UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K/A

(Amendment No. 1)

[X]

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

For the fiscal year ended December 31, 2018

[ ]

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		11-3480036
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

56 Broad Street, Suite 2
Charleston, SC		29401
(Address of principal executive offices)		(Zip Code)

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

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

Title of each class		Trading Symbol(s)		Name of each Exchange on which registered
n/a		n/a		n/a

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 every Interactive Data File required to be submitted 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 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	[ ]	Non-accelerated filer	[ ]	Smaller reporting company	[X]
				(Do not check if a smaller reporting company)
Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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, 2018, 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 $18.4 million based on the closing price of the registrant’s common stock on the OTC Markets Bulletin Board on such date. As of March 20, 2019, the registrant had 18,579,293 shares of common stock (including 914,797 shares held by its consolidated subsidiary, Rhino Resource Partners, LP) 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	7

Item 2.	Properties	33

	PART IV

Item 15.	Exhibits, Financial Statement Schedules	37

EXPLANATORY NOTE

This Amendment No. 1 to the Annual Report of Royal Energy Resources, Inc. (the “Company”) on Form 10-K/A amends our Annual Report on Form 10-K for the year ended December 31, 2018 (the “Original 10-K”), which was originally filed on March 29, 2019.

We are filing this amendment to amend Items 1 and 2 of the original 10-K in order to provide additional information about our mining properties as required by Industry Guide 7, and in response to comments to the Original 10-K received from the staff of the Division of Corporate Finance of the Securities and Exchange Commission.

This Form 10-K/A also includes the currently dated signature page and certifications from the Company’s principal executive officer and principal financial officer. This Amendment No. 1 does not reflect other subsequent events occurring after the original filing date of the Original 10-K or modify or update in any way disclosures made in the Original 10-K except as noted above. This Amendment No. 1 should be read in conjunction with the Original 10-K and with other Company filings with the Securities and Exchange Commission subsequent to the filing of the Original 10-K.

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.

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.

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.

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.

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.

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;

	●	our future levels of indebtedness and compliance with debt covenants;

	●	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. On July 7, 2004, we revived our charter and changed our name to World Marketing, Inc. In December 2007, we changed our name to Royal Energy Resources, Inc.

Prior to March 2015, we were controlled by Jacob Roth, and pursued gold, silver, copper and rare earth metals mining concessions in Romania and mining leases in the United States. In a series of transactions occurring between January and April 2015, William L. Tuorto acquired control of our common stock from Mr. Roth. Mr. Roth and his affiliates resigned as our directors and officers, and Mr. Tuorto and his nominees became our directors and officers. We also disposed of our past operations, and Mr. Tuorto has repositioned us to focus on the acquisition of natural resources assets, including coal, oil, gas and renewable energy. 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. The value of the Mineral Rights was written down to $0 at December 31, 2017 due to deterioration in the market for coal properties in West Virginia, and the absence of current efforts to market or develop the Mineral Rights. In 2018, Blaze Minerals ceased to exist as a legal entity since its charter was revoked by the state of West Virginia and the time period lapsed to apply for reinstatement.

	●	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 owned 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 ARQ Gary Land, LLC, f/k/a Hendricks Gary Land, LLC (“ARQ”); 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. The value of the investment was written down to $1.8 million at December 31, 2017 due to an option to sell such investment for $1.8 million to ARQ. In 2018 the option expired, and the Company wrote the investment down to $0.

	●	As described in more detail below, we acquired control of the Partnership on March 17, 2016.

		On November 10, 2017, we entered into an Overriding Royalty Agreement to acquire a perpetual $4.00 per ton royalty for coal transported through a coal transloading terminal on the Ohio River. The original consideration was $400,000 of our common stock, or 100,000 shares, which was later amended to be a ten year option to purchase 100,000 shares of our common stock for $4.00 per share.

	●	We are currently evaluating a number of additional coal mining assets for acquisition.

Acquisition of Rhino GP LLC and Rhino Resource Partners LP (“the Partnership” or “Rhino”)

In the first quarter of 2016, Royal acquired control of the Partnership from Wexford Capital LP and certain of its affiliates (collectively, “Wexford”) in two different closings for aggregate consideration of $4,500,000. In the closings, Royal acquired all of the membership interests of Rhino GP, LLC (“Rhino GP”), the Partnership’s general partner, 676,912 common units (which represented 40% of the outstanding common units at the time) and 945,526 subordinated units (which represented 76.5% of the subordinated units at the time). In connection with the transaction, all of the directors of Rhino GP affiliated with Wexford resigned, and Royal appointed new directors.

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. On September 1, 2017, we elected to convert the $2.0 million promissory note and an additional $2.1 million note (including accrued interest) assigned from Weston Energy LLC into shares of Royal common stock. Royal issued 914,797 shares of its common stock to the Partnership at a conversion price of $4.51 per share.

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

Cedarview Loan

On June 12, 2017, we entered into a Secured Promissory Note dated May 31, 2017 with Cedarview Opportunities Master Fund, L.P. (the “Cedarview”), under which we borrowed $2,500,000 from Cedarview. The loan bears non-default interest at the rate of 14%, and default interest at the rate of 17% per annum. We and Cedarview simultaneously entered into a Pledge and Security Agreement dated May 31, 2017, under which we pledged 5,000,000 common units in Rhino as collateral for the loan. The loan is payable through quarterly payments of interest only until May 31, 2019, when the loan matures, at which time all principal and interest is due and payable. We deposited $350,000 of the loan proceeds into an escrow account, from which interest payments for the first year will be paid. After the first year, we are obligated to maintain at least one quarter of interest on the loan in the escrow account at all times. In consideration for Cedarview’s agreement to make the loan, we transferred 25,000 common units of Rhino to Cedarview as a fee. We intended to use the proceeds to repay in full all loans made to us by E-Starts Money Co. in the principal amount of $578,593, and the balance for general corporate overhead, as well as costs associated with potential acquisitions of mineral resource companies, including legal and engineering due diligence, deposits, and down payments.

On March 5, 2019, the Company modified the terms of the Cedarview note. The Company agreed to pay $1 million of the note balance by May 31, 2019 with the remaining balance of $1.5 million and associated accrued interest due May 31, 2020. The Company has paid a $45,000 loan extension fee to execute this agreement. All other terms of the note remain the same.

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. The Partnership’s 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 it issued subordinated units representing limited partner interests in it and common units to Wexford and issued incentive distribution rights to the Partnership’s general partner. In March 2016, Royal acquired the Partnership’s general partner and a majority limited partner interest in the Partnership from Wexford.

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, the Partnership has substantially increased its proven and probable coal reserves and non-reserve coal deposits. In addition, the Partnership has successfully grown its production through internal development projects.

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

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

Current Operations

The Partnership is a diversified coal producing limited partnership formed in Delaware that is focused on coal and energy related assets and activities. 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.

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, 2018, the Partnership controlled an estimated 268.5 million tons of proven and probable coal reserves, consisting of an estimated 214.0 million tons of steam coal and an estimated 54.5 million tons of metallurgical coal. Proven and probable coal reserves increased approximately 15.8 million tons from 2017 to 2018 primarily as the result of the revised economic feasibility of the Partnership’s non-reserve coal deposits. In addition, as of December 31, 2018, the Partnership controlled an estimated 164.1 million tons of non-reserve coal deposits, which decreased primarily due to the reclassification of non-reserve coal deposits to proven and probable reserves. Periodically, the Partnership retains outside experts to independently verify its coal reserve and its non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of its coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of December 31, 2018, and covered a majority of the coal reserves and non-reserve coal deposits that the Partnership controlled as of such date. The Partnership intends to continue to periodically retain outside experts to assist management with the verification of its estimates of our coal reserves and non-reserve coal deposits going forward.

The Partnership operates underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that the Partnership 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.

For the year ended December 31, 2018, the Partnership produced approximately 4.4 million tons of coal from continuing operations and sold approximately 4.6 million tons of coal from continuing operations.

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, the Partnership continues to seek opportunities to expand and diversify its operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. The Partnership believes that such assets will allow it to grow its cash available for distribution and enhance the stability of its cash flow.

Current Liquidity and Outlook of Rhino

As of December 31, 2018, the Partnership’s available liquidity was $6.6 million. The Partnership also has a delayed draw term loan commitment in the amount of $35 million contingent upon the satisfaction of certain conditions precedent specified in the financing agreement discussed below.

On December 27, 2017, the Partnership entered into a Financing Agreement (“Financing Agreement”), which provides it with a multi-draw loan in the aggregate principal amount of $80 million. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement and an additional $35 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. The Partnership used approximately $17.3 million of the net proceeds thereof to repay all amounts outstanding and terminate the Amended and Restated Credit Agreement with PNC Bank, National Association, as Administrative Agent. The Financing Agreement terminates on December 27, 2020. For more information about our new Financing Agreement, please read “— Recent Developments—Rhino - Financing Agreement.”

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

Recent Developments – Rhino

Financing Agreement

On December 27, 2017, the Partnership entered into the Financing Agreement pursuant to which Cortland Capital Market Services LLC, as Collateral Agent and Administrative Agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein (the “Lenders”) have agreed to provide the Partnership with a multi-draw term loan in the aggregate principal amount of $80 million, subject to the terms and conditions set forth in the Financing Agreement. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement (the “Effective Date Term Loan Commitment”) and an additional $35 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). Loans made pursuant to the Financing Agreement will be secured by substantially all of the Partnership’s assets. The Financing Agreement terminates on December 27, 2020.

On April 17, 2018, the Partnership amended the Financing Agreement to allow for certain activities including a sale leaseback of certain pieces of equipment, the due date for the lease consents was extended to June 30, 2018 and confirmation of the distribution to holders of the Series A preferred units of $6.0 million (accrued in our audited consolidated financial statements at December 31, 2017). Additionally, the amendments provided that the Partnership could sell additional shares of Mammoth Energy Services, Inc. (NASDAQ: TUSK) (“Mammoth, Inc.”) and retain 50% of the proceeds with the other 50% used to reduce debt. The Partnership reduced the debt by $3.4 million with proceeds from the sale of Mammoth Inc. stock in the second quarter of 2018.

On July 27, 2018, the Partnership entered into a consent with its Lenders related to the Financing Agreement. The consent included the lenders agreement to make a $5 million loan from the Delayed Draw Term Loan Commitment, which was repaid in full on October 26, 2018 pursuant to the terms of the consent. The consent also included a waiver of the requirements relating to the use of proceeds of any sale of the shares of Mammoth Inc. set forth in the consent to the Financing Agreement, dated as of April 17, 2018 and also waived any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended June 30, 2018.

On November 8, 2018, the Partnership entered into a consent with its Lenders related to the Financing Agreement. The consent includes the lenders agreement to waive any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended September 30, 2018.

On December 20, 2018, the Partnership entered into a limited waiver and consent (the “Waiver”) to the Financing Agreement. The Waiver relates to sales of certain real property in Western Colorado, the net proceeds of which are required to be used to reduce the debt under the Financing Agreement. As of the date of the Waiver, the Partnership had sold 9 individual lots in smaller transactions. Rather than transmitting net proceeds with respect to each individual transaction, the Partnership agreed with the Lenders in principle to delay repayment until an aggregate payment could be made at the end of 2018. On December 18, 2018, the Partnership used the sale proceeds of approximately $379,000 to reduce its debt to the Lenders. The Waiver (i) contains a ratification by the Lenders of the sale of the individual lots to date and waives the associated technical defaults under the Financing Agreement for not making immediate payments of net proceeds therefrom, (ii) permits the sale of certain specified additional lots and (iii) subject to Lender consent, permits the sale of other lots on a going forward basis. The net proceeds of future sales will be held by the Partnership until a later date to be determined by the Lenders.

On February 13, 2019, the Partnership entered into a second amendment (“Amendment”) to the Financing Agreement. The Amendment provides the Lender’s consent for the Partnership to pay a one-time cash distribution on February 14, 2019 to the Series A Preferred Unitholders an amount not to exceed approximately $3.2 million. The Amendment allows the Partnership to sell its remaining shares of Mammoth Energy Services, Inc. and utilize the proceeds for payment of the one-time cash distribution to the Series A Preferred Unitholders and waives the requirement to use such proceeds to prepay the outstanding principal amount outstanding under the Financing Agreement. The Amendment also waives any Event of Default that has or would otherwise arise under Section 9.01(c) of the Financing Agreement solely by reason of the Partnership failing to comply with the Fixed Charge Coverage Ratio covenant in Section 7.03(b) of the Financing Agreement for the fiscal quarter ending December 31, 2018. The Amendment includes an amendment fee of approximately $0.6 million payable by the Partnership on May 13, 2019 and an exit fee equal to 1% of the principal amount of the term loans made under the Financing Agreement that is payable on the earliest of (w) the final maturity date of the Financing Agreement, (x) the termination date of the Financing Agreement, (y) the acceleration of the obligations under the Financing Agreement for any reason, including, without limitation, acceleration in accordance with Section 9.01 of the Financing Agreement, including as a result of the commencement of an insolvency proceeding and (z) the date of any refinancing of the term loan under the Financing Agreement. The Amendment amends the definition of the Make-Whole Amount under the Financing Agreement to extend the date of the Make-Whole Amount period to December 31, 2019.

Common Unit Warrants

The Partnership entered into a warrant agreement with certain parties that are also parties to the Financing Agreement discussed above. The warrant agreement included the issuance of a total of 683,888 warrants of the Partnership’s common units (“Common Unit Warrants”) at an exercise price of $1.95 per unit, which was the closing price of the Partnership’s units on the OTC market as of December 27, 2017. The Common Unit Warrants have a five year expiration date. The Common Unit Warrants and the Rhino common units after exercise are both transferable, subject to applicable US securities laws. The Common Unit Warrant exercise price is $1.95 per unit, but the price per unit will be reduced by future common unit distributions and other further adjustments in price included in the warrant agreement for transactions that are dilutive to the amount of Rhino’s common units outstanding. The warrant agreement includes a provision for a cashless exercise where the warrant holders can receive a net number of common units. Per the warrant agreement, the warrants are detached from the Financing Agreement and fully transferable.

Letter of Credit Facility – PNC Bank

On December 27, 2017, the Partnership entered into a master letter of credit facility, security agreement and reimbursement agreement (the “LoC Facility Agreement”) with PNC Bank, National Association (“PNC”), pursuant to which PNC agreed to provide the Partnership with a facility for the issuance of standby letters of credit used in the ordinary course of its business (the “LoC Facility”). The LoC Facility Agreement provided that the Partnership pay a quarterly fee at a rate equal to 5% per annum calculated based on the daily average of letters of credit outstanding under the LoC Facility, as well as administrative costs incurred by PNC and a $100,000 closing fee. The LoC Facility Agreement provided that the Partnership reimburse PNC for any drawing under a letter of credit by a specified beneficiary as soon as possible after payment was made. The Partnership’s obligations under the LoC Facility Agreement were secured by a first lien security interest on a cash collateral account that was required to contain no less than 105% of the face value of the outstanding letters of credit. In the event the amount in such cash collateral account was insufficient to satisfy the Partnership’s reimbursement obligations, the amount outstanding would bear interest at a rate per annum equal to the Base Rate (as that term was defined in the LoC Facility Agreement) plus 2.0%. The Partnership was to indemnify PNC for any losses which PNC may have incurred as a result of the issuance of a letter of credit or PNC’s failure to honor any drawing under a letter of credit, subject in each case to certain exceptions. The Partnership provided cash collateral to its counterparties during the third quarter of 2018 and as of September 30, 2018, the LoC Facility was terminated. The Partnership had no outstanding letters of credit at December 31, 2018.

Distribution Suspension

Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended December 31, 2018, the Partnership 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, the Partnership announced cash distributions per common unit at levels lower than the minimum quarterly distribution. 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 the Partnership’s cash flow.

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, 2018, the Partnership has accumulated arrearages at December 31, 2018 related to the common unit distribution of approximately $673.1 million.

Coal Operations

Mining and Leasing Operations

As of December 31, 2018, the Partnership operated two mining complexes located in Central Appalachia (Tug River and Rob Fork). In addition, during 2018, the Partnership operated one mining complex located in Northern Appalachia (Hopedale). The other Northern Appalachia mining complex, Sands Hill Mining, was sold in November 2017. In the Western Bituminous region, the Partnership operated one mining complex located in Emery and Carbon Counties, Utah (Castle Valley). The Partnership also operated a mining complex in the Illinois Basin, the Riveredge mine at its Pennyrile mining complex. (See Note 4 of the consolidated financial statements included elsewhere in this annual report for further information on the disposition of Sands Hill Mining)

The Partnership defines a mining complex as a central location for processing raw coal and loading coal into railroad cars, barges or trucks for shipment to customers. These mining complexes include five active preparation plants and/or loadouts, each of which receive, blend, process and ship coal that is produced from one or more of our 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 the Partnership’s coal mining and leasing operations as of December 31, 2018 (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 the Partnership’s mining operations. The Partnership employs preventive maintenance and rebuild programs to ensure that the Partnership’s 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 from continuing operations by region as of December 31, 2018.

Region

Preparation Plants and Loadouts

Transportation to Customers (1)

Number and Type of
Active Mines (2)

Tons Produced for the Year Ended

December 31, 2018 (3)

Tons Produced for the Year Ended

December 31, 2017 (3)

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)

1.2

0.9

0.4

Rob Fork Complex (KY)

Rob Fork

Truck, Barge, Rail (CSX)

1U,1S

0.5

0.6

0.3

Northern Appalachia(5)

Hopedale Complex (OH)

Nelms

Truck, Rail (OHC, WLE)

0.4

0.3

Illinois Basin

Taylorville Field (IL)

n/a

Rail (NS)

—

Pennyrile Complex (KY)

Preparation plant & river loadout

Barge

1.3

Western Bituminous

Castle Valley Complex (UT)

Truck loadout

Truck

1.0

0.9

McClane Canyon Mine (CO)(6)

n/a

Truck

—

Total

4U,3S

4.4

4.2

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 the Partnership’s mines as of December 31, 2018 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)	The Sands Hill Mining complex was previously included in the Partnership’s Northern Appalachia region and was sold in November 2017.

(6)	The McClane Canyon mine was permanently idled as of December 31, 2013.

The following table provides the number of coal acres leased and owned, the mineralization and power source for each of the Partnership’s mining complexes by region as of December 31, 2018.

	Coal Acres		Coal Acres		Coal Acres		Formation				Power
Region	Owned		Leased		Total		Age		Rock Types		Source
Central Appalachia
Tug River Complex - CAM Mining LLC (WV)		3,178		4,582		7,761		Pennsylvanian		sandstone, siltstone, shale, coal		Appalachian Power Company
Rob Fork Complex - CAM Mining LLC (KY)		2,160		3,342		5,502		Pennsylvanian		sandstone, siltstone, shale, coal		Kentucky Power Company
Rhino Eastern Complex - Rhino Eastern LLC (WV)		-		13,183		13,183		Pennsylvanian		sandstone, siltstone, shale, coal		Appalachian Power Company
Rich Mountain - Springdale Land Company (WV)		3,161		-		3,161		Pennsylvanian		sandstone, siltstone, shale, coal		MonPower
Total Central Appalachia		8,499		21,108		29,607
Northern Appalachia
Cadiz Field - Hopedale Mining LLC (OH)		1,063		3,622		4,685		Pennsylvanian		sandstone and shale, coal		American Electric Power
Leesville Field - Leesville Land Company (OH)		-		-		-		Pennsylvanian		sandstone and shale, coal		South Central Power Company
Springdale Field - Springdale Land Company (PA)		3,998		-		3,998		Pennsylvanian		sandstone and shale, coal		PPL Electric
Total Northern Appalachia		5,061		3,622		8,683
Illinois Basin
Taylorville Field - Taylorville Mining LLC (IL)		-		15,930		15,930		Pennsylvanian		sandstone and shale, coal		Ameren Illinois
Riveredge Mine Complex - Pennyrile Energy LLC (KY)		44		6,890		6,934		Pennsylvanian		sandstone and shale, coal		Kenergy Corporation
Total Illinois Basin		44		22,821		22,864
Western Bituminous
Castle Valley Complex - Castle Valley Mining LLC (UT)		-		1,658		1,658		Upper Cretaceous		sandstone and shale, coal		Rocky Mountain Power
McClane Canyon Mine - McClane Canyon LLC (CO)		18		848		866		Upper Cretaceous		sandstone and shale, coal		Grand Valley Power
Total Western Bituminous		18		2,506		2,524
Grand Total		13,622		50,056		63,678

Central Appalachia. For the year ended December 31, 2018, 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, 2018, the mines at the Partnership’s Tug River and Rob Fork mining complexes produced an aggregate of approximately 1.2 million tons of steam coal and an estimated 0.5 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 company-operated 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 1.0 million tons of steam coal and approximately 0.2 million tons of metallurgical coal for the year ended December 31, 2018.

Rob Fork Mining Complex. The Partnership’s Rob Fork mining complex is located in eastern Kentucky and produces coal from one company-operated surface mine and one company-operated 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 0.2 million tons of steam coal and 0.3 million tons of metallurgical coal for the year ended December 31, 2018.

Northern Appalachia. For the year ended December 31, 2018, the Partnership operated one mining complex located in Northern Appalachia consisting of one company-operated underground mine. For the year ended December 31, 2018, the mine produced an aggregate of approximately 0.4 million tons of steam coal. The Partnership sold the Partnership’s Sands Hill Mining operation in November 2017, which consisted of one company-operated surface mine.

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 cleaned at the Partnership’s Nelms preparation plant located on the Ohio Central Railroad and the Wheeling & Lake Erie Railroad and then shipped by train or truck to the Partnership’s customers. The infrastructure includes a full-service loadout facility. This underground mining operation produced approximately 0.4 million tons of steam coal for the year ended December 31, 2018.

Western Bituminous Region. The Partnership operate 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 include 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 1.0 million tons of steam coal from one underground mine at this complex for the year ended December 31, 2018.

Illinois Basin. The Partnership operates one mining complex in the Illinois Basin region that produces coal from an underground mine located in Daviess and McLean counties in western Kentucky contiguous to the Green River. The Partnership also have an estimated 111.1 million of proven and probable reserves in the Taylorville Field area in the Illinois Basin that remain undeveloped.

Pennyrile Mining Complex. In mid-2014, the Partnership completed the initial construction of a new underground mining operation on the purchased property, referred to as the Partnership’s Pennyrile mining complex, which includes one underground mine, a preparation plant and river loadout facility. The property is adjacent to a navigable waterway, which allows for exports to non-U.S. customers. The Partnership produced approximately 1.3 million tons of steam coal from this mine for the year ended December 31, 2018. The Partnership believe the possibility exists to expand production up to 2.0 million tons per year with further development of the mine at the Pennyrile complex.

Other Non-Mining Operations

In addition to the Partnership’s mining operations, it operates various subsidiaries which provide auxiliary services for its coal mining operations. 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 the its drilling and blasting activities at the Partnership’s company-operated 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 December 2012, the Partnership made an initial investment in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. In November 2014, the Partnership contributed its investment interest in Muskie to Mammoth Energy Partners LP (“Mammoth”) in return for a limited partner interest in Mammoth. In October 2016, the Partnership contributed its limited partner interests in Mammoth to Mammoth Energy Services, Inc. (NASDAQ: TUSK) (“Mammoth Inc.”) in exchange for 234,300 shares of common stock of Mammoth, Inc.

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”). 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 for the years ended December 31, 2017 of approximately $36,000. In June 2017, the Partnership contributed its limited partner interests in Sturgeon to Mammoth Inc. in exchange for 336,447 shares of common stock of Mammoth Inc. As of December 31, 2018, the Partnership owned 104,100 shares of Mammoth Inc.

As of December 31, 2018 and 2017, the Partnership has recorded its investment in Mammoth Inc. as a short-term asset, which the Partnership has classified as equity securities.

Coal Customers - Rhino

General

The Partnership’s primary customers for its steam coal are electric utilities and industrial consumers, and the metallurgical coal the Partnership produces is sold primarily to domestic and international steel producers and coal brokers. For the year ended December 31, 2018, approximately 81% of its coal sales tons consisted of steam coal and approximately 19% consisted of metallurgical coal. For the year ended December 31, 2018, approximately 40% 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, 2018, the Partnership derived approximately 80% of its total coal revenues from sales to its ten largest customers, with affiliates of its top three customers accounting for approximately 40.4% of its coal revenues for that period.

Coal Supply Contracts

For the year ended December 31, 2018 and 2017, approximately 64% and 59%, respectively, 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, 2018, the Partnership had commitments under supply contracts to deliver annually scheduled base quantities as follows:

Year	Tons (in thousands)		Number of customers
2019		3,699		18
2020		1,979		6
2021		352		2

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. 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 mines is 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 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 seeks 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, Blackhawk Mining, LLC, Murray Energy Corporation, Foresight Energy LP, and Wolverine Fuels, 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.

Segments

We operate as a single primary reportable segment relating to our coal investments. We have some general corporate assets that we break out separately as unallocated corporate assets in the segment disclosure. All of our revenues relate to the coal segment. See Part II. “Item 8. Financial Statements and Supplementary Data” for our segment disclosure.

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 the Partnership’s customers are subject to extensive regulation regarding the environmental impacts associated with the combustion or other use of coal, which could affect demand for their 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 the Partnership’s mining operations or their 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 their 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

Mining Permits and Approvals

Numerous governmental permits or approvals are required for coal mining operations. When the Partnership applies for these permits and approvals, they are often required to assess the effect or impact that any proposed production of coal may have upon the environment. 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, the Partnership’s 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. 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. The Partnership 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, the Partnership has been cited for violations in the ordinary course of business. However, the Partnership has 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, the Partnership 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 the Partnership operates 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 the Partnership’s 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 their mines. In addition, the Partnership’s 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 they allocate to health and safety matters, their 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. The Partnership continually monitors the performance of their 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 their compensation and retention decisions. For instance, their bonus program includes a meaningful evaluation of each eligible employee’s role in complying with, fostering and furthering their safety policies.

The Partnership evaluates a variety of safety-related metrics to assess the adequacy and performance of their safety management system. For example, the Partnership monitors and tracks 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 the Partnership’s 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 their performance relative to certain national benchmarks.

For the year ended December 31, 2018 the Partnership’s average MSHA violations per inspection day was 0.39 as compared to the most recent national average of 0.59 violations per inspection day for coal mining activity as reported by MSHA, or 33.89% 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. 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 their 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.

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 the Partnership’s 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, 2018 (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. The Partnership believes 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, the Partnership provides additional details on how they monitor 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 $0.50 per ton for underground-mined coal and $0.25 per ton for surface-mined coal, but not to exceed 2.0% of the applicable sales price (rates effective January 1, 2019). This excise tax does not apply to coal that is exported outside of the United States. In 2018, the Partnership recorded approximately $2.5 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 the Partnership’s costs expended in association with the federal black lung program. The Partnership 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 their mines and other facilities, and its costs of addressing these claims. The Partnership is insured under the Ohio State Workers Compensation Program for their operations in Ohio. Its remaining operations 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. Should this fee be increased in the future, 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, 2018, the Company had accrued approximately $15.6 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 basis 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, 2018, we had approximately $42.6 million in surety bonds outstanding to secure the performance of our reclamation obligations. Of the $42.6 million, approximately $0.4 million relates to surety bonds for Deane Mining, LLC and approximately $3.4 million relates to surety bonds for Sands Hill Mining, LLC, which in each case have not been transferred or replaced by the buyers of Deane Mining, LLC or Sands Hill Mining, LLC as was agreed to by the parties as part of the transactions. We can provide no assurances that a surety company will underwrite the surety bonds of the purchasers of these entities, nor are we aware of the actual amount of reclamation at any given time. Further, if there was a claim under these surety bonds prior to the transfer or replacement of such bonds by the buyers of Deane Mining, LLC or Sands Hill Mining, LLC, then we may be responsible to the surety company for any amounts it pays in respect of such claim. While the buyers are required to indemnify us for damages, including reclamation liabilities, pursuant the agreements governing the sales of these entities, we may not be successful in obtaining any indemnity or any amounts received may be inadequate.

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. In September 2016, EPA finalized the CSAPR Rule Update for the 2008 ozone national air quality standards (“NAAQS”). The rule aims to reduce summertime NOx emissions from power plants in 22 states in the eastern United States. Consolidated judicial challenges to the rule are now pending in the D.C. Circuit Court of Appeals.

	●	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. Various legal challenges were filed and EPA promulgated a revised final rule in November 2015. In December 2016, the D.C. Circuit remanded the Boiler MACT standards to the EPA requiring the agency to revise emissions standards for certain boiler subcategories. The court determined that the existing MACT standards should remain in place while the revised standards are being developed, but did not establish a deadline for the EPA to complete the rulemaking. In June 2017, the U.S. Supreme Court declined to review the D.C. Circuit ruling. We cannot predict the outcome of any legal challenges that may be filed in the future. Before reconsideration, the EPA estimated that the rule would 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 that cannot be determined at this time.

	●	The EPA has adopted new, more stringent 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. The EPA completed area designations for the 2015 ozone standards in July 2018. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and customers could be affected when the standards are implemented by the applicable states. Moreover, we could face adverse impacts on our business to the extent that these and any other new rules affecting coal-fired power plants result in reduced demand for coal.

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.

Climate Change

One by-product of burning coal is carbon dioxide or CO₂, which EPA considers a GHG and a major source of concern with respect to climate change and global warming.

On the international level, the United States was 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; however, in August 2017 the U.S. State Department officially informed the United Nations of the intent of the U.S. to withdraw from the agreement, with the earliest possible effective date of withdrawal being November 4, 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. These commitments could further reduce demand and prices for coal.

At the Federal level, EPA has taken a number of steps to regulate GHG emissions. For example, in August 2015, the EPA issued its final Clean Power Plan (the “CPP”) rules that establish carbon pollution standards for power plants, called CO₂emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay of the implementation of the CPP in February 2016. By its terms, this stay will remain in effect throughout the pendency of the appeals process. 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 courts will rule on the legality of the CPP. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with the proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the effort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of the appellate process and were implemented in their current form or if the ANPRM results in a different proposal to control GHG emissions from electric utility generating units, 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 we mine and sell, thereby reducing the Partnership’s revenues and materially and adversely affecting their 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 their coal.

If mandatory restrictions on CO₂ 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. For example, 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.

There have also been attempts to encourage greater regulation of coalbed methane because methane has a greater GHG effect than CO2. Methane from coal mines can give rise to safety concerns, and may require that various measures be taken to mitigate those risks. If new laws or regulations were introduced to reduce coalbed methane emissions, those rules could adversely affect the Partnership’s costs of operations.

These and other current or future global climate change laws, regulations, court orders or other legally enforceable mechanisms, or related public perceptions regarding climate change, are expected to require additional controls on coal-fired power plants and industrial boilers and may cause some users of coal to further switch from coal to alternative sources of fuel, thereby depressing demand and pricing for coal.

Finally, some scientists have warned that increasing concentrations of greenhouse gases (“GHGs”) in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If these warnings are correct, and if any such effects were to occur in areas where the Partnership or their customers operate, they could have an adverse effect on their assets and operations.

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 our operations. Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the Clean Water Act. A 2015 rulemaking by EPA to revise the standard was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit and stayed for certain primarily western states by a United States District Court in North Dakota. In January 2018, the Supreme Court determined that the circuit courts do not have jurisdiction to hear challenges to the 2015 rule, removing the basis for the Sixth Circuit to continue its nationwide stay. Additionally, EPA has promulgated a final rule that extends the applicability date of the 2015 rule for another two years in order to allow EPA to undertake a rulemaking on the question of what constitutes a water of the United States. In the meantime, judicial challenges to the 2015 rulemaking are likely to continue to work their way through the courts along with challenges to the recent rulemaking that extends the applicability date of the 2015 rule. For now, EPA and the Corps will continue to apply the existing standard for what constitutes a water of the United States as determined by the Supreme Court in the Rapanos case and post-Rapanos guidance. Should the 2015 rule take effect, or should a different rule expanding the definition of what constitutes a water of the United States be promulgated as a result of EPA and the Corps’s rulemaking process, 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.” The Court previously upheld the EPA’s ability to exercise this authority. 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 their 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. The Partnership 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 NWP 21 issued in January of 2017. If the 2017 NWP 21 cannot be used for any of the Partnership’s proposed surface coal mining projects, the Partnership 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.

The Partnership currently has 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. The Partnership 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 their applications may not be granted or, alternatively, the Corps may require material changes to their proposed operations before it grants permits. While the Partnership will continue to pursue the issuance of these permits in the ordinary course of their operations, to the extent that the permitting process creates significant delay or limits the Partnership’s ability to pursue certain reserves beyond their current five year plan, their 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 the Partnership’s coal mines could limit their ability to obtain NPDES permits, require more costly water treatment, and adversely affect their coal production.

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. The Partnership is 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 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, the Partnership does 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 chemical facility security regulatory program.

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. The Partnership is 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.

Federal Power Act – Grid Reliability Proposal

Pursuant to a direction from the Secretary of the Department of Energy, the Federal Energy Regulatory Commission (“FERC”) issued a notice of proposed rulemaking under the Federal Power Act regarding the valuation by regional electric grid system operators of the reliability and resilience attributes of electricity generation. The rulemaking would have required the FERC to impose market rules that would allow certain cost recovery by electricity-generating units that maintain a 90-day fuel supply on-site and that are therefore capable of providing electricity during supply disruptions from emergencies, extreme weather or natural or man-made disasters. Many coal-fired electricity generating plants could have qualified under this criteria and the cost recovery could have helped improve the economics of their operations. However, in January 2018, the FERC terminated the proposed rulemaking, finding that it failed to satisfy the legal requirements of section 206 of the Federal Power Act, and initiated a new proceeding to further evaluate whether additional FERC action regarding resilience is appropriate. Should a version of this rule be adopted in the future along the lines originally proposed, it could provide economic incentives for companies that produce electricity from coal, among other fuels, which could either slow or stabilize the trend in the shuttering of coal-fired power plants and could thereby maintain certain levels of domestic demand for coal. We cannot speculate on the timing or nature of any subsequent FERC or grid operator actions resulting from the FERC’s decision to further study the issue of grid resiliency.

Employees

We and our subsidiaries employed 702 full-time employees as of December 31, 2018. None of the employees are subject to collective bargaining agreements. We believe that we have 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 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

Reserves are defined by the SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Reserves are further classified as proven or probable according to the degree of certainty of existence. The terms and criteria utilized to estimate reserves for this study are based on United States Geological Survey Circular 891 and in general accordance with SEC Industry Guide 7, and are summarized as follows:

	●	Proven (Measured) Reserves: Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; and 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.

	●	Probable (Indicated) Reserves: 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.

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 outside expert performs an independent pro forma economic analysis using industry-accepted guidelines and this is used, in part, to classify tonnage as either reserve or resource, based on current market conditions. The outside expert reviews updated coal market sales price data provided by another third party, along with mine operating cost information supplied by us. Economic feasibility is considered to classify a coal deposit as either a reserve or a resource by evaluating coal thickness, overburden thickness, coal quality, costs of mining, processing, transportation, and expected selling price, among other factors. For the surface mining resource areas, the mining costs are estimated using the surface mining overburden ratios provided in the reserve evaluation. Direct mining costs are estimated for labor, blasting, fuel and lubrication supplies, repairs and maintenance, operating supplies, and other costs. The pro forma mining cost estimates for underground mining areas begin with the computation of representative total seam thickness for each area evaluated. The clean-tons-per-foot of mining advance is calculated to support mine production and productivity calculations. All underground and highwall miner coal resources is expected to require washing to remove coal partings and out-of-seam contamination. Preparation plant yield is calculated by multiplying the in-seam recovery, out-of-seam contamination, and plant efficiency factors. In-seam recovery factors is obtained from summaries of the available laboratory analyses and coal quality data. Direct mining costs are estimated for labor, supplies, maintenance and repairs, mine power and other direct mining costs. Sales, general and administration and environmental cost allocations are based on values typically observed by the third party expert. Sales variable costs for royalty payments, black lung excise tax and reclamation fees are calculated, along with cost components for other indirect mining costs and depreciation, depletion and amortization. Coal reserves are considered to be economically recoverable at a price in excess of the cash costs to mine the coal.

The most recent audit by an independent engineering firm of our coal reserve and non-reserve coal deposit estimates was completed by Marshall Miller & Associates, Inc. as of December 31, 2018, and covered a majority of the coal reserves and non-reserve coal deposits that we controlled as of such date. 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.

We have 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, 2018, we controlled an estimated 268.5 million tons of proven and probable coal reserves, consisting of an estimated 214.0 million tons of steam coal and an estimated 54.5 million tons of metallurgical coal. Proven and probable coal reserves increased approximately 15.8 million tons from 2017 to 2018 primarily as the result of the revised economic feasibility of our non-reserve coal deposits. In addition, as of December 31, 2018, we controlled an estimated 164.1 million tons of non-reserve coal deposits, which decreased primarily due to the reclassification of non-reserve coal deposits to proven and probable reserves. For the year ended December 31, 2018, we purchased and sold 331 tons of third-party coal.

Substantially all of our reserves in the Central Appalachia and Western Bituminous regions are marketable as compliance coal under Phase II of the Federal Clean Air Act, while our reserves in the Northern Appalachian and Illinois Basin are not marketable as compliance coal. Compliance coal is defined by Phase II of the Federal Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.

Coal Reserves

The following table provides information as of December 31, 2018 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)		23.0		19.8			3.2			18.8			4.3			9.2			13.8			13.0			10.0
Rob Fork Complex (KY)		14.0		12.9			1.1			14.0			-			6.4			7.6			11.6			2.4
Rhino Eastern Field (WV) (3)		33.9		19.4			14.4			29.1			4.7			-			33.9			-			33.9
Rich Mountain Field (WV)		8.2		2.7			5.5			-			8.2			8.2			-			-			8.2
Total Central Appalachia (5)		79.1		54.8			24.2			61.9			17.2			23.8			55.3			24.6			54.5
Northern Appalachia
Hopedale Complex (OH)		18.6		15.2			3.5			18.6			-			4.0			14.6			18.6			-
Leesville Field (OH)		-		-			-			-			-			-			-			-			-
Springdale Field (PA)		13.7		8.8			4.9			-			13.7			13.7			-			13.7			-
Total Northern Appalachia (5)		32.3		24.0			8.4			18.6			13.7			17.7			14.6			32.3			-
Illinois Basin
Taylorville Field (IL)		111.1		38.9			72.3			-			111.1			-			111.1			111.1			-
Pennyrile Complex (KY)		24.9		14.1			10.7			24.9			-			0.2			24.7			24.9			-
Total Illinois Basin (5)		136.0		53.0			83.0			24.9			111.1			0.2			135.8			136.0			-
Western Bituminous
Castle Valley Complex (UT)		14.9		11.3			3.6			14.9			-			-			14.9			14.9			-
McClane Canyon Mine (CO) (4)		6.2		4.1			2.1			6.2			-			0.1			6.1			6.2			-
Total Western Bituminous (5)		21.1		15.4			5.7			21.1			-			0.1			21.0			21.1			-
Total (5)		268.5		147.2			121.3			126.5			142.0			41.8			226.7			214.0			54.5
Percentage of total (5)				54.8	%		45.2	%		47.1	%		52.9	%		15.6	%		84.4	%		79.7	%		20.3	%

	(1)	Represents recoverable tons. The recoverable tonnage estimates take into account mining losses and coal wash plant losses of material from both mining dilution and any non-coal material found within the coal seams. Except for coal expected to be processed and sold on a direct-shipped basis, a specific wash plant recovery factor has been estimated from representative exploration data for each coal seam and applied on a mine-by-mine basis to the estimates. Actual wash plant recoveries vary depending on customer coal quality specifications.

	(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, 2018.

	(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 reserves 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. Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun. These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.

The following table provides information on particular characteristics of our coal reserves as of December 31, 2018:

	As Received Basis (1)										Proven and Probable Coal Reserves (2)
													Sulfur Content
Region	% Ash			% Sulfur			Btu/lb.		S02/mm Btu		Total		<1%			1-1.5%			>1.5%			Unknown
											(in million tons)
Central Appalachia
Tug River Complex (KY, WV)		9.42	%		1.19	%		13,145		1.80		23.0		9.9			9.7			2.5			0.9
Rob Fork Complex (KY)		5.41	%		1.26	%		13,527		1.87		14.0		6.5			4.3			1.6			1.6
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		6.24	%		0.91	%		13,611		1.34		79.1		53.4			18.9			4.1			2.7
Northern Appalachia
Hopedale Complex (OH)		6.66	%		2.26	%		13,738		3.30		18.6		-			-			18.6			-
Springdale Field (PA)		7.08	%		1.91	%		13,337		2.87		13.7		-			-			13.7			-
Total Northern Appalachia		6.84	%		2.11	%		13,568		3.11		32.3		-			-			32.3			-
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		24.9		-			-			24.9			-
Total Illinois Basin		7.76	%		3.35	%		11,133		6.01		136.0		-			-			136.0			-
Western Bituminous
Castle Valley Complex (UT)		10.58	%		0.90	%		12,055		1.49		14.9		5.3			9.6			-			-
McClane Canyon Mine (CO) (4)		11.19	%		0.57	%		11,241		1.01		6.2		6.2			-			-			-
Total Western Bituminous		10.76	%		0.80	%		11,814		1.36		21.1		11.5			9.6			-			-
Total (5)		7.45	%		2.29	%		12,194		3.76		268.5		64.9			28.5			172.4			2.7
Percentage of total (5)														24.2	%		10.6	%		64.2	%		1.0	%

	(1)	As received basis represents average quality on a moist basis.

	(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, 2018.

	(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, 2018:

	Non-Reserve Coal Deposits
			Total Tons
Region	Total Tons		Owned			Leased
		(in million tons)
Central Appalachia		38.0		10.7			27.3
Northern Appalachia		60.6		55.8			4.8
Illinois Basin		35.9		-			35.9
Western Bituminous		29.6		-			29.6
Total		164.1		66.5			97.6
Percentage of total				40.52	%		59.48	%

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.

Office Facilities

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

The Partnership leases 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 2018 to extend the lease term for five additional years to July 31. 2023.

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

Filed previously with the registrant’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “Original 10-K”), which was originally filed on March 29, 2019, and which are incorporated herein by reference.

(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.

EXHIBIT LIST

Exhibit Number	Description	Filer

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

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

The registrant incorporates by reference all exhibits filed with the Original 10-K or incorporated by reference to other reports therein.

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/ Richard A. Boone
		Richard A. Boone
		Chief Executive Officer

Date: December 06, 2019

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/ Richard A. Boone	Chief Executive Officer and Director (Principal Executive Officer)	December 06, 2019
Richard A. Boone

/s/ Wendell S. Morris	Chief Financial Officer (Principal Financial and Accounting Officer)	December 06, 2019
Wendell S. Morris

/s/ William L. Tuorto	Director	December 06, 2019
William L. Tuorto

Royal Energy Resources, Inc. 10-K/A