Co. (“E-Starts”) pursuant to a 6% demand promissory note. (See Note 9) The proceeds were used to repay all of our indebtedness at the time. E-Starts is owned by William L. Tuorto, our Chairman and Chief Executive Officer. On June 11, 2015, the Company borrowed an additional $200,000 from E-Starts pursuant to a non-interest bearing demand promissory note. On September 22, 2016, we borrowed $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note and on December 8, 2016, we borrowed an additional $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note. The total amount owed to E-Starts at December 31, 2016 and December 31, 2015 was $503,593 and $403,593, respectively, plus accrued interest.

 

GS Energy, LLC is owned by Ian and Gary Ganzer and is a creditor of Blue Grove Coal, LLC.

 

 

The details of the due to related party account are summarized as follows:

 

		December 31, 2016				August 31, 2015
		(in thousands)
Due to E-Starts Money Co
Expense advances		$	11			$	10
Accrued interest			22				6
Total obligations			33				16
Due to GS Energy, LLC			18				18
Due to Ian and Gary Ganzer			20				-
Total		$	71			$	34

 

On May 14, 2015, the Company entered into an Option Agreement to acquire substantially all of the assets of Wellston for 500,000 shares of the Company’s common stock. The Option Agreement originally terminated on September 1, 2015, but was later extended to December 31, 2016. Wellston owns approximately 1,600 acres of surface and 2,200 acres of mineral rights in McDowell County, West Virginia (the “Wellston Property”). Pursuant to the Option Agreement, pending the closing of the Wellston Property, the Company agreed to loan Wellston up to $500,000 from time to time. The loan is pursuant to Promissory Note bearing interest at 12% per annum, due and payable at the expiration of the Option Agreement, and secured by a Deed of Trust on the Wellston Property. The Company ultimately loaned Wellston $53,000. Our President and Secretary, Ronald Phillips, owns a minority interest in Wellston, and is the manager of Wellston. On September 13, 2016, Wellston sold its assets to an unrelated third party, and we received a royalty of $1 per ton on the first 250,000 tons of coal mined from the property in consideration for a release of our lien on Wellston’s assets.

 

In January 2014, the President and Chief Executive Officer of the Company acquired 6,700,000 shares of the Company’s common stock in exchange for $100,500 due to him, including $71,550 assumed by him of the Company’s liabilities to third party vendors. The fair value of the shares was $502,500. The difference between the value of the shares and the amount paid of $402,000 is included as non-cash compensation in selling, general and administrative expense in the statement of operations. This compensation is for the years 2008 through 2014 for which the President and Chief Executive Officer had not been previously received any compensation.

 

17. EMPLOYEE BENEFITS

 

401(k) Plans—Rhino and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company 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 Operating Company’s discretion. The expense under these plans for the period owned by the Company is included in cost of operations and selling, general and administrative expense in the Company’s consolidated statements of operations and was as follows:

 

 

						Four months
		Year ended				ended				Year ended
		December 31,				December 31,				August 31,
		2016				2015				2015
		(in thousands)
401(k) plan expense		$	1,206			$	-			$	-

 

18. EQUITY-BASED COMPENSATION

 

Stock option plan - The Royal Energy Resources, Inc. 2015 Stock Option Plan and the Royal Energy Resources, Inc. 2015 Employee, Consultant and Advisor Stock Compensation Plan (“Plans”) were approved by the Company’s board on July 31, 2015. Each Plan reserves 1,000,000 shares for awards under each Plan. The Company’s Board of Directors is designated to administer the Plan. No options are outstanding under the Plans at December 31, 2016. 95,597 shares were issued from the Employee, Consultant and Advisor Stock Compensation Plan during the four months ended December 31, 2015 and 28,094 shares were issued during the year ended December 31, 2016. As of December 31, 2016, there are 1,000,000 shares available under the Stock Option Plan and 876,309 shares available under the Employee, Consultant and Advisor Stock Compensation Plan. The shares issued under the Employee, Consultant and Advisor Stock Compensation Plan were expensed at their market value on the date of issuance.

 

In October 2010, the General Partner of Rhino 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 was 247,940.

 

 

						Weighted
						Average
						Grant Date
		Common				Fair Value
		Units				(per unit)
Non-vested awards outstanding when Rhino was acquired			127			$	2.58
Granted			183			$	2.19
Vested			(310	)		$	2.35
Non-vested awards at December 31, 2016			-			$	-

 

For the years ended December 31, 2016 the Company recorded expense of approximately $0.4 million for the LTIP awards. For the year ended December 31, 2016, the total fair value of the awards that vested was $0.7 million. As of December 31, 2016, the Company did not have any unrecognized compensation expense or intrinsic value of any non-vested LTIP awards.

 

19. COMMITMENTS AND CONTINGENCIES

 

Coal Sales Contracts and Contingencies—As of December 31, 2016, the Company had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

 

Year		Tons (in thousands)				Number of customers
2017			3,669				14
2018			701				5

 

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

 

Purchase Commitments—As of December 31, 2016, the Company had a commitment to purchase approximately 1.0 million gallons of diesel fuel at fixed prices from January 2017 through December 2017 for approximately $2.0 million.

 

Leases—The Company leases various mining, transportation and other equipment under operating leases. The Company also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the year ended December 31, 2016, the four months ended December 31, 2015 and the years ended August 31, 2015 and 2014 was as follows:

 

						Four months
		Year ended				ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
		(in thousands)
Lease expense		$	4,062			$	6			$	7				-
Royalty expense		$	8,115			$	-			$	-				-

 

 

Approximate future minimum lease and royalty payments (not including advance royalties already paid and recorded as assets in the accompanying consolidated balance sheet) are as follows:

 

Years Ending December 31,		Royalties				Leases
		(in thousands)
2017		$	1,640			$	2,533
2018			1,615				148
2019			1,665				-
2020			1,648				-
2021			1,767				-
Thereafter			8,836				-
Total minimum royalty and lease payments		$	17,171			$	2,681

 

Environmental Matters—Based upon current knowledge, the Company 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 Company 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.

 

Legal Matters—The Company 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 Company 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 Company. Management is also not aware of any significant legal, regulatory or governmental proceedings against or contemplated to be brought against the Company.

 

Guarantees/Indemnifications and Financial Instruments with Off-Balance Sheet Risk—In the normal course of business, the Company 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 balance sheet. The amount of bank letters of credit outstanding with PNC Bank, N.A., as the letter of credit issuer under the credit facility, was $26.1 million as of December 31, 2016. The bank letters of credit outstanding reduce the borrowing capacity under the credit facility. In addition, the Company has outstanding surety bonds with third parties of $48.9 million as of December 31, 2016 to secure reclamation and other performance commitments.

 

The credit facility is fully and unconditionally, jointly and severally guaranteed by Rhino and substantially all of its wholly owned subsidiaries. Borrowings under the credit facility are collateralized by the unsecured assets of Rhino and substantially all of its wholly owned subsidiaries. See Note12 for a more complete discussion of the Company’s debt obligations.

 

Joint Ventures—The Company may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012. The Company did not make any capital contributions to the Timber Wolf joint venture during the year ended December 31, 2016.

 

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

 

Blue Grove Coal, LLC (“Blue Grove”). On June 10, 2015, the Company acquired Blue Grove in exchange for 350,000 shares of its common stock. Blue Grove was owned 50% by Ian Ganzer, our chief operating officer, and 50% by Gary Ganzer, Ian Ganzer’s father (the “Members”). Simultaneous with the Company’s acquisition of Blue Grove, Blue Grove entered into an operator agreement with GS Energy, LLC, under which Blue Grove has an exclusive right to mine the coal properties of GS Energy for a two year period. During the term of the Operator Agreement, Blue Grove is entitled to all revenues from the sale of coal mined from GS Energy’s properties, and is responsible for all costs associated with the mining of the properties or the properties themselves, including operating costs, lease, rental or royalty payments, insurance and bonding costs, property taxes, licensing costs, etc. Simultaneous with the acquisition of Blue Grove, Blue Grove also entered into a Management Agreement with Black Oak Resources, LLC (“Black Oak”), a company owned by the Members. Under the Management Agreement, Blue Grove subcontracted all of its responsibilities under the Management Agreement with GS Energy to Black Oak. In consideration, Black Oak was entitled to 75% of all net profits generated by the mining of the coal properties of GS Energy. Subsequently, the agreement with Black Oak was amended to provide that Black Oak was entitled to 100% of the first $400,000 and 50% of the next $1,000,000, for a maximum of $900,000 of net profits generated by the mining of the coal properties of GS Energy.

 

The Members have an option to purchase the membership interests in Blue Grove from the Company. If exercised between ten and sixteen months after closing, the exercise price of the option is $50,000 less any dividends received on the shares of common stock issued in the acquisition, plus 90% of the shares issued to acquire Blue Grove. If exercised between sixteen and twenty-four months after closing, the exercise price of the option is 80% of the shares issued to acquire Blue Grove. The call option will terminate when (i) the parties agree it has terminated, (ii) when the Company pays the Members at least $1,900,000 to acquire their shares of common stock, or (iii) when a comparable option granted to the Members with respect to common stock issued to them to acquire GS Energy is terminated. The Company also has an option to sell the Blue Grove membership interests back to the Members. If exercised between ten and sixteen months after closing, the exercise price of the Company’s option is 90% of the common stock issued to the Ganzers to acquire Blue Grove. If exercised between sixteen and twenty-four months after closing, the exercise price of the Company’s option is 80% of the common stock issued to the Members to acquire Blue Grove.

 

On December 23, 2015, the Company and the Members entered into an Amendment to Securities Exchange Agreement (“Amendment”) originally entered into on June 8, 2015. Pursuant to the Amendment, the consideration for the acquisition of Blue Grove was reduced from 350,000 shares of the Company’s common stock to 10,000 shares. See Note 3.

 

Distributions on Common Units. Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2016, Rhino has suspended the cash distribution on its common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, Rhino paid cash distributions per common unit at levels lower than the minimum quarterly distribution. Rhino has not paid any distribution on its subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect its cash flow.

 

 

20. MAJOR CUSTOMERS

 

The Company 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):

 

 

						Four months
		Year ended				Ended				Year ended				Year ended
		December 31, 2016				December 31, 2015				August 31, 2015				August 31, 2014
		(in thousands)
Revenues
PPL Corporation		$	34,308			$	-			$	-				-
PacifiCorp Energy		$	14,923			$	-			$	-				-
Big Rivers		$	11,930			$	-			$	-				-
Alpha Natural Resources		$	-			$	-			$	281				-

 

		December 31, 2016				August 31, 2015
		(in thousands)
Accounts receivable
PPL Corporation		$	1,496			$	-
PacifiCorp Energy			1,509				-
Big Rivers			-				-
Alpha Natural Resources			-				44

 

21. FAIR VALUE MEASUREMENTS

 

The Company determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s assumptions of what market participants would use.

 

The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below:

 

	●	Level One - Quoted prices for identical instruments in active markets.
	●	Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs.
	●	Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity.

 

In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.

 

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 Company’s senior secured credit facility was determined based upon a market approach and approximates the carrying value at December 31, 2016. The fair value of the senior secured credit facility is a Level 2 measurement.

 

As of December 31, 2016, the Company had a recurring fair value measurement relating to its investment in Mammoth Energy Services, Inc. (“Mammoth, Inc.”). In October 2016, the Company contributed its limited partner interests in Mammoth to Mammoth Energy Services, Inc. (“Mammoth, Inc.”) in exchange for 234,300 shares of common stock of Mammoth, Inc. The common stock of Mammoth, Inc. began trading on the NASDAQ Global Select Market in October 2016 under the ticker symbol TUSK and the Company sold 1,953 shares during the initial public offering of Mammoth, Inc. and received proceeds of approximately $27,000. The Company’s remaining shares of Mammoth, Inc. are subject to a 180-day lock-up period from the date of Mammoth Inc.’s initial public offering and are classified as a held-for-sale investment on the Company’s consolidated balance sheet. Based on the availability of a quoted price, the recurring fair value measurement of the Mammoth, Inc. shares is a Level 2 measurement.

 

 

As of December 31, 2016, December 31, 2015 and August 31, 2015, the Company did not have any nonrecurring fair value measurements related to any assets held for sale.

 

For the years ended December 31, 2016, the four months ended December 31, 2015 and the year ended August 31, 2015, the Company had nonrecurring fair value measurements related to asset impairments as described in Note 6. The nonrecurring fair value measurements for the asset impairments were Level 3 measurements.

 

22. SEGMENT INFORMATION

 

The Company primarily produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah and sells primarily to electric utilities in the United States.

 

As of December 31, 2016, the Company has four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois Basin. Additionally, the Company has an Other category that includes its ancillary businesses.

 

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

 

Reportable segment results of operations and financial position for the year ended December 31, 2016 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization). The Company did not have a reportable segment prior to March 17, 2016.

 

		Central				Northern				Rhino				Illinois								Total
		Appalachia				Appalachia				Western				Basin				Other				Consolidated
Total assets		$	41,995			$	10,967			$	27,498			$	14,665			$	71,117			$	166,242
Total revenues			33,031				31,620				26,726				46,843				349				138,569
DD&A			1,215				577				992				1,681				38				4,503
Interest expense			1,579				201				312				784				1,421				4,297
Net income (loss) from continuing operations		$	(20,031	)		$	6,783			$	2,526			$	459			$	(3,934	)		$	(14,197	)

 

 

23. SUBSEQUENT EVENTS

 

On March 27, 2017, the Company filed a Certificate of Amendment to its Certificate of Incorporation which changed the authorized capital of the Company. The authorized preferred shares, par value $0.00001 per share was reduced from 10,000,000 shares to 5,000,000 shares and the authorized common shares, par value $0.00001 per share, was reduced from 500,000,000 shares to 25,000,000 shares.

 

On December 30, 2016, Royal entered into a Secured Promissory Note and a Pledge and Security Agreement with Weston Energy, LLC (“Weston”) under which Royal borrowed $2.0 million from Weston (the “Loan”). The Loan bore interest at 8% per annum and all principal and interest was due and payable on January 15, 2017, which date was later extended to January 31, 2017. The Loan was payable, at the option of Royal, either in cash, or in common units of Rhino. The proceeds of the Loan were used to make an investment of $2.0 million in 200,000 Series A Preferred Units of Rhino on December 30, 2016, at $10 per Series A Preferred Unit.

 

On January 27, 2017, Royal repaid the Loan in full by the payment of $1,000,000 cash to Weston and the sale to Weston of 100,000 Series A Preferred Units at $10 per Series A Preferred Unit. Royal funded the cash portion of the repayment of the Loan by selling its remaining 100,000 Series A Preferred Units to a third party for $10 per Series A Preferred Unit. As a result, Royal did not realize any gain or loss on its investment in the Series S Preferred Units.

 

 

24. SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)

 

		Three Months Ended
		March 31, 2016				June 30, 2016				September 30, 2016				December 31, 2016
Revenues		$	7,258			$	42,740			$	43,415			$	45,156
Cost and Expenses:
Cost of operations			3,994				33,860				35,249				38,531
Asset impairment			-				-				-				16,746
INCOME (LOSS) FROM OPERATIONS			624				2,337				1,425				(14,197	)
Income (loss) from continuing operations			249				577				(615	)			(14,364	)
Income from discontinued operations			-				-				650				-
Net income (loss) attributable to Company shareholders		$	157			$	382			$	(629	)		$	(14,274	)
Net income (loss) per share, basic and diluted:
Continuing operations		$	.01			$	.02			$	.04			$	(0.85	)
Discontinued operations			-				-				(.04	)			-
Total		$	.01			$	.02			$	-			$	(0.85	)

 

* Amount in 2nd Quarter of $13,300 recorded as asset impairment was reclassified as an adjustment to the original purchase price.

 

Amount in 3rd Quarter of $575 in discontinued operations and gains of $1,763 were reclassified as an adjustment to the original purchase price.

 

 

		Three Months Ended
		November 30, 2014				February 28, 2015				May 31, 2015				August 31, 2015
Revenues:		$	-			$	-			$	-			$	281
Cost of operations			-				-				-				283
INCOME (LOSS) FROM OPERATIONS			(11	)			(78	)			(49	)			(348	)
Income (loss)			(20	)			(80	)			(52	)			(350	)
Net income (loss) attributable to Company shareholders		$	(20	)		$	(80	)		$	(52	)		$	(350	)
Net income (loss) per share, basic and diluted:		$	(0.00	)		$	(0.01	)		$	(0.01	)		$	(0.03	)
		$	(0.00	)		$	(0.01	)		$	(0.01	)		$	(0.03	)