UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended: September 30, 2017

 

or

 

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from:

 

Royal Energy Resources, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware		000-52547		11-3480036
(State or Other Jurisdiction of		(Commission		(I.R.S. Employer
Incorporation or Organization)		File Number)		Identification No.)

 

56 Broad Street, Suite 2, Charleston, SC 29401

(Address of Principal Executive Offices) (Zip Code)

 

843-900-7693

(Registrant’s telephone number, including area code)

 

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 [  ] No [X]

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, emerging growth company or a smaller reporting company.

 

	Large accelerated filer [  ]	Accelerated filer [X]	Non-accelerated filer [  ]	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 Securities Act. [  ]

 

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

 

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date: 18,079,293 shares of common stock issued and outstanding as of November 8, 2017.

 

 

 

TABLE OF CONTENTS

 

		Page
PART I – FINANCIAL INFORMATION		4
ITEM 1:	Financial Statements	4
ITEM 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
ITEM 3:	Quantitative and Qualitative Disclosures About Market Risk	60
ITEM 4:	Controls and Procedures	60
PART II - OTHER INFORMATION		61
Item 1:	Legal Proceedings	61
ITEM 1A:	Risk Factors	61
ITEM 2:	Unregistered Sales of Equity Securities and Use of Proceeds	61
ITEM 3:	Defaults upon Senior Securities.	61
ITEM 4:	Mine Safety Disclosures.	62
ITEM 5:	Other Information.	62
ITEM 6:	Exhibits	62
SIGNATURES		63

 

 

Cautionary Note Regarding Forward-Looking Statements

 

This Quarterly Report on Form 10-Q contains certain “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 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 forecasted in these statements.

 

Any differences could be caused by a number of factors, including, but not limited to: our ability to maintain adequate cash flow and to obtain financing necessary to fund our capital expenditures, meet working capital needs and maintain and grow our operations or our ability to obtain alternative financing upon the expiration of our amended and restated senior secured credit facility and our related ability to continue as a going concern; our future levels of indebtedness and compliance with debt covenants; sustained depressed levels of or further decline 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. Other factors that could cause our actual results to differ from our projected results are described elsewhere in (1) this Form 10-Q, (2) our Annual Report on Form 10-K for the year ended December 31, 2016, (3) our reports and registration statements filed from time to time with the Securities and Exchange Commission and (4) other announcements we make from time to time. In addition, we may be subject to unforeseen risks that may have a materially adverse effect on us. Accordingly, no assurances can be given that the actual events and results will not be materially different from the anticipated results described in the forward-looking statements.

 

The forward-looking statements speak only as of the date made, and, other than as required by law, 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.—FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands)

 

		September 30, 2017				December 31, 2016
		(Unaudited)				(Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	1,416			$	86
Accounts receivable, less allowance for bad debts of $0 as of September 30, 2017 and December 31, 2016			18,467				13,893
Inventories			11,334				8,050
Advance royalties, current portion			653				898
Investment in available for sale securities			9,590				3,532
Prepaid expenses and other			4,653				4,929
Total current assets			46,113				31,388
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs			247,789				69,684
Less accumulated depreciation, depletion and amortization			(41,030	)			(4,572	)
Net property, plant and equipment			206,759				65,112
Advance royalties, net of current portion			7,847				7,652
Investment in unconsolidated affiliates			130				5,121
Intangible purchase option			21,750				21,750
Goodwill			-				7,594
Intangible assets, less accumulated amortization of $101 and $67, respectively			-				34
Other non-current assets			27,694				27,591
TOTAL		$	310,293			$	166,242
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable			11,954				10,447
Accrued expenses and other			12,435				11,405
Accrued preferred distributions			4,118				-
Notes payable-related party			504				504
Current portion of long-term debt			9,940				12,040
Current portion of asset retirement obligations			917				917
Related party advance and accrued interest payable			42				71
Total current liabilities			39,910				35,384
NON-CURRENT LIABILITIES:
Deferred tax liability			43,396				-
Long-term debt, net of current portion			2,500				-
Asset retirement obligations, net of current portion			20,497				26,503
Other non-current liabilities			40,319				39,073
Total non-current liabilities			106,712				65,576
Total liabilities			146,622				100,960
COMMITMENTS AND CONTINGENCIES (NOTE 16)
STOCKHOLDERS’ EQUITY
Preferred stock: $0.00001 par value; authorized 5,000,000 shares; 51,000 issued and outstanding at September 30, 2017 and authorized 10,000,000 shares; 51,000 issued and outstanding at December 31, 2016.
Common stock: $0.00001 par value; authorized 25,000,000 shares; 18,079,293 shares issued and outstanding at September 30, 2017 and authorized 500,000,000; 17,212,278 shares issued and outstanding at December 31, 2016.			1				1
Additional paid-in capital			46,861				47,295
Stock subscription receivable			-				(213	)
Accumulated other comprehensive income			1,440				874
Treasury Stock			(4,126	)			-
Retained earnings (accumulated deficit)			90,415				(20,579	)
Total stockholders’ equity owned by common shareholders			134,591				27,378
Non-controlling interest			29,080				37,904
Total stockholders’ equity owned by common shareholders			163,671				65,282
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	310,293			$	166,242

 

See notes to unaudited condensed consolidated financial statements.

 

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands, except per unit data)

 

		Three Months								Nine Months
		Ended September 30,								Ended September 30,
		2017				2016				2017				2016
REVENUES:
Coal sales		$	56,460			$	40,992			$	162,951			$	86,675
Freight and handling revenues			220				424				537				1,106
Other revenues			1,666				1,999				4,944				3,406
Total revenues			58,346				43,415				168,432				91,187
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			46,376				35,249				137,898				72,648
Freight and handling costs			1,518				385				2,516				988
Depreciation, depletion and amortization			6,954				1,639				37,071				3,029
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)			3,133				4,717				9,804				11,520
Loss on sale/disposal of assets—net			(45	)			(100	)			25				(125	)
Total costs and expenses			57,936				41,890				187,314				88,060
INCOME/(LOSS) FROM OPERATIONS			410				1,525				(18,882	)			3,127
INTEREST AND OTHER INCOME/(EXPENSE):
Interest income
Other			86				(54	)			87				(17	)
Related party			-				2				0				5
Interest expense
Other			(1,079	)			(1,958	)			(3,307	)			(4,054	)
Related Party			(89	)			(3	)			(95	)			(9	)
Gain on extinguishment of debt			-				1,663				-				1,663
Equity in net (loss)/income of unconsolidated affiliates			-				(27	)			35				(92	)
Gain on bargain purchase			-				-				171,151				-
Total interest and other (expense)/income			(1,082	)			(377	)			167,871				(2,504	)
NET (LOSS)/INCOME BEFORE INCOME TAXES FROM CONTINUING OPERATIONS			(672	)			1,148				148,989				623
INCOME TAXES			(635	)			-				43,396				-
NET (LOSS)/INCOME FROM CONTINUING OPERATIONS			(37	)			1,148				105,593				623
DISCONTINUED OPERATIONS (NOTE 4)
(Loss)/Income from discontinued operations			-				(70	)			-				650
NET (LOSS)/INCOME BEFORE NON-CONTROLLING INTEREST			(37	)			1,078				105,593				1,273
Less net (loss)/income attributable to non-controlling interest			(15	)			166				(9,288	)			196
NET (LOSS)/INCOME ATTRIBUTABLE TO COMPANY’S STOCKHOLDERS			(22	)			912				114,881				1,077
Other comprehensive income:
Fair market value adjustment for available-for-sale investment			(990	)			-				1,030				-
Less comprehensive income attributable to non-controlling interest			(451	)			-				464				-
COMPREHENSIVE (LOSS)/INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	(561	)		$	912			$	115,447			$	1,077
Net (loss)/income per share, basic and diluted
Continuing operations		$	(0.00	)		$	0.06			$	6.63			$	0.03
Discontinued operations			-				(0.00	)			-				0.04
		$	(0.00	)		$	0.05			$	6.63			$	0.07
Weighted average shares outstanding, basic and diluted			17,725,230				16,699,036				17,325,596				15,624,438

 

See notes to unaudited condensed consolidated financial statements.

 

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

		Nine Months Ended September 30,
		2017				2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	105,593			$	1,273
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			37,071				3,754
Accretion on asset retirement obligations			1,255				760
Amortization of deferred revenue			-				(1,174	)
Amortization of advance royalties			876				554
Amortization of debt issuance costs			1,098				1,413
Amortization of actuarial gain							(1	)
Loss on retirement of advance royalties			136				31
(Gain) on sale/disposal of assets—net			25				(125	)
(Gain) on bargain purchase			(171,151	)			-
Loss on impairment of asset			-				2,000
Equity in net loss of unconsolidated affiliates			(36	)			53
Equity-based compensation			260				489
Value of common shares issued for services			250				-
Accrued interest income-related party			-				5
Accrued interest expense-related party			9				9
Changes in assets and liabilities:
Accounts receivable			(4,820	)			(2,202	)
Inventories			(3,284	)			(3,366	)
Advance royalties			(962	)			(682	)
Prepaid expenses and other assets			(1,784	)			(829	)
Accounts payable			1,211				332
Accounts payable-related party			-				9
Accrued expenses and other liabilities			2,916				960
Deferred income taxes			43,396				-
Asset retirement obligations			(34	)			(91	)
Net cash provided by operating activities			12,025				3,172
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in Rhino Resource Partners, LP			-				(4,500	)
Investment in Blaze Mining royalty			-				150
Note receivable-related party			-				(9	)
Cash acquired in acquisitions			-				619
Sale of Rhino preferred and common units			2,300				-
Proceeds from sale of Elk Horn			890				10,650
Additions to property, plant, and equipment			(14,306	)			(3,385	)
Proceeds from sales of property, plant, and equipment			404				7
Net cash (used in)/provided by investing activities			(10,712	)			3,532
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit			98,350				80,150
Repayments on line of credit			(98,450	)			(91,300	)
Payments on debt issuance costs			(227	)			(1,148	)
Proceeds from related party loans			85				50
NP Rhino converted to Royal Shares			-				-
Repayments on loan			-				55
Repayments of loans from related party			(2,000	)			-
Gain on extinguishment of debt			-				(1,663	)
Restricted cash from Royal			-				(2,000	)
Proceeds from issuance of common stock			120				1,183
Repayment of notes payable and long-term debt			-				(1,210	)
Proceeds from loan -Cedarview			2,150				-
Proceeds from issuance of convertible notes			-				2,150
Net cash provided by/(used in) financing activities			28				(13,733	)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS			1,341				(7,029	)
CASH AND CASH EQUIVALENTS—Beginning of period			75				7,104
CASH AND CASH EQUIVALENTS—End of period		$	1,416			$	75

 

See notes to unaudited condensed consolidated financial statements.

 

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

September 30, 2017

 

(Unaudited)

 

1	BASIS OF PRESENTATION, ORGANIZATION AND GOING CONCERN

 

Basis of presentation

 

The accompanying unaudited condensed consolidated financial statements include the accounts of Royal Energy Resources, Inc. (the “Company,” “Royal,”) and its wholly owned subsidiaries Rhino GP LLC (“Rhino GP” or (“General Partner”), Blaze Minerals, LLC (“Blaze”), a West Virginia limited liability company, and Blue Grove Coal, LLC (“Blue Grove”), a West Virginia limited liability company (transferred to previous owners on July 1, 2017), and its majority owned subsidiary Rhino Resource Partners, LP (“Rhino” or the “Partnership”)(OTCQB:RHNO), a Delaware limited partnership. Rhino GP is the General Partner of Rhino. All significant intercompany balances and transactions have been eliminated in consolidation.

 

Unaudited Interim Financial Information—The accompanying unaudited interim financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. The condensed consolidated statement of financial position as of September 30, 2017, condensed consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2017 and 2016 and the condensed consolidated statements of cash flows for the nine months ended September 30, 2017 and 2016 include all adjustments (consisting of normal recurring adjustments) which the Company considers necessary for a fair presentation of the financial position, operating results and cash flows for the periods presented. The condensed consolidated statement of financial position as of December 31, 2016 was derived from audited consolidated financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America (“U.S.”). These unaudited interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report for the year ended December 31, 2016 filed with the SEC on April 3, 2017.

 

The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the entire year.

 

Organization and nature of business

 

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

 

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

 

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

 

 

As discussed further below, Royal obtained control of, and a majority limited partner interest, in Rhino on March 17, 2016. Rhino was formed on April 19, 2010 to acquire Rhino Energy LLC (the “Operating Company”). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Illinois, Kentucky, Ohio, West Virginia, and Utah. The majority of Rhino’s sales are made to domestic utilities and other coal-related organizations in the United States.

 

Royal Energy Resources, Inc. Acquisition of Rhino

 

On January 21, 2016, a definitive agreement (“Definitive Agreement”) was completed between Royal and Wexford Capital LP and certain of its affiliates (collectively, “Wexford”) whereby Royal acquired 676,912 issued and outstanding common units of Rhino previously owned by Wexford for $3.5 million. The Definitive Agreement also included a commitment by Royal to acquire within sixty days from the date of the Definitive Agreement all of the issued and outstanding membership interests of Rhino GP, the General Partner of Rhino, as well as 945,526 issued and outstanding subordinated units of the Partnership owned by Wexford for $1.0 million.

 

On March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of the General Partner, as well as 945,526 issued and outstanding subordinated units from Wexford. Royal obtained control of, and a majority limited partner interest, in the Partnership with the completion of this transaction.

 

On March 21, 2016, Royal and the Partnership entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant to which the Partnership issued 6,000,000 common units to Royal in a private placement at $1.50 per common unit for an aggregate purchase price of $9.0 million. Royal paid the Partnership $2.0 million in cash and delivered a promissory note payable to Rhino in the amount of $7.0 million (the “Rhino Promissory Note”). The promissory note was payable in three installments: (i) $3.0 million on July 31, 2016; (ii) $2.0 million on or before September 30, 2016 and (iii) $2.0 million on or before December 31, 2016. On December 30, 2016, the Partnership modified the Rhino Promissory Note with Royal for the final $2.0 million payment due on or before December 31, 2016 to extend the due date to December 31, 2018 and to provide that it would be convertible into shares of Royal common stock at Royal’s election. On September 1, 2017, Royal elected to convert the Rhino Promissory Note to shares of Royal common stock. Please read “—Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.”

 

As a result of these transactions, Rhino became a majority-owned subsidiary of Royal.

 

Option Agreement-Armstrong Energy

 

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

 

 

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

 

The Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the Seventh Amendment and the GP Amendment. Upon the request by Rhino Holdings, Rhino will also enter into a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding common units.

 

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

 

On October 31, 2017, Armstrong Energy and its subsidiaries filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy Court. Per the Chapter 11 petitions, Armstrong Energy will file a detailed restructuring plan as part of the Chapter 11 proceedings. The Partnership is evaluating the Armstrong Energy Chapter 11 filing and any effect it may have on the Option Agreement. See Note 7 for further information on the Partnership’s assessment of the Call Option.

 

Series A Preferred Unit Purchase Agreement

 

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

 

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

 

 

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

 

Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note

 

On December 30, 2016, the Partnership and Royal entered into a letter agreement whereby they extended the maturity dates of the Weston Promissory Note and the final installment payment of the Rhino Promissory Note to December 31, 2018. The letter agreement further provides that the aggregate $4.0 million balance of the Weston Promissory Note and Rhino Promissory Note may be converted at Royal’s option into a number of shares of Royal’s common stock equal to the outstanding balance multiplied by seventy-five percent (75%) of the volume-weighted average closing price of Royal’s common stock for the 90 days preceding the date of conversion (“Royal VWAP”), subject to a minimum Royal VWAP of $3.50 and a maximum Royal VWAP of $7.50. On September 1, 2017, Royal elected to convert the Rhino Promissory Note and the Weston Promissory Note into shares of Royal common stock. Royal issued 914,797 shares of its common stock to Rhino at a conversion price of $4.51 per share. See Note 12 for further discussion.

 

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

 

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

 

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

 

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

 

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

 

 

Debt Classification— Rhino evaluated its amended and restated senior secured credit facility at September 30, 2017 to determine whether this debt liability should be classified as a long-term or current liability. As of December 31, 2016, Rhino had met the requirements to extend the maturity date of the credit facility to December 31, 2017. Since the credit facility has an expiration date of December 2017, the Company determined that its credit facility debt liability at September 30, 2017 of $9.9 million, should be classified as a current liability on its unaudited condensed consolidated statements of financial position. The classification of the credit facility balance as a current liability raises substantial doubt of the Rhino’s, and thus the Company’s ability to continue as a going concern for the next twelve months. Rhino is considering alternative financing options that could result in a new long-term credit facility. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount of and classification of liabilities that may result should the Company be unable to continue as a going concern.

 

Reclassifications— Certain prior year amounts have been reclassified to discontinued operations on the unaudited condensed consolidated statements of operations and comprehensive income related to the disposal of an operating component of Rhino, the Elk Horn coal leasing business, during 2016. See Note 4 for further information on the Elk Horn disposal.

 

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

 

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

 

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 Corporation (NASDAQ: GPOR) (“Gulfport”). The Partnership accounts for the investment in this joint venture and results of operations under the equity method based upon its ownership percentage. The Partnership recorded its proportionate share of the operating income for this investment for the three and nine months ended September 30, 2017 of approximately $0 and $36,000, respectively. The Partnership recorded its proportionate share of the operating (loss) for Sturgeon for the three and nine months ended September 30, 2016 of approximately ($26,000) and ($0.1) million, respectively. 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 September 30, 2017, the Partnership owned 568,794 shares of Mammoth Inc.

 

As of September 30, 2017 and December 31, 2016, the Partnership recorded a fair market value adjustment of $1.0 million and $1.6 million, respectively, for its available-for-sale investment in Mammoth Inc. based on the market value of the shares at September 30, 2017 and December 31, 2016, respectively, which was recorded in Other Comprehensive Income. As of September 30, 2017 and December 31, 2016, the Partnership has recorded its investment in Mammoth Inc. as a short-term asset, which the Partnership has classified as available-for-sale. The Partnership has included its investment in Mammoth and its prior investment in Muskie and Sturgeon in its Other category for segment reporting purposes.

 

 

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

 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). ASU 2016-02 requires that lessees recognize all leases (other than leases with a term of twelve months or less) on the balance sheet as lease liabilities, based upon the present value of the lease payments, with corresponding right of use assets. ASU 2016-02 also makes targeted changes to other aspects of current guidance, including identifying a lease and lease classification criteria as well as the lessor accounting model, including guidance on separating components of a contract and consideration in the contract. The amendments in ASU 2016-02 will be effective for the Company on January 1, 2019 and will require modified retrospective application as of the beginning of the earliest period presented in the financial statements. Early application is permitted. The Company is currently evaluating this guidance and currently believes this new guidance will not have a material impact on its financial results when adopted, but will require additional assets and liabilities to be recognized for certain agreements where the Company has the rights to use assets.

 

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

 

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

 

3	ACQUISITIONS

 

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

 

As discussed in Note 1, the Company acquired Rhino GP and obtained control of, and became a majority limited partner, in Rhino on March 17, 2016. Rhino GP is the General Partner of Rhino.

 

 

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

 

Rhino has a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2016, Rhino controlled an estimated 256.9 million tons of proven and probable coal reserves, consisting of an estimated 203.5 million tons of steam coal and an estimated 53.4 million tons of metallurgical coal. In addition, as of December 31, 2016, Rhino controlled an estimated 196.5 million tons of non-reserve coal deposits.

 

At September 30, 2017, the Company’s investment in Rhino consists of $11,250,213 in cash. The acquisition was completed in three steps as described in Note 1. The fair value of Rhino’s property, plant and equipment was determined by an independent, third-party appraiser that completed their report during the first quarter of 2017. The fair value of the Partnership’s coal properties were based on observable inputs from market transactions that closely related to the nature of Rhino’s coal properties. The asset retirement obligations of the Partnership were adjusted to fair value based upon current risk adjusted discount rates. The original provisional assets and liabilities were adjusted as of March 31, 2017 within the one year measurement period. The total income statement impact of these adjustments was recognized during the three months ended March 31, 2017. The table below reflects the value the assets acquired and the liabilities assumed for the acquisition of Rhino.

 

		Final Amounts				Provisional Amounts
		March 17, 2016				December 31, 2016
		(thousands)
Assets:
Current Assets		$	25,851			$	23,117
Property, plant and equipment			229,950				66,812
Other non-current assets			37,673				40,047
Total identifiable assets			293,474				129,976
Liabilities:
Current liabilities			60,211				62,810
Non-current liabilities
Long-term debt, net of current portion			2,536				2,536
Asset retirement obligations, net of current portion			17,986				27,108
Other non-current liabilities			37,090				37,092
Total non-current liabilities			57,612				66,736
Total liabilities			117,823				129,546
Net identifiable assets			175,651				430
Goodwill			-				7,594
subtotal			175,651				8,024
Non-controlling shareholders			-				3,524
Bargain purchase gain			171,151				-
Total consideration paid		$	4,500			$	4,500

 

Note: Final amounts were determined in the quarter ending March 31, 2017 as discussed above, which resulted in the differences to the provisional amounts.

 

 

Operating results for Rhino for the three and nine months ended September 30, 2017 and 2016 are as follows.

 

		Three months ended September 30,								Nine months ended September 30,
		2017				2016				2017				2016
		(in thousands)								(in thousands)
Revenues		$	58,346			$	43,415			$	168,432			$	124,358
Comprehensive income (loss)			682				(3,785	)			963				(126,960	)
Net loss per unit, basic and fully diluted		$	-			$	(0.41	)		$	0.29			$	(20.43	)

 

The first quarter’s remeasurement of the acquired net assets of Rhino resulted in the recognition of a deferred income tax liability of $55,529 as of the acquisition date. The recognition of this deferred tax liability has been included in the first quarter’s provision for income taxes. The recognition of the deferred tax liability also reflects future taxable income through the reversals of temporary differences; therefore, the first quarter’s tax provision also includes the reversal of a valuation allowance of $7,415 which had been applied to deferred tax assets at December 31, 2016. The remaining components of the provision consists of the deferred tax effects arising from other net income and expense items for the period, including the effects of acquisition remeasurements recognized in the first quarter. The Company had a reduction in income tax expense in the three months ended September 30, 2017.

 

Blaze Mining Company, LLC Option Termination and Royalty Agreement

 

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

 

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

 

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

 

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

 

 

The Company performed a comprehensive review of its current coal mining operations as well as potential future development projects for the year ended December 31, 2016 to ascertain any potential impairment losses. Since production from this property had not begun at December 31, 2016, the Company engaged a third-party engineer to provide an estimate of fair value. The specialist valued the royalty interests at $4.4 million. Accordingly, the Company recorded an asset impairment loss of $16.7 million in the fourth quarter of 2016.

 

Blue Grove Coal, LLC (“Blue Grove”).

 

On June 10, 2015, the Company entered into a Securities Purchase Agreement (the “Blue Grove Agreement”) under which it acquired all of the membership interests in Blue Grove Coal, LLC (“Blue Grove”) from Ian Ganzer and Gary Ganzer (the “Ganzers”) for 350,000 shares of common stock. The Blue Grove Amendment was amended on December 23, 2015 to reduce the purchase price for Blue Grove to 10,000 shares of common stock. Blue Grove was the operator of a surface coal mine owned by G.S. Energy, LLC, a company also owned by the Ganzers, but ceased operations in the third quarter of 2015 when the buyer of coal from the mine filed for bankruptcy. On July 1, 2017, the Company entered into a Call Option Agreement with the Ganzers, under which the Company exercised its right to put its membership interests in Blue Grove to the Ganzers. Under the agreement, the Company conveyed all of the its ownership in Blue Grove to the Ganzers, and the Ganzers returned 10,000 shares of the Company’s common stock which they had received on consideration for the Blue Grove membership interests. Under the Call Option Agreement, the Ganzers agreed to release the Company from any liability, and to indemnify and hold the Company harmless against any liability arising out of its relationship with Blue Grove. Under the Call Option Agreement, Ian Ganzer also released the Company of any liability under his employment agreement with the Company, although Mr. Ganzer was allowed to retain 15,998 shares of common stock issued to him as a signing bonus under his employment agreement, which had vested as of the date of his resignation in September 2016.

 

4.	DISCONTINUED OPERATIONS

 

Elk Horn Coal Leasing

 

In August 2016, the Partnership entered into an agreement to sell its Elk Horn coal leasing company (“Elk Horn”) to a third party for total cash consideration of $12.0 million. The Partnership received $10.5 million in cash consideration upon the closing of the Elk Horn transaction and the remaining $1.5 million of consideration was paid in ten equal monthly installments of $150,000 on the 20^th of each calendar month beginning on September 20, 2016. The previous operating results of Elk Horn have been reclassified and reported on the (Gain)/loss from discontinued operations line on the Company’s unaudited condensed consolidated statement of operations and comprehensive income for the three and nine months ended September 30, 2016.

 

Major components of net income from discontinued operations for the three and nine months ended September 30, 2017 and 2016 are summarized as follows:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2017				2016				2017				2016
		(in thousands)
Major line items constituting (loss)/income from discontinued operations for the Elk Horn disposal:
Other revenues		$	-			$	442			$	-			$	1,707
Total revenues			-				442								1,707
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			-				345				-				650
Depreciation, depletion and amortization			-				86				-				237
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)			-				78				-				161
Interest expense and other			-				3				-				9
Total costs and expenses			-				512				-				1,057
(Loss)/Income from discontinued operations before income taxes for the Elk Horn disposal			-				(70	)			-				650
Income taxes			-				-				-				-
Net (loss)/ income from discontinued operations		$	-			$	(70	)		$	-			$	650

 

 

5	PREPAID EXPENSES AND OTHER CURRENT ASSETS

 

Prepaid expenses and other current assets as of September 30, 2017 and December 31, 2016 consisted of the following:

 

		September 30, 2017				December 31, 2016
		(in thousands)
Other prepaid expenses		$	1,731			$	761
Debt issuance costs—net			110				981
Escrow deposit			263				-
Prepaid insurance			1,922				1,432
Prepaid leases			123				77
Supply inventory			504				614
Deposits			-				164
Note receivable-current portion			-				900
Total Prepaid expenses and other		$	4,653			$	4,929

 

Debt issuance costs were included in Prepaid expenses and other current assets as of September 30, 2017 and December 31, 2016 since Rhino’s credit facility balance was classified as a current liability. See Note 10 for further information on the amendments to Rhino’s amended and restated senior secured credit facility.

 

As of December 31, 2016, the note receivable balance of $0.9 million related to the $1.5 million of consideration to be paid in ten equal monthly installments of $150,000 for the Elk Horn sale discussed earlier. The note receivable was paid in full as of September 30, 2017.

 

6	PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, including coal properties and mine development and construction costs, as of September 30, 2017 and December 31, 2016 are summarized by major classification as follows:

 

		Useful Lives		September 30, 2017				December 31, 2016
				(in thousands)
Coal properties, including mining and other equipment		1 - 20 Years		$	-			$	69,684
Land					10,986				n/a
Mining and other equipment and related facilities		2 - 20 Years			201,792				n/a
Mine development costs		1 - 15 Years			762				n/a
Coal properties		1 - 15 Years			31,141				n/a
Construction work in process					3,108				n/a
Total					247,789				69,684
Less accumulated depreciation, depletion and amortization					(41,030	)			(4,572	)
Net				$	206,759			$	65,112

 

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties and oil and natural gas properties, amortization expense for mine development costs, amortization expense for intangible assets and amortization expense for asset retirement costs for the three and nine months ended September 30, 2017 and 2016 were as follows:

 

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2017				2016				2017				2016
		(in thousands)								(in thousands)
Depreciation expense-mining and other equipment and related facilities		$	6,784			$	1,662			$	36,219			$	3,074
Depletion expense for coal properties and oil and natural gas properties			160				-				878				-
Amortization of mine development costs			10				-				39				-
Amortization expense for intangible assets			-				-				34				-
Amortization expense for asset retirement costs			-				(23	)			(99	)			(45	)
Total depreciation, depletion and amortization		$	6,954			$	1,639			$	37,071			$	3,029

 

As discussed in Notes 1 and 3, the Company acquired and became a majority limited partner in Rhino on March 17, 2016. The Company completed its purchase accounting fair value adjustments in the first quarter of 2017 and adjusted the previous provisional amounts the Company had recorded for the Rhino acquisition. The fair value purchase adjustments resulted in a bargain purchase gain of $171 million recorded in the first quarter of 2017 that related to the prior 2016 reporting period as well as $16.1 million of additional depreciation, depletion and amortization expense recorded in the first quarter of 2017 that related to the prior 2016 reporting period.

 

7	INTANGIBLE AND OTHER NON-CURRENT ASSETS

 

Other non-current assets as of September 30, 2017 and December 31, 2016 consisted of the following:

 

		September 30, 2017				December 31, 2016
		(in thousands)
Deposits and other		$	343			$	218
Non-current receivable			27,157				27,157
Deferred expenses			194				216
Total		$	27,694			$	27,591

 

Non-current receivable. The non-current receivable balance of $27.2 million as of September 30, 2017 and December 31, 2016 consisted of the amount due from the Partnership’s workers’ compensation insurance providers for potential claims against the Partnership that are the primary responsibility of the Partnership, which are covered under the Partnership’s insurance policies. The $27.2 million is also included in the accrued workers’ compensation benefits liability balance, which is included in non-current liabilities. The Company presents this amount on a gross asset and liability basis since a right of setoff does not exist per the accounting guidance in ASC Topic 210, Balance Sheet. This presentation has no impact on the results of operations or cash flows.

 

Call Option-Armstrong Energy. As discussed in Note 1, the Partnership and Rhino Holdings executed an Option Agreement in December 2016 where the Partnership received a Call Option from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy. In exchange for Rhino Holdings granting the Partnership the Call Option, the Partnership issued 5.0 million common units to Rhino Holdings upon the execution of the Option Agreement. The Partnership valued the Call Option at $21.8 million based upon the closing price of the Partnership’s publicly traded common units on the date the Option Agreement was executed. The Partnership has determined the value of the common units issued at December 30, 2016 of $21.8 million constituted an amount that would be applied to the potential acquisition of Armstrong Energy, as discussed in Note 1.

 

As discussed in Note 1, on October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy Court. The Partnership is evaluating the Chapter 11 petitions filed by Armstrong Energy and the Partnership will further evaluate the detailed restructuring plan when it is submitted by Armstrong Energy to determine what, if any, effect the ultimate outcome of the Chapter 11 proceedings will have on the Call Option. Because of the uncertain facts and circumstances surrounding the current state of the Armstrong Energy Chapter 11 proceedings, which includes the possibility that the Partnership will still exercise the Call Option as outlined in Note 1, the Partnership concluded that the value of the Call Option was not impaired as of September 30, 2017. However, management expects that further information, including the progression of Armstrong’s restructuring plan and bankruptcy proceedings, will become available in the next quarter; such information may have a material effect on the carrying value of the Option Agreement.

 

 

8	ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

 

Accrued expenses and other current liabilities as of September 30, 2017 and December 31, 2016 consisted of the following:

 

		September 30, 2017				December 31, 2016
		(in thousands)
Payroll, bonus and vacation expense		$	1,786			$	1,721
Non income taxes			3,393				2,669
Royalty expenses			2,077				1,617
Accrued interest			601				601
Health claims			803				630
Workers’ compensation & pneumoconiosis			2,450				2,450
Other			1,325				1,717
Total		$	12,435			$	11,405

 

9	NOTES PAYABLE – RELATED PARTY

 

Related party notes payable consist of the following at September 30, 2017 and December 31, 2016.

 

		September 30, 2017				December 31, 2016
		(thousands)
Demand note payable dated March 6, 2015; owed E-Starts Money Co., a related party; interest at 6% per annum		$	204			$	204
Demand note payable dated June 11, 2015; owed E-Starts Money Co., a related party; non-interest bearing			200				200
Demand note payable dated September 22, 2016; owed E-Starts Co., a related party; non-interest bearing			50				50
Demand note payable dated December 8, 2016; owed to E-Starts Money Co., a related party; non-interest bearing			50				50
Total related party notes payable		$	504			$	504

 

The related party notes payable have accrued interest of $31,509 at September 30, 2017 and $22,372 at December 31, 2016. For the three and nine months ended September 30, 2017, the Company expensed $3,046 and $9,137, respectively, in interest from the related party loans.

 

10

DEBT

 

Debt as of September 30, 2017 and December 31, 2016 consisted of the following:

 

		September 30, 2017				December 31, 2016
		(in thousands)
Senior secured credit facility with PNC Bank, N.A.		$	9,940			$	10,040
Note payable to Weston Energy dated December 30, 2016; interest at 8% per annum; due January 15, 2017			-				2,000
Note payable to Cedarview Opportunities Master Fund, L.P. dated May 31, 2017; interest at 14% annum; due May 31, 2019			2,500				-
Total			12,440				12,040
Less current portion			(9,940	)			(12,040	)
Long-term debt		$	2,500			$	-

 

 

Secured Promissory Note – On June 12, 2017, Company entered into a Secured Promissory Note dated May 31, 2017 with Cedarview Opportunities Master Fund, L.P. (the “Lender”), under which the Company borrowed $2,500,000 from the Lender. The loan bears non-default interest at the rate of 14%, and default interest at the rate of 17% per annum. The Company and the Lender simultaneously entered into a Pledge and Security Agreement dated May 31, 2017, under which the Company 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. The Company 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, the Company is obligated to maintain at least one quarter of interest on the loan in the escrow account at all times. In consideration for the Lender’s agreement to make the loan, the Company transferred 25,000 Common Units of Rhino to the Lender as a fee. The Company intends to use the proceeds to repay in full all loans made to the Company by E-Starts Money Co. in the principal amount of $503,593, and to use 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.

 

Senior Secured Credit Facility with PNC Bank, N.A.— On July 29, 2011, the Partnership executed the amended and restated credit agreement (as amended, the “Amended and Restated Credit Agreement”). The maximum availability under the amended and restated credit facility was $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million was available for letters of credit. In April 2015, the amended and restated credit agreement was amended and the borrowing commitment under the facility was reduced to $100.0 million and the amount available for letters of credit was reduced to $50.0 million. As described below, in March 2016 and May 2016, the borrowing commitment under the facility was further reduced to $80.0 million and $75.0 million, respectively, and the amount available for letters of credit was reduced to $30.0 million. In addition, as described below, the borrowing commitment under the facility was further reduced by amendments in July 2016 and December 2016 to $44.3 million as of September 30, 2017. The amount available for letters of credit was unchanged from these amendments.

 

On March 17, 2016, the Partnership entered into a fourth amendment (the “Fourth Amendment”) of the amended and restated credit agreement. The Fourth Amendment amended the definition of change of control in the amended and restated credit agreement to permit Royal to purchase the membership interests of the General Partner. The Fourth Amendment also eliminated the option to borrow funds utilizing the LIBOR rate plus an applicable margin and establishes the borrowing rate for all borrowings under the facility to be based upon the current PRIME rate plus an applicable margin of 3.50%.

 

On May 13, 2016, the Partnership entered into the Fifth Amendment of the amended and restated credit agreement, which extended the term to July 31, 2017.

 

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

 

 

In December 2016, the Partnership entered into a seventh amendment of its amended and restated credit agreement (the “Seventh Amendment”). The Seventh Amendment allows for the issuance of the Series A preferred units as outlined in the Amended and Restated Partnership Agreement. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. The Seventh Amendment alters the maximum leverage ratio to 4.0 to 1.0 effective December 31, 2016 through May 31, 2017 and 3.5 to 1.0 from June 30, 2017 through December 31, 2017. The maximum leverage ratio shall be reduced by 0.50 to 1.0 for every $10.0 million of net cash proceeds, in the aggregate, received after the Seventh Amendment date from (i) the issuance of any equity by the Partnership and/or (ii) the disposition of any assets in excess of $2.0 million in the aggregate, provided, however, that in no event will the maximum leverage ratio be reduced below 3.0 to 1.0.

 

The Seventh Amendment alters the minimum consolidated EBITDA, as calculated on a rolling twelve months basis, to $12.5 million from December 31, 2016 through May 31, 2017 and $15.0 million from June 30, 2017 through December 31, 2017. The Seventh Amendment alters the maximum capital expenditures allowed, as calculated on a rolling twelve months basis, to $20.0 million through the expiration of the credit facility. A condition precedent to the effectiveness of the Seventh Amendment is the receipt of the $13.0 million of cash proceeds received by the Partnership from the issuance of the Series A preferred units pursuant to the Preferred Unit Agreement, which was used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contribution, which was a requirement of prior amendments to the credit agreement.

 

On March 23, 2017, the Partnership entered into an eighth amendment (the “Eighth Amendment”) of its amended and restated credit agreement that allows the annual auditor’s report for the years ended December 31, 2016 and 2015 to contain a qualification with respect to the short-term classification of the Partnership’s credit facility balance without creating a default under the credit agreement.

 

On June 9, 2017, the Partnership entered into a ninth amendment (the “Ninth Amendment”) of its amended and restated credit agreement that permitted outstanding letters of credit to be replaced with different counterparties without affecting the revolving credit commitments under the credit agreement. The Ninth Amendment also permits certain lease and sale leaseback transactions under the credit agreement that do not affect the revolving credit commitments under the credit agreement for asset dispositions and also do not factor in the calculation of the maximum capital expenditures allowed under the credit agreement.

 

At September 30, 2017, the Partnership had borrowed $9.9 million at a variable interest rate of PRIME plus 3.50% (7.75% at September 30, 2017). In addition, the Partnership had outstanding letters of credit of $26.1 million at a fixed interest rate of 5.00% at September 30, 2017. Based upon a maximum borrowing capacity of 3.50 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Partnership had not used $8.2 million of the borrowing availability at September 30, 2017. As of September 30, 2017 and December 31, 2016, the Partnership was in compliance with respect to all covenants contained in its credit agreement.

 

11	ASSET RETIREMENT OBLIGATIONS

 

The changes in asset retirement obligations for the nine months ended September 30, 2017 and the year ended December 31, 2016 are as follows:

 

		Nine months ended				Year ended
		September 30, 2017				December 31, 2016
		(in thousands)
Balance at beginning of period (including current portion)		$	27,420			$	-
Acquired			-				28,200
Accretion expense			1,255				1,105
Adjustment resulting from annual recosting and other			-				(1,685	)
Adjustments to the liability resulting from final purchase allocation			(7,228	)			-
Liabilities settled			(33	)			(200	)
Balance at end of period			21,414				27,420
Less current portion of asset retirement obligation			(917	)			(917	)
Long-term portion of asset retirement obligation		$	20,497			$	26,503

 

 

12	STOCKHOLDERS’ EQUITY

 

In October 2012 the Company amended its charter to authorize issuance of up to 500,000,000 shares of common stock with a par value of $0.00001. In March 2017, the Company filed an amendment to its Certificate of Incorporation to reduce the authorized shares of Common Stock to 25,000,000 and to reduce the authorized shares of Preferred Stock to 5,000,000 from 10,000,000.

 

Series A preferred stock

 

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

 

Stock subscription receivable

 

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

 

Issuance of shares in private placement

 

In the first quarter of 2017, the Company issued 21,817 shares to three investors in a private placement at $5.50 per share.

 

Conversion of the Weston Promissory Note and the Rhino Promissory Note

 

On September 1, 2017, Royal elected to convert the Weston Promissory Note of $2.1 million (including accrued interest) and the Rhino Promissory Note of $2.0 million to 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. Please read “Note 1. Basis of Presentation, Organization and Going Concern – Organization and Nature of Business —Letter Agreement Regarding Rhino Promissory Note and Weston Promissory Note.” The Company recorded the $4.1 million conversion of the Weston Promissory Note and Rhino Promissory Note as Treasury Stock in the Company’s stockholders’ equity section of the Company’s unaudited condensed consolidated statements of financial position.

 

13	RELATED PARTY TRANSACTIONS

 

On March 6, 2015, the Company borrowed $203,593 from E-Starts Money Co. (“E-Starts”) pursuant to a 6% demand promissory note. (See Note 9) The proceeds were used to repay all of Royal’s indebtedness at the time. E-Starts is owned by William L. Tuorto, our Chairman and Chief Executive Officer. On June 11, 2015, the Company borrowed an additional $200,000 from E-Starts pursuant to a non-interest bearing demand promissory note. On September 22, 2016, the Company borrowed $50,000 from E-Starts pursuant to a non-bearing demand promissory note. On December 8, 2016, the Company borrowed $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note. On March 3, 2017, the Company borrowed $50,000 from E-Starts pursuant to a non-interest bearing demand promissory note which was repaid by Royal on June 28, 2017. On March 16, 2017, the Company borrowed $25,000 from E-Starts pursuant to a non-interest bearing demand promissory note which was repaid by Royal on June 28, 2017. On April 26, 2017, the Company borrowed $10,000 from E-Starts pursuant to a non-interest bearing promissory note which was repaid by Royal on June 6, 2017. The total amount owed to E-Starts at September 30, 2017 and December 31, 2016 was $503,593, plus accrued interest.

 

 

E-Starts, in addition to the promissory notes listed above, advanced money to the Company for use in paying certain obligations of the Company.

 

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

 

		September 30, 2017				December 31, 2016
		(thousands)
Due to E-Starts Money Co
Expense advances		$	10			$	11
Accrued interest			32				22
			42				33
Due to GS Energy, LLC			-				18
Due to Ian Ganzer			-				10
Due to Gary Ganzer			-				10
		$	42			$	71

 

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

 

Blue Grove Coal, LLC). On June 10, 2015, the Company acquired Blue Grove in exchange for 350,000 shares of its common stock. Blue Grove was owned 50% by Ian Ganzer, who became our chief operating officer simultaneous with the acquisition, and 50% by Gary Ganzer, Ian Ganzer’s father (the “Members”). Simultaneous with the Company’s acquisition of Blue Grove, Blue Grove entered into an operator agreement with GS Energy, LLC, (“GS Energy”), under which Blue Grove has an exclusive right to mine the coal properties of GS Energy for a two year period. Simultaneous with the acquisition of Blue Grove, Blue Grove also entered into a Management Agreement with Black Oak Resources, LLC (“Black Oak”), a company owned by the Members. Under the Management Agreement, Blue Grove subcontracted all of its responsibilities under the Management Agreement with GS Energy to Black Oak. In consideration, Black Oak was entitled to 75% of all net profits generated by the mining of the coal properties of GS Energy. Subsequently, the agreement with Black Oak was amended to provide that Black Oak was entitled to 100% of the first $400,000 and 50% of the next $1,000,000, for a maximum of $900,000 of net profits generated by the mining of the coal properties of GS Energy.

 

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

 

On July 1, 2017, the Company entered into an agreement with Ian and Gary Ganzer, under which the Company transferred its interest in Blue Grove to the Ganzers in consideration for the Ganzers’ return of 10,000 shares of the Company’s common stock, which was the purchase price for Blue Grove. In the same agreement, Ian Ganzer returned 9,599 shares of common stock for cancellation. The shares represented the unvested portion of a stock bonus issued to Mr. Ganzer when he was employed as chief operating officer of the Company. The parties executed mutual releases of liability. In addition, the Ganzers’ agreed to hold the Company harmless against any liability arising out its former ownership of Blue Grove.

 

14	EMPLOYEE BENEFITS

 

401(k) Plans— The Partnership and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Operating Company’s discretion. The expense under these plans for the three and nine months ended September 30, 2017 and 2016 is included in Cost of operations and Selling, general and administrative expense in the unaudited condensed consolidated statements of operations and comprehensive income and was as follows:

 

		Three months ended September 30,								Nine months ended September 30,
		2017				2016				2017				2016
		(in thousands)
401(k) plan expense		$	387			$	406			$	1,107			$	1,113

 

 

15	EQUITY-BASED COMPENSATION

 

Stock option plan - The Royal Energy Resources, Inc. 2015 Stock Option Plan and the Royal Energy Resources, Inc. 2015 Employee, Consultant and Advisor Stock Compensation Plan (“Plans”) were approved by the Company’s board on July 31, 2015. Each Plan reserves 1,000,000 shares for awards. The Company’s Board of Directors is designated to administer the Plan. No options are outstanding under the Plans at September 30, 2017. As of September 30, 2017, there were 114,092 shares issued from the Employee, Consultant and Advisor Stock Compensation Plan. As of September 30, 2017, there are 1,000,000 shares available under the Stock Option Plan and 885,908 shares available under the Employee, Consultant and Advisor Stock Compensation Plan. The shares issued under the Employee, Consultant and Advisor Stock Compensation Plan were expensed at their market value on the date of issuance.

 

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

 

16	COMMITMENTS AND CONTINGENCIES

 

Coal Sales Contracts and Contingencies—As of September 30, 2017, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

 

Year		Tons (in thousands)				Number of customers
2017-Q4			1,329				14
2018			1,825				6
2019			700				2

 

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

 

Purchase Commitments— The Partnership has a commitment to purchase approximately 1.0 million gallons of diesel fuel at fixed prices from January 2017 through December 2017 for approximately $2.0 million.

 

Purchased Coal Expenses—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts. In addition, the Partnership incurs expense from time to time related to coal purchased on the over-the-counter market (“OTC”). The Partnership had no expense for purchased coal from coal purchase contracts or expense from OTC purchases for the three and nine months ended September 30, 2017 and 2016.

 

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the three and nine months ended September 30, 2017 and 2016 are included in Cost of operations in the unaudited condensed consolidated statements of operations for the period owned by the Company were as follows:

 

		Three months ended September 30,								Nine months ended September 30,
		2017				2016				2017				2016
		(in thousands)
Lease expense		$	726			$	1,438			$	3,217			$	3,517
Royalty expense		$	3,636			$	2,409			$	10,963			$	7,350

 

 

 

17	MAJOR CUSTOMERS

 

The Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues:

 

		September 30				December 31				Nine months				Nine months
		2017				2016				ended				ended
		Receivable				Receivable				September 30				September 30
		Balance				Balance				2017 Sales				2016 Sales
		(in thousands)
LG&E and KU (PPL)		$	1,749			$	1,496			$	30,971			$	31,333
Big Rivers Electric Corporation			1,133				-				18,387				14,045
Integrity Coal Sales			2,125				1,975				18,152				2,532
Dominion Energy			1,826				-				17,148				4,673

 

18	FAIR VALUE OF FINANCIAL INSTRUMENTS

 

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

 

 

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

 

Level One - Quoted prices for identical instruments in active markets.

 

Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs.

 

Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity.

 

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

 

The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership’s amended and restated senior secured credit facility was based upon a Level 2 measurement utilizing a market approach, which incorporated market-based interest rate information with credit risks similar to the Partnership. The fair value of the Partnership’s amended and restated senior secured credit facility approximates the carrying value at September 30, 2017. The book value of the Company’s secured promissory note is considered to be representative of its fair value as of September 30, 2017 since only a brief time period has elapsed since the note was entered on May 31, 2017.

 

As of September 30, 2017 and December 31, 2016, the Partnership had a recurring fair value measurement relating to its investment in Mammoth, Inc. As discussed in Note 2, in October 2016, the Partnership contributed its limited partner interests in Mammoth to Mammoth, Inc. in exchange for 234,300 shares of common stock of Mammoth, Inc. The common stock of Mammoth, Inc. began trading on the NASDAQ Global Select Market in October 2016 under the ticker symbol TUSK and the Partnership sold 1,953 shares during the initial public offering of Mammoth, Inc. and received proceeds of approximately $27,000. 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 September 30, 2017, the Partnership owned 568,794 shares of Mammoth, Inc. The Partnership’s shares of Mammoth, Inc. are classified as an available-for-sale investment on the unaudited condensed consolidated statements of financial position. Based on the availability of a quoted price, the recurring fair value measurement of the Mammoth, Inc. shares is a Level 1 measurement.

 

19	SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

 

The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2017 and 2016 excludes approximately $1.3 million and $0.2 million, respectively, of property additions, which are recorded in accounts payable. The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2017 excludes the debt conversion as discussed in Note 12.

 

20	SEGMENT INFORMATION

 

The Company produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah. The Company sells primarily to electric utilities in the United States. For the three months ended September 30, 2017, the Company had four reportable segments: Central Appalachia (comprised of both surface and underground mines located in Eastern Kentucky and Southern West Virginia), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Rhino Western (comprised of an underground mine in Utah) and Illinois Basin (comprised of an underground mine in western Kentucky).

 

 

The Company’s other category is comprised of the Company’s ancillary businesses, its remaining oil and natural gas activities and its corporate overhead. The Company has not provided disclosure of total expenditures by segment for long-lived assets, as the Company does not maintain discrete financial information concerning segment expenditures for long lived assets, and accordingly such information is not provided to the Company’s chief operating decision maker. The information provided in the following tables represents the primary measures used to assess segment performance by the Company’s chief operating decision maker. For the 2017 reporting period, the Partnership changed its methodology for allocating interest expense to its reportable segments where interest expense is no longer allocated to the reportable segments and is reported in the Other category. All prior periods have been recast to reflect this allocation methodology change.

 

Reportable segment results of operations for the three months ended September 30, 2017 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

 

		Central				Northern				Rhino				Illinois								Total
		Appalachia				Appalachia				Western				Basin				Other				Consolidated
		(in thousands)
Total revenues		$	27,891			$	6,398			$	9,080			$	14,965			$	12			$	58,346
DD&A			2,533				508				1,448				2,352				113				6,954
Interest expense *			-				-				-				-				1,168				1,168
Net(loss) from continuing operations		$	(321	)		$	(74	)		$	(105	)		$	(172	)		$	635			$	(37	)

 

Reportable segment results of operations for the three months ended September 30, 2016 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization) (Rhino is only included from its date of acquisition of March 17, 2016):

 

		Central				Northern				Rhino				Illinois								Total
		Appalachia				Appalachia				Western				Basin				Other				Consolidated
		(in thousands)
Total revenues		$	10,432			$	10,974			$	7,219			$	14,576			$	214			$	43,415
DD&A			415				196				326				666				36				1,639
Interest expense *			552				59				119				310				921				1,961
Net (loss)/income from continuing operations		$	(276	)		$	2,296			$	-			$	(505	)		$	(367	)		$	1,148

 

Reportable segment results of operations for the nine months ended September 30, 2017 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

 

		Central				Northern				Rhino				Illinois								Total
		Appalachia				Appalachia				Western				Basin				Other				Consolidated
		(in thousands)
Total revenues		$	76,880			$	17,014			$	25,141			$	49,377			$	20			$	168,432
DD&A			13,062				2,908				7,632				12,828				641				37,071
Interest expense *			-				-				-				-				3,402				3,402
Net income from continuing operations		$	(10,116	)		$	(2,239	)		$	(3,308	)		$	(6,500	)		$	127,756			$	105,593

 

Reportable segment results of operations for the nine months ended September 30, 2016 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization) (Rhino is only included from its date of acquisition of March 17, 2016):

 

		Central				Northern				Rhino				Illinois								Total
		Appalachia				Appalachia				Western				Basin				Other				Consolidated
		(in thousands)
Total revenues		$	15,892			$	23,250			$	18,434			$	33,331			$	280			$	91,187
DD&A			818				420				678				1,044				69				3,029
Interest expense *			1,404				224				238				596				1,601				4,063
Net (loss)/income from continuing operations		$	(349	)		$	1,246			$	(19	)		$	(150	)		$	(105	)		$	623

 

*For the 2017 reporting period, the Partnership changed its methodology for allocating interest expense to its reportable segments where interest expense is no longer allocated to the reportable segments and is reported in the Other category. All prior periods have been recast to reflect this allocation methodology change.

 

21	PARENT COMPANY FINANCIAL STATEMENTS

 

The Company’s Rhino subsidiary has certain restrictions on its assets and funds that are available to be transferred outside of Rhino based upon its Amended and Restated Credit Agreement as discussed in Note 10. Due to the restrictions on the assets and funds available for remittance to the Company, the following tables present the financial statements of the parent Company for all periods presented.

 

 

Item 1. Financial Statements (Unaudited)

 

PART I.—FINANCIAL INFORMATION

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED STATEMENTS OF FINANCIAL POSITION

(in thousands)

 

		September 30, 2017				December 31, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	1,389			$	39
Prepaid expenses and other			264				54
Total current assets			1,653				93
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs			11,432				11,432
Less accumulated depreciation, depletion and amortization			-				-
Net property, plant and equipment			11,432				11,432
Investment in Rhino, net			197,714				61,136
Intangible assets, less accumulated amortization of $-0- and $67, respectively			-				34
TOTAL		$	210,799			$	72,695
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable			-				29
Accrued expenses and other			686				769
Note payable-related parties			504				2,504
Note payable-Rhino			-				4,040
Related party advance and accrued interest payable			42				71
Total current liabilities			1,232				7,413
NON-CURRENT LIABILITIES:
Deferred tax liability			43,396				-
Long-term debt, net of current portion			2,500				-
Total non-current liabilities			45,896				-
Total liabilities			47,128				7,413
STOCKHOLDERS’ EQUITY
Preferred stock: $0.00001 par value; authorized 5,000,000 shares; 51,000 issued and outstanding at September 30, 2017 and authorized 10,000,000 shares; 51,000 issued and outstanding at December 31, 2016
Common stock: $0.00001 par value; authorized 25,000,000 shares; 18,079,293 shares issued and outstanding at September 30, 2017 and authorized 500,000,000; 18,079,293 shares issued and outstanding at December 31, 2016.			1				1
Additional paid-in capital			46,861				47,295
Stock subscription receivable			-				(213	)
Accumulated other comprehensive income			1,440				874
Treasury stock			(4,126	)			-
Retained earnings (accumulated deficit)			90,415				(20,579	)
Total stockholders’ equity owned by common shareholders			134,591				27,378
Total non-controlling interest			29,080				37,904
Total stockholders’ equity			163,671				65,282
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	210,799			$	72,695

 

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands, except per unit data)

 

		Three Months								Nine Months
		Ended September 30,								Ended September 30,
		2017				2016				2017				2016
REVENUES:
Revenues		$	-			$	-			$	-			$	-
Total revenues			-				-				-				-
COSTS AND EXPENSES:
Depreciation, depletion and amortization			-				17				34				50
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)			463				436				1,350				1,488
Total costs and expenses			463				453				1,384				1,538
(LOSS)/INCOME FROM OPERATIONS			(463	)			(453	)			(1,384	)			(1,538	)
INTEREST AND OTHER (EXPENSE)/INCOME:
Interest income
Other			1				-				1				1
Related party			-				2				-				5
Interest expense
Other			(88	)			(54	)			(146	)			(93	)
Related Party			(89	)			(3	)			(95	)			(9	)
Gain on bargain purchase			-				-				171,151				-
Equity in net income from Rhino			(33	)			1,586				(20,538	)			2,907
Total interest and other (expense)/income			(209	)			1,531				150,373				2,811
NET (LOSS)/INCOME FROM OPERATIONS BEFORE INCOME TAXES			(672	)			1,078				148,989				1,273
INCOME TAXES			(635	)			-				43,396				-
NET (LOSS)/INCOME FROM OPERATIONS			(37	)			1,078				105,593				1,273
NET (LOSS/ INCOME BEFORE NON-CONTROLLING INTEREST			(37	)			1,078				105,593				1,273
Less net (loss)/income attributable to non-controlling interest			(15	)			166				(9,288	)			196
NET (LOSS)/INCOME ATTRIBUTABLE TO COMPANY’S STOCKHOLDERS		$	(22	)		$	912			$	114,881			$	1,077
Net(loss)/income per share, basic and diluted		$	(0.00	)		$	0.05			$	6.63			$	0.07
Weighted average shares outstanding, basic and diluted			18,079,293				16,699,036				17,325,596				15,624,438

 

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

 

		Nine Months Ended September 30,
		2017				2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	105,593			$	1,273
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation, depletion and amortization			34				50
Bargain purchase gain			(171,151	)			-
Equity in net loss of Rhino			20,538				(2,907	)
Deferred income taxes			43,396				-
Value of common shares issued for services			250				-
Accrued interest income-related party			-				5
Accrued interest expense-related party			9				9
Changes in assets and liabilities:
Prepaid expenses and other assets			139				56
Accounts payable			(28	)			(31	)
Accrued expenses and other liabilities			(74	)			447
Net cash used in operating activities			(1,294	)			(1,098	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in Rhino Resource Partners, LP			-				(11,500	)
Investment in Blaze Mining royalty			-				150
Sale of Rhino preferred and common units			2,300				-
Net cash provided by (used in) investing activities			2,300				(11,350	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from related party loans			85				5,050
Note payable converted to Royal shares			-				-
Repayments on related party loans			(2,000	)			(5,000	)
Proceeds from issuance of common stock			120				1,183
Proceeds from issuance of convertible notes			-				2,150
Net proceeds from note payable			2,150				2,000
Net cash provided by financing activities			355				5,383
NET (DECREASE) IN CASH AND CASH EQUIVALENTS			1,361				(7,065	)
CASH AND CASH EQUIVALENTS—Beginning of period			28				7,104
CASH AND CASH EQUIVALENTS—End of period		$	1,389			$	39

 

 

22	SUBSEQUENT EVENTS

 

On October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy Court. The Partnership is evaluating the Chapter 11 petitions filed by Armstrong Energy and the Partnership will further evaluate the detailed restructuring plan when it is submitted by Armstrong Energy to determine what, if any, effect the ultimate outcome of the Chapter 11 proceedings will have on the Partnership’s financial statements.

 

On November 7, 2017, the Partnership closed an agreement with a third party to transfer 100% of the memberships interests and related assets and liabilities in the Partnership’s Sands Hill Mining entity to the third party in exchange for a future override royalty for any mineral sold, excluding coal, from Sands Hill Mining after the closing date. The Partnership expects to recognize a gain from the sale of Sands Hill since the third party will assume the reclamation obligations associated with this operation.

 

 

ITEM 2:

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or similar terms refer to Royal Energy Resources, Inc (the “Company”)., Rhino Resource Partners LP and its subsidiaries, in total. References to “Rhino” or “the Partnership” refer to Rhino Resource Partners, LP. References to “General Partner” refer to Rhino GP LLC, General Partner of Rhino Resource Partners LP. The following discussion of the historical financial condition and results of operations should be read in conjunction with the historical audited consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in such Annual Report on Form 10-K.

 

In August 2016, we sold our Elk Horn coal leasing company (“Elk Horn”) to a third party for total cash consideration of $12.0 million. Our unaudited condensed consolidated statements of operations and comprehensive income have been retrospectively adjusted to reclassify our Elk Horn operations to discontinued operations for the three and nine months ended September 30, 2016.

 

Overview

 

The Company previously pursued gold, silver, copper and rare earth metals mining concessions in Romania and mining leases in the United States. Commencing in January 2015, the Company began a series of transactions under which the Company would dispose of all of its existing assets, undergo a change in ownership control and management, and repurpose itself as a North American energy recovery company, with plans to purchase a group of synergistic, long-lived energy assets by taking advantage of favorable valuations for mergers and acquisitions in the current energy markets. In April 2015, the Company completed its first acquisition in furtherance of its change in principal operations, consisting of 40,976 net acres of coal and coalbed methane, located across 22 counties in West Virginia. In June 2015, the Company completed the acquisition of Blue Grove Coal, LLC, a licensed operator of a coal mine owned by GS Energy, LLC. See below regarding acquisition of majority control of Rhino Resource Partners, LP (“Rhino”). See Notes 1 and 3 to the unaudited condensed consolidated financial statements for additional completed acquisitions.

 

Current management of the Company acquired control of the Company in March 2015, with the goal of using the Company as a vehicle to acquire undervalued natural resource assets. The Company has raised approximately $8.4 million through the sale of shares of common stock in private placements, and is currently evaluating a number of possible acquisitions of operating coal mines and non-operating coal assets. There are currently many coal assets for sale at attractive prices due to distressed conditions in the coal industry. The distressed conditions are mainly due to new environmental regulations, which have increased operating costs for coal operators, and have encouraged coal buyers to switch to less costly energy sources, such as natural gas. The resulting drop in demand from coal buyers has caused the price of coal to decline considerably, and caused bankruptcy filings by many of the major coal operators. Despite the current distress in the industry, industry experts still predict that coal will supply a significant percentage of the nation’s energy needs for the foreseeable future, and thus overall demand for coal will remain significant. Management believes there are a number of attractive acquisition candidates in the coal industry which can be operated profitably at current prices and under the current regulatory environment.

 

 

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

 

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

 

On March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of Rhino GP as well as the 945,526 issued and outstanding subordinated units from Wexford. Royal obtained control of, and a majority limited partner interest in Rhino with the completion of this transaction.

 

Overview after Rhino Acquisition

 

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

 

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2016, we controlled an estimated 256.9 million tons of proven and probable coal reserves, consisting of an estimated 203.5 million tons of steam coal and an estimated 53.4 million tons of metallurgical coal. In addition, as of December 31, 2016, we controlled an estimated 196.5 million tons of non-reserve coal deposits.

 

We operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate may vary from time to time depending on a number of factors, including demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

 

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

 

For the three and nine months ended September 30, 2017, we generated revenues of approximately $58.3 million and $168.4 million, respectively, and we generated net loss of $0.1 million for the three months ended September 30, 2017 and net income of $105.6 million for the nine months ended September 30, 2017. For the three months ended September 30, 2017, we produced and sold approximately 1.1 million tons of coal, of which approximately 35% were sold pursuant to long-term supply contracts. For the nine months ended September 30, 2017, we produced and sold approximately 3.1 million tons of coal, of which approximately 65% were sold pursuant to long-term supply contracts.

 

 

Current Liquidity and Outlook

 

Since our credit facility has an expiration date of December 31, 2017, we determined that our credit facility debt liability at September 30, 2017 and December 31, 2016 of $9.9 million and $10.0 million, respectively, should be classified as a current liability on our unaudited condensed consolidated statements of financial position. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months.

 

We are evaluating and negotiating alternative credit facilities. We currently anticipate repaying the debt outstanding under our credit facility with the proceeds from one of these alternative facilities in the fourth quarter of 2017. If it becomes apparent this refinancing will not occur prior to December 31, 2017, we may seek a short-term extension of the Partnership’s existing credit facility. There can be no assurance that we will be able to refinance our credit facility or that the lenders will be willing to grant an extension to provide us with additional time to refinance. If we are unable to secure a replacement facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including repaying amounts due under our credit facility upon expiration, which could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements, we may not be able to continue as a going concern. For more information about our liquidity and our credit facility, please read “—Liquidity and Capital Resources.”

 

Further, even if we are able to refinance our credit facility, the replacement credit facility may include a significantly higher interest rate, significant amortization payments, or liens on a substantial portion of our assets, all of which could adversely impact our future plans and operations.

 

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

 

As of September 30, 2017, our available liquidity was $9.6 million, including cash on hand of $1.4 million and $8.2 million available under our amended and restated credit agreement. On May 13, 2016, we entered into a fifth amendment (the “Fifth Amendment”) of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintains the amount available for letters of credit at $30 million. As of December 31, 2016, we met the requirements to extend the maturity date of the credit facility to December 31, 2017. In December 2016, we entered into a seventh amendment (the “Seventh Amendment”) of our amended and restated credit agreement. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provided for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. For more information about our amended and restated credit agreement, please read “—Recent Developments—Amended and Restated Credit Agreement Amendments” below.

 

As of September 30, 2017, beyond the operations of Rhino, the Company has no established sources of revenues sufficient to fund the development of its business, or to pay projected operating expenses and commitments for the next year. Since the current maturity date of our credit facility is December 31, 2017, we were unable to demonstrate that we had sufficient liquidity to operate our business over the next twelve months from the date of filing our Annual Report on Form 10-K and thus substantial doubt was raised by our auditors about our ability to continue as a going concern.

 

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

 

 

Recent Developments

 

Sands Hill Disposition

 

On November 7, 2017, we closed an agreement with a third party to transfer 100% of the memberships interests and related assets and liabilities in our Sands Hill Mining entity to the third party in exchange for a future override royalty for any mineral sold, excluding coal, from Sands Hill Mining after the closing date. We expect to recognize a gain from the sale of Sands Hill since the third party will assume the reclamation obligations associated with this operation.

 

Option Agreement

 

On December 30, 2016, Royal entered into the Option Agreement with Rhino, Rhino Resources Partners Holdings, LLC (“Rhino Holdings”) and Rhino GP. Rhino Holdings is an entity wholly owned by certain investment partnerships managed by Yorktown Partners LLC (“Yorktown”), and the General Partner. Upon execution of the Option Agreement, Rhino received a Call Option from Rhino Holdings to acquire substantially all of the outstanding common stock of Armstrong Energy that is owned by investment partnerships managed by Yorktown, which currently represent approximately 97% of the outstanding common stock of Armstrong Energy. Armstrong Energy is a coal producing company with approximately 567 million tons of proven and probable reserves and five mines located in the Illinois Basin in western Kentucky as of December 31, 2016. The Option Agreement stipulates that Rhino can exercise the Call Option no earlier than January 1, 2018 and no later than December 31, 2019. In exchange for Rhino Holdings granting the Call Option, Rhino issued 5.0 million Call Option Premium Units to Rhino Holdings upon the execution of the Option Agreement. The Option Agreement stipulates Rhino can exercise the Call Option and purchase the common stock of Armstrong Energy in exchange for a number of common units to be issued to Rhino Holdings, which when added with the Call Option Premium Units, will result in Rhino Holdings owning 51% of the fully diluted common units of Rhino. The purchase of Armstrong Energy through the exercise of the Call Option would also require Royal to transfer a 51% ownership interest in Rhino GP to Rhino Holdings. The ability to exercise the Call Option is conditioned upon (i) sixty (60) days having passed since the entry by Armstrong Energy into an agreement with its bondholders to restructure its bonds and (ii) the amendment of our revolving credit facility to permit the acquisition of Armstrong Energy. The percentage ownership of Armstrong Energy represented by the Armstrong Shares as of the date the Call Option is exercised is subject to dilution based upon the terms under which Armstrong Energy restructures its indebtedness, the terms of which have not been determined.

 

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

 

The Option Agreement contains customary covenants, representations and warranties and indemnification obligations for losses arising from the inaccuracy of representations or warranties or breaches of covenants contained in the Option Agreement, the Seventh Amendment (defined below) and the GP Amendment (defined below). Upon the request by Rhino Holdings, we will also enter into a registration rights agreement that provides Rhino Holdings with the right to demand two shelf registration statements and registration statements on Form S-1 by Rhino, as well as piggyback registration rights for as long as Rhino Holdings owns at least 10% of the outstanding common units of Rhino.

 

 

Pursuant to the Option Agreement, the Second Amended and Restated Limited Liability Company Agreement of General Partner was amended (“GP Amendment”). Pursuant to the GP Amendment, Mr. Bryan H. Lawrence was appointed to the board of directors of the General Partner as a designee of Rhino Holdings and Rhino Holdings has the right to appoint an additional independent director to the General Partner. Rhino Holdings has the right to appoint two members to the board of directors of the General Partner for as long as it continues to own 20% of the common units on an undiluted basis. The GP Amendment also provided Rhino Holdings with the authority to consent to any delegation of authority to any committee of the board of the General Partner. Upon the exercise of the Call Option or the Put Option, the Second Amended and Restated Limited Liability Company Agreement of General Partner, as amended, will be further amended to provide that Royal and Rhino Holdings will each have the ability to appoint three directors and that the remaining director will be the chief executive officer of our General Partner unless agreed otherwise. If the acquisition transaction would close as contemplated herein, with Rhino Holdings owning 51% of both Rhino and Rhino GP, Rhino would no longer be a consolidated subsidiary of Royal but would be an equity method investment.

 

On October 31, 2017, Armstrong Energy filed Chapter 11 petitions in the Eastern District of Missouri’s United States Bankruptcy Court. Per the Chapter 11 petitions, Armstrong Energy will file a detailed restructuring plan as part of the Chapter 11 proceedings. Based on the uncertain facts and circumstances surrounding the current state of the Armstrong Energy Chapter 11 proceedings, which includes the possibility that we will still exercise the Call Option as outlined in Note 1, we concluded that the value of the Call Option was not impaired as of September 30, 2017.

 

Series A Preferred Unit Purchase Agreement

 

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

 

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

 

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

 

On January 27, 2017, Royal sold 100,000 of its Series A preferred units to Weston and its other 100,000 Series A preferred units to another third party for their original cost.

 

 

Fourth Amended and Restated Partnership Agreement of Rhino’s Limited Partnership

 

On December 30, 2016, Rhino GP entered into the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (“Amended and Restated Partnership Agreement”) to create, authorize and issue the Series A preferred units.

 

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

 

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

 

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

 

Amended and Restated Credit Agreement Amendments

 

In December 2016, Rhino entered into a Seventh Amendment, which allows for the Series A preferred units as outlined in the Fourth Amended and Restated Agreement of Limited Partnership, which is further discussed in “—Fourth Amended and Restated Partnership Agreement”. The Seventh Amendment immediately reduces the revolving credit commitments by $11.0 million and provides for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. The Seventh Amendment alters the maximum leverage ratio to 4.0 to 1.0 effective December 31, 2016 through May 31, 2017 and 3.5 to 1.0 from June 30, 2017 through December 31, 2017. The maximum leverage ratio shall be reduced by 0.50 to 1.0 for every $10.0 million of net cash proceeds, in the aggregate, received after the Seventh Amendment date from (i) the issuance of any equity by us and/or (ii) the disposition of any assets in excess of $2.0 million in the aggregate, provided, however, that in no event will the maximum leverage ratio be reduced below 3.0 to 1.0.

 

 

The Seventh Amendment alters the minimum consolidated EBITDA, as calculated on a rolling twelve months basis, to $12.5 million from December 31, 2016 through May 31, 2017 and $15.0 million from June 30, 2017 through December 31, 2017. The Seventh Amendment alters the maximum capital expenditures allowed, as calculated on a rolling twelve months basis, to $20.0 million through the expiration of the credit facility. A condition precedent to the effectiveness of the Seventh Amendment was the receipt of the $13.0 million of cash proceeds received by us from the issuance of the Series A preferred units pursuant to the Preferred Unit Agreement, which we used to repay outstanding borrowings under the revolving credit facility. Per the Seventh Amendment, the receipt of $13.0 million cash proceeds fulfills the required Royal equity contributions as outlined in the previous amendments to our credit agreement.

 

On March 23, 2017, Rhino entered into an eighth amendment (the “Eighth Amendment”) of its amended and restated credit agreement that allows the annual auditor’s report for the years ending December 31, 2016 and 2015 to contain a qualification with respect to the short-term classification of our credit facility balance without creating a default under the credit agreement.

 

On June 9, 2017, we entered into a ninth amendment (the “Ninth Amendment”) of our amended and restated credit agreement that permitted outstanding letters of credit to be replaced with different counterparties without affecting the revolving credit commitments under the credit agreement. The Ninth Amendment also permits certain lease and sale leaseback transactions under the credit agreement that do not affect the revolving credit commitments under the credit agreement for asset dispositions and also do not factor in the calculation of the maximum capital expenditures allowed under the credit agreement.

 

As of September 30, 2017 and December 31, 2016, we were in compliance with respect to all covenants contained in our credit agreement.

 

Factors That Impact Our Business

 

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

 

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

 

We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of September 30, 2017, we had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

 

Year		Tons (in thousands)				Number of customers
2017-Q4			1,329				14
2018			1,825				6
2019			700				2

 

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

 

 

Results of Operations

 

Consolidated Information

 

As noted above, the Company completed the acquisition of control of Rhino on March 17, 2016. Accordingly, the Company began consolidating the operations of Rhino on that date. The following summarizes the financial statements of Royal for the three and nine months ended September 30, 2017 and 2016, which includes the results of operation of Rhino from the date that the Company acquired majority control, as adjusted for changes in the fair value of certain Rhino assets as of the date of the transaction. During the three and nine months ended September 30, 2017, the Company’s only operating activities consisted of Rhino.

 

Our revenues for the three and nine months ended September 30, 2017 and 2016 are summarized as follows:

 

		Three Months								Nine Months
		Ended September 30,								Ended September 30,
		2017				2016				2017				2016
REVENUES:
Coal sales		$	56,460			$	40,992			$	162,951			$	86,675
Freight and handling revenues			220				424				537				1,106
Other revenues			1,666				1,999				4,944				3,406
Total revenues		$	58,346			$	43,415			$	168,432			$	91,187

 

Our costs and expenses for the three and nine months ended September 30, 2017 and 2016 are summarized as follows:

 

		Three Months								Nine Months
		Ended September 30,								Ended September 30,
		2017				2016				2017				2016
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	46,376			$	35,249			$	137,898			$	72,648
Freight and handling costs			1,518				385				2,516				988
Depreciation, depletion and amortization			6,954				1,639				37,071				3,029
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)			3,133				4,717				9,804				11,520
(Gain) on sale/disposal of assets—net			(45	)			(100	)			25				(125	)
Total costs and expenses		$	57,936			$	41,890			$	187,314			$	88,060

 

Interest and other Income/(Expense) for the three and nine months ended September 30, 2017 and 2016 are summarized as follows:

 

 

		Three Months								Nine Months
		Ended September 30,								Ended September 30,
		2017				2016				2017				2016
		(in thousands)
INTEREST AND OTHER (EXPENSE)/INCOME:
Interest expense - related party		$	(89	)		$	(3	)		$	(95	)		$	(9	)
Interest expense - other			(1,079	)			(2,012	)			(3,307	)			(4,071	)
Interest income - related party							2								5
Interest income - other			86				-				87				-
Gain on extinguishment of debt							1,663								1,663
Bargain purchase gain							-				171,151				-
Equity in net loss/(income) of unconsolidated affiliates			-				(27	)			35				(92	)
Total interest and other (Expense)/Income		$	(1,082	)		$	(377	)		$	167,871			$	(2,504	)

 

As of September 30, 2017, we have four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois Basin. Additionally, we have an Other category that includes our ancillary businesses and our remaining oil and natural gas activities. Our Central Appalachia segment consists of two mining complexes: Tug River and Rob Fork, which, as of September 30, 2017, together included one underground mine, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex, and the Leesville field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of September 30, 2017. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of September 30, 2017 (please read Note 22 for further discussion). Our Rhino Western segment includes our underground mine in the Western Bituminous region at our Castle Valley mining complex in Utah. Our Illinois Basin segment includes one underground mine, preparation plant and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our Taylorville field reserves located in central Illinois.

 

Evaluating Our Results of Operations

 

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

 

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

 

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

 

Cost of Operations Per Ton. Cost of operations per ton sold represents the cost of operations (exclusive of depreciation, depletion and amortization) divided by tons of coal sold. Management uses this measurement as a key indicator of the efficiency of operations.

 

 

Summary

 

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the three and nine months ended September 30, 2017 and 2016:

 

		Three months ended September 30,								Nine months ended September 30,
		2017				2016				2017				2016
		(in millions)
Statement of Operations Data:
Total revenues		$	58.3			$	43.4			$	168.4			$	91.2
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)			46.4				35.2				137.9				72.6
Freight and handling costs			1.5				0.4				2.5				1.0
Depreciation, depletion and amortization			7.0				1.6				37.1				3.0
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)			3.1				4.7				9.8				11.5
(Gain) on sale/disposal of assets-net			(0.1	)			-				-				-
Income/(loss) from operations			0.4				1.5				(18.9	)			3.1
Interest and other (expense)/income:
Interest expense			(1.2	)			(2.0	)			(3.4	)			(4.1	)
Interest income			0.1				-				0.1				-
Gain on bargain purchase			-				-				171.2				-
Gain on extinguishment of debt			-				1.7				-				1.7
Income taxes			0.6								(43.4	)
Equity in net (loss)/income of unconsolidated affiliates			-				(0.1	)			-				(0.1	)
Total interest and other (expense)			(0.5	)			(0.4	)			124.5				(2.5	)
Net (loss)/income from continuing operations			(0.1	)			1.1				105.6				0.6
Net income from discontinued operations			-				-				-				0.7
Net (loss)/income		$	(0.1	)		$	1.1			$	105.6			$	1.3
Other Financial Data
Adjusted EBITDA from continuing operations		$	7.5			$	5.1			$	18.3			$	8.1
Adjusted EBITDA from discontinued operations			-				-				-				0.9
Total Adjusted EBITDA		$	7.5			$	5.1			$	18.3			$	9.0

 

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

 

Summary. For the three months ended September 30, 2017, our total revenues increased to $58.3 million from $43.4 million for the three months ended September 30, 2016, which is a 34.4% increase. We sold approximately 1.1 million tons of coal for the three months ended September 30, 2017, which is a 28.8% increase compared to the tons of coal sold for the three months ended September 30, 2016. The increase in revenue and tons sold was primarily the result of increased production in Central Appalachia due to recent increases in coal prices and demand for met and steam coal produced in this region. We anticipate the recent increase in price and demand will continue to benefit our financial results for the remainder of 2017.

 

Net loss from continuing operations was $0.1 million for the three months ended September 30, 2017 compared to net income from continuing operations of $1.1 million for the three months ended September 30, 2016. The decrease in the results was primarily due to the increase in depreciation during the three months ended September 30, 2017, which was the result of the fair value purchase accounting adjustment made during the 2017 reporting period. For the three months ended September 30, 2016, our net income from continuing operations was impacted by an impairment charge of $2.0 million related to the note receivable from the sale of our Deane mining complex.

 

Adjusted EBITDA from continuing operations increased to $7.5 million for the three months ended September 30, 2017 from $5.1 million for the three months ended September 30, 2016. Adjusted EBITDA from continuing operations increased period over period primarily due to the increase in coal revenues at our Central Appalachia segment as coal prices and demand increased in this region.

 

 

Tons Sold. The following table presents tons of coal sold by reportable segment for the three months ended September 30, 2017 and 2016:

 

		Three months				Three months				Increase/
		ended				ended				(Decrease)
Segment		September 30, 2017				September 30, 2016				Tons				% *
		(in thousands, except %)
Central Appalachia			381.6				179.7				201.9				112.4	%
Northern Appalachia			114.5				149.1				(34.6	)			(23.3	%)
Rhino Western			241.9				185.1				56.8				30.7	%
Illinois Basin			315.8				304.5				11.3				3.7	%
Total *			1,053.8				818.4				235.4				28.8	%

 

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

 

We sold approximately 1.1 million tons of coal for the three months ended September 30, 2017, which was a 28.8% increase compared to the three months ended September 30, 2016. The increase in tons sold period over period was primarily due to higher sales from our Central Appalachia segment due to the increased demand for met and steam coal from this region.

 

Tons of coal sold in our Central Appalachia segment increased by approximately 112.4% to approximately 0.4 million tons for the three months ended September 30, 2017 compared to the three months ended September 30, 2016, primarily due to an increase in demand for met and steam coal tons from this region.

 

For our Northern Appalachia segment, tons of coal sold decreased by approximately 23.3% for the three months ended September 30, 2017 compared to the three months ended September 30, 2016, as we experienced a decrease in tons sold from our Sands Hill and Hopedale operations due to weak demand for coal from this region.

 

Coal sales from our Rhino Western segment increased by approximately 30.7% for the three months ended September 30, 2017 compared to the same period in 2016 due to increased customer demand.

 

For our Illinois Basin segment, tons of coal sold increased by approximately 3.7% for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 as we increased production and sales period over period from our Pennyrile mine in western Kentucky to meet our contracted sales commitments.

 

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the three months ended September 30, 2017 and 2016:

 

 

		Three months				Three months
		ended				ended				Increase/(Decrease)
Segment		September 30, 2017				September 30, 2016				$				%*
		(in millions, except per ton data and %)
Central Appalachia
Coal revenues		$	27.9			$	10.4			$	17.5				167.8	%
Freight and handling revenues			-				-				-				n/a
Other revenues			-				-				-				n/a
Total revenues		$	27.9			$	10.4			$	17.5				167.8	%
Coal revenues per ton*		$	73.02			$	57.91			$	15.11				26.1	%
Northern Appalachia
Coal revenues		$	4.6			$	8.8			$	(4.2	)			(48.0	%)
Freight and handling revenues			0.2				0.4				(0.2	)			(48.1	%)
Other revenues			1.6				1.8				(0.2	)			(9.3	%)
Total revenues		$	6.4			$	11.0			$	(4.6	)			(41.7	%)
Coal revenues per ton*		$	39.81			$	58.75			$	(18.94	)			(32.2	%)
Rhino Western
Coal revenues		$	9.1			$	7.2			$	1.9				25.8	%
Freight and handling revenues			-				-				-				n/a
Other revenues			-				-				-				n/a
Total revenues		$	9.1			$	7.2			$	1.9				25.8	%
Coal revenues per ton*		$	37.53			$	39.00			$	(1.47	)			(3.8	%)
Illinois Basin
Coal revenues		$	14.9			$	14.6			$	0.3				2.4	%
Freight and handling revenues			-				-				-				n/a
Other revenues			-				-				-				n/a
Total revenues		$	14.9			$	14.6			$	0.3				2.4	%
Coal revenues per ton*		$	47.37			$	47.97			$	(0.60	)			(1.2	%)
Other**
Coal revenues			n/a				n/a				n/a				n/a
Freight and handling revenues			n/a				n/a				n/a				n/a
Other revenues			-				0.2				(0.2	)			(94.7	%)
Total revenues		$	-			$	0.2			$	(0.2	)			(94.7	%)
Coal revenues per ton*			n/a				n/a				n/a				n/a
Total
Coal revenues		$	56.5			$	41.0			$	15.5				37.7	%
Freight and handling revenues			0.2				0.4				(0.2	)			(48.1	%)
Other revenues			1.6				2.0				(0.4	)			(16.6	%)
Total revenues		$	58.3			$	43.4			$	14.9				34.4	%
Coal revenues per ton*		$	53.58			$	50.09			$	3.49				7.0	%

 

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

 

Our coal revenues for the three months ended September 30, 2017 increased by approximately $15.5 million, or 37.7%, to approximately $56.5 million from approximately $41.0 million for the three months ended September 30, 2016. The increase in coal revenues was primarily due to an increase in met and steam coal tons sold in Central Appalachia as we saw increased demand for met and steam coal from this region during the period. Coal revenues per ton was $53.58 for the three months ended September 30, 2017, an increase of $3.49, or 7.0%, from $50.09 per ton for the three months ended September 30, 2016. This increase in coal revenues per ton was primarily the result of a higher mix of higher priced met coal tons sold in Central Appalachia compared to the prior period.

 

For our Central Appalachia segment, coal revenues increased by approximately $17.5 million, or 167.8%, to approximately $27.9 million for the three months ended September 30, 2017 from approximately $10.4 million for the three months ended September 30, 2016. This increase was primarily due to the increase in coal prices and demand for met and steam coal tons sold from this region. Coal revenues per ton for our Central Appalachia segment increased by $15.11, or 26.1%, to $73.02 per ton for the three months ended September 30, 2017 as compared to $57.91 for the three months ended September 30, 2016, which was primarily due to a higher mix of higher priced met coal tons sold in Central Appalachia compared to the prior period.

 

 

For our Northern Appalachia segment, coal revenues were approximately $4.6 million for the three months ended September 30, 2017, a decrease of approximately $4.2 million, or 48.0%, from approximately $8.8 million for the three months ended September 30, 2016. This decrease was primarily due to a decrease in tons sold from our Sands Hill and Hopedale operations in Northern Appalachia due to weak demand for coal from the Northern Appalachia region during the three months ended September 30, 2017. Coal revenues per ton decreased by $18.94 or 32.2% per ton to $39.81 for the three months ended September 30, 2017 as compared to $58.75 for the three months ended September 30, 2016, which was primarily due to lower prices for tons sold from our Hopedale complex compared to the prior year due to weak demand for coal from this region.

 

For our Rhino Western segment, coal revenues increased by approximately $1.9 million, or 25.8%, to approximately $9.1 million for the three months ended September 30, 2017 from approximately $7.2 million for the three months ended September 30, 2016 primarily due to an increase in tons sold from the Castle Valley mine due to increased customer demand. Coal revenues per ton for our Rhino Western segment decreased by $1.47 or 3.8% to $37.53 per ton for the three months ended September 30, 2017 as compared to $39.00 per ton for the three months ended September 30, 2016 due to lower contracted sales prices.

 

For our Illinois Basin segment, coal revenues of approximately $14.9 million for the three months ended September 30, 2017 increased by approximately $0.3 million, or 2.4%, compared to $14.6 million for the three months ended September 30, 2016. The increase was due to increased sales from our Pennyrile mine in western Kentucky to fulfill our customer contracts. Coal revenues per ton for our Illinois Basin segment were $47.37 for the three months ended September 30, 2017, a decrease of $0.60, or 1.2%, from $47.97 for the three months ended September 30, 2016. The decrease in coal revenues per ton was due to lower contracted prices for tons sold.

 

Other revenues for our Other category were relatively flat for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016.

 

Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the three months ended September 30, 2017 and 2016:

 

 

		Three months				Three months
		ended				ended				Increase/(Decrease)
Segment		September 30, 2017				September 30, 2016				$				%*
		(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	20.8			$	8.9			$	11.9				133.7	%
Freight and handling costs			1.2				-				1.2				n/a
Depreciation, depletion and amortization			2.5				0.4				2.1				525.0	%
Selling, general and administrative			-				-				-				n/a
Cost of operations per ton*		$	54.73			$	49.29			$	5.44				11.0	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	6.6			$	7.8			$	(1.2	)			(15.4	%)
Freight and handling costs			0.3				0.4				(0.1	)			(25.0	%)
Depreciation, depletion and amortization			0.5				0.2				0.3				150.0	%
Selling, general and administrative			-				-				-				n/a
Cost of operations per ton*		$	57.95			$	52.13			$	5.82				11.2	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	6.6			$	5.3			$	1.3				24.5	%
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			1.5				0.3				1.2				400.0	%
Selling, general and administrative			-				-				-				n/a
Cost of operations per ton*		$	27.48			$	28.82			$	(1.34	)			(4.6	%)
Illinois Basin
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	13.0			$	13.4			$	(0.4	)			(3.0	%)
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			2.4				0.7				1.7				242.9	%
Selling, general and administrative			-				0.1				(0.1	)			n/a
Cost of operations per ton*		$	41.40			$	43.99			$	(2.59	)			(5.9	%)
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	(0.6	)		$	(0.2	)		$	(0.4	)			200.0	%
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			0.1				-				0.1				n/a
Selling, general and administrative			3.1				4.6				(1.5	)			(32.6	%)
Cost of operations per ton*			n/a				n/a				n/a				n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	46.4			$	35.2			$	11.2				31.8	%
Freight and handling costs			1.5				0.4				1.1				275.0	%
Depreciation, depletion and amortization			7.0				1.6				5.4				337.5	%
Selling, general and administrative			3.1				4.7				(1.6	)			(34.0	%)
Cost of operations per ton*		$	44.08			$	43.07			$	1.01				2.3	%

 

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

 

Cost of operations per ton and related percentages are calculated using Rhino cost of operations only.

 

** Cost of operations presented for our Other category includes costs incurred by our ancillary businesses and our oil and natural gas investments. The activities performed by these ancillary businesses do not directly relate to coal production. As a result, per ton measurements are not presented for this category.

 

Cost of Operations. Total cost of operations increased by $11.2 million or 31.8% to $46.4 million for the three months ended September 30, 2017 as compared to $35.2 million for the three months ended September 30, 2016. Our cost of operations per ton was $44.08 for the three months ended September 30, 2017, an increase of $1.01, or 2.3%, from the three months ended September 30, 2016. The increase in cost of operations was primarily due to the $11.9 million increase in cost of production at our Central Appalachia operations as demand for met and steam coal increased in this region. Cost of operations per ton increased due to higher maintenance costs and costs for outside services.

 

Our cost of operations for the Central Appalachia segment increased by $11.9 million, or 133.7%, to $20.8 million for the three months ended September 30, 2017 from $8.9 million for the three months ended September 30, 2016. Our cost of operations per ton of $54.73 for the three months ended September 30, 2017 was an increase of 11.0% compared to $49.29 per ton for the three months ended September 30, 2016. Total cost of operations increased period over period as we increased production in this region during the three months ended September 30, 2017 due to increased demand for met and steam coal.

 

 

In our Northern Appalachia segment, our cost of operations decreased by $1.2 million, or 15.4%, to $6.6 million for the three months ended September 30, 2017 from $7.8 million for the three months ended September 30, 2016. Our cost of operations per ton was $57.95 for the three months ended September 30, 2017, an increase of $5.82, or 11.2%, compared to $52.13 for the three months ended September 30, 2016. The decrease in total cost of operations in Northern Appalachia was due to a decrease in sales in this region in response to weak market demand. The increase in the cost of operations on a per ton basis was primarily due to fixed operating costs being allocated to fewer tons of coal sold during the current period.

 

Our cost of operations for the Rhino Western segment increased by $1.3 million, or 24.5%, to $6.6 million for the three months ended September 30, 2017 from $5.3 million for the three months ended September 30, 2016. Total cost of operations increased for the three months ended September 30, 2017 compared to the same period in 2016 due to increased tons produced and sold from our Castle Valley operation. Our cost of operations per ton was $27.48 for the three months ended September 30, 2017, a decrease of $1.34, or 4.6%, compared to $28.82 for the three months ended September 30, 2016. Cost of operations per ton decreased for the three months ended September 30, 2017 compared to the same period in 2016 due to an increase in tons sold from our Castle Valley mine in the current period.

 

Cost of operations in our Illinois Basin segment was $13.0 million while cost of operations per ton was $41.40 for the three months ended September 30, 2017, both of which related to our Pennyrile mining complex in western Kentucky. For the three months ended September 30, 2016, cost of operations in our Illinois Basin segment was $13.4 million and cost of operations per ton was $43.99. The decrease in cost of operations per ton was primarily the result of an increase in tons sold during the current period.

 

Freight and Handling Total freight and handling cost increased to $1.5 million for the three months ended September 30, 2017 as compared to $0.4 million for the three months ended September 30, 2016. The increase in freight and handling costs was primarily the result of rail transportation costs in our Central Appalachia operations as we completed more export coal sales in the current period that require us to pay for railroad transportation to the port of export.

 

Depreciation, Depletion and Amortization. Total DD&A expense for the three months ended September 30, 2017 was $7.0 million as compared to $1.6 million for the three months ended September 30, 2016.

 

For the three months ended September 30, 2017, our depreciation cost increased to $6.8 million compared to $1.6 million for the three months ended September 30, 2016. This increase in depreciation is primarily the result of the purchase accounting fair value adjustments made in the first quarter of 2017 which increased the carrying value of the fixed assets.

 

For the three months ended September 30, 2017, our depletion and amortization cost was $0.2 million.

 

Selling, General and Administrative. SG&A expense for the three months ended September 30, 2017 decreased to $3.1 million as compared to $4.7 million for the three months ended September 30, 2016. This decrease was primarily attributable to the $2.0 million impairment charge related to the note receivable from the sale of our Deane mining complex during the three months ended September 30, 2016.

 

Interest Expense. Interest expense for the three months ended September 30, 2017 decreased to $1.2 million as compared to $2.0 million for the three months ended September 30, 2016. This decrease was primarily due to lower outstanding balances on our senior secured credit facility and reduced debt issuance costs during the three months ended September 30, 2017.

 

Net Income (Loss) from Continuing Operations. The following table presents net income (loss) from continuing operations by reportable segment for the three months ended September 30, 2017 and 2016:

 

 

		Three months ended				Three months ended				Increase
Segment		September 30, 2017				September 30, 2016				(Decrease)
		(in millions)
Central Appalachia		$	(0.3	)		$	(0.3	)		$	-
Northern Appalachia			(0.1	)			2.3				(2.4	)
Rhino Western			(0.1	)			-				(0.1	)
Illinois Basin			(0.2	)			(0.5	)			0.3
Other			0.6				(0.4	)			1.0
Total		$	(0.1	)		$	1.1			$	(1.2	)

 

For the three months ended September 30, 2017, net loss from continuing operations was approximately $0.1 million compared to net income from continuing operations of approximately $1.1 million for the three months ended September 30, 2016. For the three months ended September 30, 2017, our net loss from continuing operations was negatively impacted due to an increase in depreciation expense, which was the result of the fair value purchase accounting adjustment made during the 2017 reporting period. For the three months ended September 30, 2016, our net income from continuing operations was impacted by an impairment charge of $2.0 million related to the note receivable from our Deane mining complex sale and positively impacted by a gain of $1.7 million for extinguishment of debt, which resulted when we settled a $2.8 million note payable to a third party for $1.1 million.

 

For our Central Appalachia segment, net loss from continuing operations was approximately $0.3 million for the three months ended September 30, 2017, remaining flat compared to net loss from continuing operations for the three months ended September 30, 2016.

 

Net loss from continuing operations in our Northern Appalachia segment was $0.1 million for the three months ended September 30, 2017 compared to net income from continuing operations of $2.3 million for the three months ended September 30, 2016. Net income for the three months ended September 30, 2016 was positively impacted by a gain of $1.7 million for extinguishment of debt, which resulted when we settled a $2.8 million note payable to a third party for $1.1 million.

 

Net loss from continuing operations in our Rhino Western segment was $0.1 million for the three months ended September 30, 2017 and remained fairly flat compared to the three months ended September 30, 2016.

 

For our Illinois Basin segment, we generated net loss from continuing operations of $0.2 million for the three months ended September 30, 2017, which was an improvement of $0.3 million compared to the three months ended September 30, 2016. This increase in net income was primarily the result of decreased costs as we continue to optimize production at our Pennyrile mining complex.

 

For the Other category, we had net income from continuing operations of $0.6 million for the three months ended September 30, 2017 as compared to net loss from continuing operations of $0.4 million for the three months ended September 30, 2016, which was impacted by an impairment charge of $2.0 million related to the note receivable from our Deane mining complex sale.

 

Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the three months ended September 30, 2017 and 2016:

 

		Three months ended				Three months ended				Increase
Segment		September 30, 2017				September 30, 2016				(Decrease)
		(in millions)
Central Appalachia		$	2.2			$	0.3			$	2.3
Northern Appalachia			0.4				0.8				(0.4	)
Rhino Western			1.4				0.4				0.9
Illinois Basin			2.2				0.3				1.8
Other			1.3				3.2				(2.1	)
Total *		$	7.5			$	5.1			$	2.4

 

*Totals may not foot due to rounding

 

 

Adjusted EBITDA from continuing operations for the three months ended September 30, 2017 increased by $2.4 million to $7.5 million from $5.1 million for the three months ended September 30, 2016. Adjusted EBITDA from continuing operations increased period over period primarily due to increase in coal sales revenue at our Central Appalachia segment, which was the result of an increase in met and steam coal tons sold due to increased demand in coal produced from this region. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA from continuing operations to net income/(loss) from continuing operations on a segment basis.

 

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

 

The nine months ended 2017 versus 2016 amounts and percentages presented in the following tables and summaries are not comparative since Royal acquired Rhino on March 17, 2016 and thus, only six and half months of Rhino’s financial data is included in the 2016 reporting period. Total tons sold, revenue per ton and cost of operations per ton, however, are reported based on Rhino’s total tons, revenues and cost of operations for the nine months ended September 30, 2016 as that information is comparable to that for 2017 and eliminates the impact of seasonality on these metrics.

 

Summary. For the nine months ended September 30, 2017, our total revenues were $168.4 million compared to $91.2 million for the nine months ended September 30, 2016. We sold approximately 3.1 million tons of coal for the nine months ended September 30, 2017 compared to 2.4 million tons of coal sold for the nine months ended September 30, 2016. Total revenues of $168.4 million was positively impacted by a substantial increase in revenue from our Central Appalachia segment as production and sales increased due to the increase in coal prices and demand for met and steam coal produced in this region.

 

We generated net income from continuing operations of approximately $105.6 million for the nine months ended September 30, 2017 compared to a net income from continuing operations of approximately $0.6 million for the nine months ended September 30, 2016. Our net income from continuing operations improved during the nine months ended September 30, 2017 compared to 2016 due primarily to the bargain purchase gain recognized in the first quarter of 2017.

 

Adjusted EBITDA from continuing operations increased to $18.3 million for the nine months ended September 30, 2017 from $8.1 million for the nine months ended September 30, 2016. Adjusted EBITDA for the nine months ended September 30, 2017 benefited from the increase in revenues in our Central Appalachia segment resulting from the increase in production and sales in this region. Adjusted EBITDA for the nine months ended September 30, 2016 was positively impacted by the $3.9 million prior service cost benefit resulting from the cancellation of the postretirement benefit plan at our Hopedale operation.

 

Including the net income from discontinued operations of approximately $0.7 million, our total net loss and Adjusted EBITDA for the nine months ended September 30, 2016 were $1.3 million and $9.0 million, respectively. We did not incur a gain or loss from discontinued operations for the nine months ended September 30, 2017.

 

Tons Sold. The following table presents tons of coal sold by reportable segment for the nine months ended September 30, 2017 and 2016:

 

		Nine months				Nine months				Increase/
		ended				ended				(Decrease)
Segment		September 30, 2017				September 30, 2016**				Tons				% *
		(in thousands, except %)
Central Appalachia			1,090.7				367.9				722.8				196.4	%
Northern Appalachia			308.4				432.8				(124.4	)			(28.8	%)
Rhino Western			661.7				652.1				9.6				1.5	%
Illinois Basin			1,013.6				953.7				59.9				6.3	%
Total			3,074.4				2,406.5				667.9				27.8	%

 

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

 

** Total tons sold represents all tons sold by Rhino during the nine months ended September 30, 2016.

 

 

We sold approximately 3.1 million tons of coal for the nine months ended September 30, 2017, which was a 27.8% increase compared to the nine months ended September 30, 2016. The increase in tons sold year-to-year was primarily due to higher sales from our Central Appalachia segment due to an increase in demand for met and steam coal from this region.

 

Tons of coal sold in our Central Appalachia segment increased by approximately 196.4% to approximately 1.1 million tons for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, due to an increase in met and steam coal tons sold in the nine months ended September 30, 2017 compared to 2016 resulting from increased market demand for coal from this region.

 

For our Northern Appalachia segment, tons of coal sold decreased by approximately 28.8% for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 as we experienced a decrease in tons sold from our Northern Appalachia segment due to weak demand for coal in this region.

 

Tons of coal sold from our Rhino Western segment remained relatively flat at 0.7 million tons for the nine months ended September 30, 2017 compared to the same period in 2016.

 

For our Illinois Basin segment, tons of coal sold increased by approximately 6.3% for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 as we increased production and sales year-to-year from our Pennyrile mine in western Kentucky to meet our contracted sales commitments.

 

 

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the nine months ended September 30, 2017 and 2016:

 

		Nine months				Nine months
		ended				ended				Increase/(Decrease)
Segment		September 30, 2017				September 30, 2016				$				%*
		(in millions, except per ton data and %)
Central Appalachia
Coal revenues		$	76.8			$	16.0			$	60.8				380.0	%
Freight and handling revenues			-				-				-				n/a
Other revenues			0.1				-				0.1				n/a
Total revenues		$	76.9			$	16.0			$	60.9				380.6	%
Coal revenues per ton*		$	70.38			$	58.62			$	11.76				20.1	%
Northern Appalachia
Coal revenues		$	11.7			$	18.2			$	(6.5	)			(35.7	%)
Freight and handling revenues			0.5				1.1				(0.6	)			(54.5	%)
Other revenues			4.8				4.0				0.8				20.0	%
Total revenues		$	17.0			$	23.3			$	(6.3	)			(27.0	%)
Coal revenues per ton*		$	37.86			$	56.91			$	(19.05	)			(33.5	%)
Rhino Western
Coal revenues		$	25.1			$	18.4			$	6.7				36.4	%
Freight and handling revenues			-				-				-				n/a
Other revenues			-				-				-				n/a
Total revenues		$	25.1			$	18.4			$	6.7				36.4	%
Coal revenues per ton*		$	37.99			$	38.55			$	(0.56	)			(1.4	%)
Illinois Basin
Coal revenues		$	49.4			$	33.3			$	16.1				48.3	%
Freight and handling revenues			-				-				-				n/a
Other revenues			-				-				-				n/a
Total revenues		$	49.4			$	33.3			$	16.1				48.3	%
Coal revenues per ton*		$	48.71			$	47.65			$	1.06				2.2	%
Other**
Coal revenues			n/a				n/a				n/a				n/a
Freight and handling revenues			n/a				n/a				n/a				n/a
Other revenues			-				0.2				(0.2	)			(100.0	%)
Total revenues		$	-			$	0.2			$	(0.2	)			(100.0	%)
Coal revenues per ton*			n/a				n/a				n/a				n/a
Total
Coal revenues		$	163.0			$	85.9			$	77.1				89.8	%
Freight and handling revenues			0.5				1.1				(0.6	)			(54.5	%)
Other revenues			4.9				4.2				0.7				16.7	%
Total revenues		$	168.4			$	91.2			$	77.2				84.6	%
Coal revenues per ton*		$	53.00			$	48.52			$	4.48				9.2	%

 

*	Percentages and per ton amounts are calculated based on actual amounts and not the rounded amounts presented in this table.
	Coal revenues per ton are based on Rhino’s total tons sold and total revenue during the nine months ended September 30, 2016.
**	The Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses also do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Other category.

 

Our coal revenues for the nine months ended September 30, 2017 were approximately $163.0 million compared to $85.9 million for the nine months ended September 30, 2016 as we saw increased tons sold primarily due to increased market demand for coal from our Central Appalachia region. Coal revenues per ton was $53.00 for the nine months ended September 30, 2017, an increase of $4.48, or 9.2%, from $48.52 per ton for the nine months ended September 30, 2016. This increase in coal revenues per ton was primarily due to a higher mix of higher priced met coal tons sold in Central Appalachia compared to the prior period.

 

 

For our Central Appalachia segment, coal revenues were approximately $76.8 million for the nine months ended September 30, 2017 compared to $16.0 million for the nine months ended September 30, 2016, as we saw increased market demand for coal from this segment. Coal revenues per ton for our Central Appalachia segment increased by $11.76, or 20.1%, to $70.38 per ton for the nine months ended September 30, 2017 as compared to $58.62 for the nine months ended September 30, 2016, which was primarily due to a higher mix of higher priced met coal tons sold in Central Appalachia compared to the prior period.

 

For our Northern Appalachia segment, coal revenues were approximately $11.7 million for the nine months ended September 30, 2017 compared to $18.2 million for the nine months ended September 30, 2016. This decrease was primarily due to a decrease in tons sold from our Sands Hill and Hopedale operations in Northern Appalachia due to weak demand for coal from the Northern Appalachia region during the nine months ended September 30, 2017. Coal revenues per ton for our Northern Appalachia segment decreased by $19.05, or 33.5%, to $37.86 per ton for the nine months ended September 30, 2017 as compared to $56.91 per ton for the nine months ended September 30, 2016.

 

For our Rhino Western segment, coal revenues were approximately $25.1 million for the nine months ended September 30, 2017 compared to $18.4 million for the nine months ended September 30, 2016 due primarily to an increase in tons sold from the Castle Valley mine due to increased customer demand. Coal revenues per ton for our Rhino Western segment remained relatively flat at $37.99 for the nine months ended September 30, 2017, compared to $38.55 for the nine months ended September 30, 2016.

 

For our Illinois Basin segment, coal revenues were approximately $49.4 million for the nine months ended September 30, 2017, compared to $33.3 million for the nine months ended September 30, 2016. The increase was due to increased sales from our Pennyrile mine in western Kentucky to fulfill our customer contracts. Coal revenues per ton for our Illinois Basin segment were $48.71 for the nine months ended September 30, 2017, an increase of $1.06, or 2.2%, from $47.65 for the nine months ended September 30, 2016. The increase in coal revenues per ton was due to higher contracted prices for tons sold.

 

 

Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the nine months ended September 30, 2017 and 2016:

 

		Nine months				Nine months
		ended				ended				Increase/(Decrease)
Segment		September 30, 2017				September 30, 2016				$				%*
		(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	59.7			$	16.1			$	43.6				270.8	%
Freight and handling costs			1.8				-				1.8				n/a
Depreciation, depletion and amortization			13.0				0.8				12.2				1525.0	%
Selling, general and administrative			0.2				9.4				(9.2	)			(97.9	%)
Cost of operations per ton*		$	54.76			$	59.23			$	(4.47	)			(7.6	%)
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	18.2			$	13.7			$	4.5				32.8	%
Freight and handling costs			0.7				1.0				(0.3	)			(30.0	%)
Depreciation, depletion and amortization			2.9				0.4				2.5				625.0	%
Selling, general and administrative			0.1				0.1				-				0.0	%
Cost of operations per ton*		$	59.09			$	42.67			$	16.42				38.5	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	20.1			$	14.7			$	5.4				36.7	%
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			7.7				0.7				7.0				1000.0	%
Selling, general and administrative			0.1				-				0.1				n/a
Cost of operations per ton*		$	30.30			$	30.47			$	(0.17	)			(0.6	%)
Illinois Basin
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	41.8			$	29.5			$	12.3				41.7	%
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			12.8				1.0				11.8				1180.0	%
Selling, general and administrative			0.1				0.1				-				n/a
Cost of operations per ton*		$	41.26			$	41.81			$	(0.55	)			(1.3	%)
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) `		$	(1.8	)		$	(1.4	)		$	(0.4	)			28.6	%
Freight and handling costs			-				-				-				n/a
Depreciation, depletion and amortization			0.7				0.1				0.6				600.0	%
Selling, general and administrative			9.3				1.9				7.4				389.5	%
Cost of operations per ton**			n/a				n/a				n/a				n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		$	138.0			$	72.6			$	65.4				90.1	%
Freight and handling costs			2.5				1.0				1.5				150.0	%
Depreciation, depletion and amortization			37.1				3.0				34.1				1136.7	%
Selling, general and administrative			9.8				11.5				(1.7	)			(14.8	%)
Cost of operations per ton*		$	44.91			$	40.77			$	4.14				10.2	%

 

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

 

** Cost of operations presented for our Other category includes costs incurred by our ancillary businesses and our oil and natural gas investments. The activities performed by these ancillary businesses do not directly relate to coal production. As a result, per ton measurements are not presented for this category.

 

 

Cost of Operations. Total cost of operations was $138.0 million for the nine months ended September 30, 2017 as compared to $72.6 million for the nine months ended September 30, 2016. The increase in cost of operations was primarily due to an increase in production at our Central Appalachia operations as demand for met and steam coal increased in this region. Total cost of operations per ton increased primarily due to higher costs in Central Appalachia due to an increase in coal production and sales resulting from increased market demand in this region during the nine months ended September 30, 2017.

 

Our cost of operations for the Central Appalachia segment was approximately $59.7 million compared to $16.1 million for the nine months ended September 30, 2016. We increased production and sales during the current period due to increased met and steam coal demand that resulted in higher cost of operations during the current period compared to the prior period. Our cost of operations per ton of $54.76 for the nine months ended September 30, 2017 was a decrease of 7.6% compared to $59.23 per ton for the nine months ended September 30, 2016. We increased sales during the current period due to increased met and steam coal demand that resulted in lower cost of operations per ton compared to the prior period.

 

In our Northern Appalachia segment, our cost of operations was approximately $18.2 compared to $13.7 million for the nine months ended September 30, 2016. The increase year-over-year was due to Royal’s ownership period for the 2016 included only six and one-half months of production cost. The increase in the cost of operations per ton was primarily due to fixed operating costs being allocated to lower sales tons at our Northern Appalachia segment during the nine months ended September 30, 2017.

 

Our cost of operations for the Rhino Western segment was approximately $20.1 million for the nine months ended September 30, 2017 compared to $14.7 million for the nine months ended September 30, 2016. Total cost of operations increased for the nine months ended September 30, 2017 compared to 2016 primarily due to increased tons produced and sold from our Castle Valley operation. Our cost of operations and cost of operations per ton for our Rhino Western segment were both relatively flat period over period.

 

Cost of operations in our Illinois Basin segment was $41.8 million for the nine months ended September 30, 2017, which related to our Pennyrile mining complex in western Kentucky. During the nine months ended September 30, 2016, cost of operations in our Illinois Basin segment was $29.5 million. The increase year-over-year was due to Royal’s ownership period for the 2016 included only six and one-half months of production cost. The increase in cost of operations per ton remained relatively flat.

 

Freight and Handling. Total freight and handling cost increased to $2.5 million for the nine months ended September 30, 2017 as compared to $1.0 million for the nine months ended September 30, 2016. The increase in freight and handling costs was primarily the result of rail transportation costs in our Central Appalachia operations as we executed more export coal sales in the current period that require us to pay for railroad transportation to the port of export.

 

Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization (“DD&A”) expense for the nine months ended September 30, 2017 was $37.1 million as compared to $3.0 million for the nine months ended September 30, 2016.

 

For the nine months ended September 30, 2017, our depreciation cost was $36.1 million compared to $3.0 million for the nine months ended September 30, 2016 as the result of the fair value purchase adjustments made in the first quarter of 2017.  

 

For the nine months ended September 30, 2017, our depletion cost was $0.9 million and our amortization expense was $0.1 million.

  

Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the nine months ended September 30, 2017 was approximately $9.8 million compared to $11.5 million for the nine months ended September 30, 2016. This decrease was primarily the result of a $2.0 million impairment charge related to the note receivable from the sale of our Deane mining complex during the nine months ended September 30, 2016.

 

Interest Expense. Interest expense for the nine months ended September 30, 2017 was $3.4 million as compared to $4.1 million for the nine months ended September 30, 2016. This decrease was primarily due to lower outstanding balances on our senior secured credit facility. See the discussion on our credit agreement in “Liquidity and Capital Resources - Amended and Restated Credit Agreement.”

 

 

Net Income (Loss) from Continuing Operations. The following table presents net income/(loss) from continuing operations by reportable segment for the nine months ended September 30, 2017 and 2016:

 

		Nine months Ended				Nine months Ended				Increase
Segment		September 30, 2017				September 30, 2016				(Decrease)
		(in millions)
Central Appalachia		$	(10.1	)		$	(0.3	)		$	(9.8	)
Northern Appalachia			(2.2	)			1.2				(3.4	)
Rhino Western			(3.3	)			-				(3.3	)
Illinois Basin			(6.5	)			(0.2	)			(6.3	)
Other			127.7				(0.1	)			127.8
Total		$	105.6			$	0.6			$	105.0

 

For the nine months ended September 30, 2017, total net income from continuing operations was approximately $105.6 million which includes the $171.2 million bargain purchase gain and income tax expense of $43.4 million.

 

For our Central Appalachia segment, net loss from continuing operations was approximately $10.1 million for the nine months ended September 30, 2017, compared to a net loss from continuing operations of $0.3 million for the nine months ended September 30, 2016. The net loss for the nine months ended September 30, 2017 was negatively impacted by additional depreciation expense as the result of the purchase accounting fair value adjustments made in the first quarter of 2017.

 

Net loss from continuing operations in our Northern Appalachia segment was $2.2 million for the nine months ended September 30, 2017 compared to net income of $1.2 million for the nine months ended September 30, 2016. The net income from continuing operations for the 2016 reporting period was positively impacted by the prior service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation. The net loss for the nine months ended September 30, 2017 was negatively impacted by additional depreciation expense as the result of the purchase accounting fair value adjustments made in the first quarter of 2017.

 

Net loss from continuing operations in our Rhino Western segment was $3.3 million for the nine months ended September 30, 2017, compared to break-even for the nine months ended September 30, 2016. The net loss for the nine months ended September 30, 2017 was negatively impacted by additional depreciation expense as the result of the purchase accounting fair value adjustments made in the first quarter of 2017.

 

For our Illinois Basin segment, we generated net loss from continuing operations of $6.5 million for the nine months ended September 30, 2017, compared to net loss from continuing operations of $0.2 million for the nine months ended September 30, 2016. The net loss for the nine months ended September 30, 2017 was negatively impacted by additional depreciation expense as the result of the purchase accounting fair value adjustments made in the first quarter of 2017.

 

For the Other category, we had a net income from continuing operations of $127.7 million for the nine months ended September 30, 2017 which was impacted by the $171.2 million bargain purchase gain partially offset by income tax expense of $43.4 million.

 

Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the nine months ended September 30, 2017 and 2016:

 

		Nine months Ended				Nine months Ended				Increase
Segment		September 30, 2017				September 30, 2016				(Decrease)
		(in millions)
Central Appalachia		$	2.9			$	1.9			$	0.3
Northern Appalachia			0.7				0.1				0.8
Rhino Western			4.4				1.0				3.6
Illinois Basin			6.3				1.4				5.4
Other			4.0				3.6				0.2
Total *		$	18.3			$	8.1			$	10.2

 

*Total may not foot due to rounding

 

 

Adjusted EBITDA from continuing operations was $18.3 million for the nine months ended September 30, 2017 which was primarily the result of the increase in revenues from coal sales at our Central Appalachia operation. Adjusted EBITDA for the nine months ended September 30, 2016 was positively impacted by the $3.9 million prior service cost benefit resulting from the cancellation of the postretirement benefit plan at our Hopedale operation.

 

Reconciliations of Adjusted EBITDA The following tables present reconciliations of Adjusted EBITDA to the most directly comparable GAAP financial measures for each of the periods indicated:

 

		Central				Northern				Rhino				Illinois
Three months ended September 30, 2017		Appalachia				Appalachia				Western				Basin				Other				Total
		(in millions)
Net income/(loss) from continuing operations		$	(0.3	)		$	(0.1	)		$	(0.1	)		$	(0.2	)		$	0.6			$	(0.1	)
Plus:
DD&A			2.5				0.5				1.5				2.4				0.1				7.0
Interest expense			-				-				-				-				1.2				1.2
EBITDA from continuing operations†		$	2.2			$	0.4			$	1.4			$	2.2			$	1.9			$	8.1
Plus: Income taxes			-				-				-				-				(0.6	)			(0.6	)
Adjusted EBITDA from continuing operations†			2.2				0.4				1.4				2.2				1.3				7.5
Adjusted EBITDA from discontinued operations†			-				-				-				-				-				-
Adjusted EBITDA †		$	2.2			$	0.4			$	1.4			$	2.2			$	1.3			$	7.5

 

			Central				Northern				Rhino				Illinois
Three months ended September 30, 2016			Appalachia				Appalachia				Western				Basin				Other				Total*
			(in millions)
Net income/(loss) from continuing operations		$	(0.3	)		$	2.3			$	-			$	(0.5	)		$	(0.4	)		$	1.1
Plus:
DD&A			0.4				0.2				0.3				0.7								1.6
Interest expense			0.2				-				0.1				0.1				1.6				2.0
EBITDA from continuing operations†		$	0.3			$	2.5			$	0.4			$	0.3			$	1.2			$	4.7
Plus: Non-cash asset impairment (1)			-				-				-				-				2.0				2.0
Less: Gain on extinguishment of debt (2)			-				(1.7	)			-				-				-				(1.7	)
Adjusted EBITDA from continuing operations†			0.3				0.8				0.4				0.3				3.2				5.1
Adjusted EBITDA from discontinued operations†			-				-				-				-				-				-
Adjusted EBITDA †		$	0.3			$	0.8			$	0.4			$	0.3			$	3.2			$	5.1

 

		Central				Northern				Rhino				Illinois
Nine months ended September 30, 2017		Appalachia				Appalachia				Western				Basin				Other				Total
		(in millions)
Net income/(loss) from continuing operations		$	(10.1	)		$	(2.2	)		$	(3.3	)		$	(6.5	)		$	127.7			$	105.6
Plus:
DD&A			13.0				2.9				7.7				12.8				0.7				37.1
Interest expense			-				-				-				-				3.4				3.4
EBITDA from continuing operations†		$	2.9			$	0.7			$	4.4			$	6.3			$	131.8			$	146.1
Plus:Income taxes																			43.4				43.4
Less:Gain on bargain purchase			-				-				-				-				(171.2	)			(171.2	)
Adjusted EBITDA from continuing operations†			2.9				0.7				4.4				6.3				4.0				18.3
Adjusted EBITDA from discontinued operations†			-				-				-				-				-				-
Adjusted EBITDA †		$	2.9			$	0.7			$	4.4			$	6.3			$	4.0			$	18.3

 

 

		Central				Northern				Rhino				Illinois
Nine months ended September 30, 2016		Appalachia				Appalachia				Western				Basin				Other				Total*
		(in millions)
Net income/(loss) from continuing operations		$	(0.3	)		$	1.2			$	-			$	(0.2	)		$	(0.1	)		$	0.6
Plus:
DD&A			0.8				0.4				0.7				1.0				0.1				3.0
Interest expense			1.4				0.2				0.3				0.6				1.6				4.1
EBITDA from continuing operations†		$	1.9			$	1.8			$	1.0			$	1.4			$	1.6			$	7.7
Plus: Non-cash asset impairment (1)			-				-				-				-				2.0				2.0
Less: Gain on extinguishment of debt (2)			-				(1.7	)			-				-				-				(1.7	)
Adjusted EBITDA from continuing operations†			1.9				0.1				1.0				1.4				3.6				8.1
Adjusted EBITDA from discontinued operations†			0.9				-				-				-				-				0.9
Adjusted EBITDA †		$	2.8			$	0.1			$	1.0			$	1.4			$	3.6			$	9.0

 

	*	Totals may not foot due to rounding.
	†	EBITDA is calculated based on actual amounts and not the rounded amounts presented in this table.

 

(1)	During the three and nine months ended September 30, 2016, we recorded a $2.0 million asset impairment related to a note receivable that was recorded in 2015 related to the sale of the Deane mining complex discussed earlier. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.
(2)	For the three and nine months ended September 30, 2016, we recorded a gain of approximately $1.7 million for the extinguishment of debt. We executed an agreement with the third party that held approximately $2.8 million of other notes payable to settle the debt for $1.1 million of cash consideration, which resulted in an approximate $1.7 million gain from the extinguishment of this debt. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.

 

Liquidity and Capital Resources

 

Liquidity

 

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

 

Our principal indicators of our liquidity are our cash on hand and availability under our amended and restated credit agreement. As of September 30, 2017, our available liquidity was $9.6 million, including cash on hand of $1.4 million and $8.2 million available under our credit facility. On May 13, 2016, we entered into a Fifth Amendment of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. The Fifth Amendment also immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintained the amount available for letters of credit at $30 million. In December 2016, we entered into a Seventh Amendment of our amended and restated credit agreement. The Seventh Amendment immediately reduced the revolving credit commitments by $11.0 million and provided for additional revolving credit commitment reductions of $2.0 million each on June 30, 2017 and September 30, 2017. The Seventh Amendment further reduced the revolving credit commitments over time on a dollar-for-dollar basis for the net cash proceeds received from any asset sales after the Seventh Amendment date once the aggregate net cash proceeds received exceeds $2.0 million. For more information about our amended and restated credit agreement, please read — “Amended and Restated Credit Agreement.”

 

We are evaluating and negotiating alternative credit facilities. We currently anticipate repaying the debt outstanding under our credit facility with the proceeds from one of these alternative facilities in the fourth quarter of 2017. If it becomes apparent this refinancing will not occur prior to December 31, 2017, we may seek a short-term extension of our existing credit facility. There can be no assurance that we will be able to refinance our credit facility or that the lenders will be willing to grant an extension to provide us with additional time to refinance. If we are unable to secure a replacement facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including repaying amounts due under our credit facility upon expiration, which could cause us to further curtail our operations and reduce our spending and to alter our business plan. Further, even if we are able to refinance our credit facility, the replacement credit facility may include a significantly higher interest rate, significant amortization payments, or liens on a substantial portion of our assets, all of which could adversely impact our future plans and operations.

 

 

We may also be required to consider other options, such as selling additional assets, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. We continue to take measures and cost and productivity improvements, to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures and meet our financial commitments and debt service obligations.

 

At September 30, 2017, beyond the operations of Rhino, the Company has not established sources of revenues sufficient to fund the development of its business, or to pay projected operating expenses and commitments for the next year. Also the current maturity date of Rhino’s credit facility is December 31, 2017, and without an extension of that facility or the successful negotiation of a replacement credit facility, we are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months and thus substantial doubt is raised about our ability to continue as a going concern.

 

Cash Flows

 

Net cash provided by operating activities was $12.0 million for the nine months ended September 30, 2017 as compared to cash provided by operating activities of $3.2 million for the nine months ended September 30, 2016. This increase in cash provided by operating activities for the nine months ended September 30, 2017 was primarily the result of the increase in production and sales in our Central Appalachia segment for the nine months ended September 30, 2017 as compared to 2016 due to increased met coal demand from this region.

 

Net cash used for investing activities was $10.7 million for the nine months ended September 30, 2017 as compared to cash provided by investing activities of $3.5 million for the nine months ended September 30, 2016. Net cash used in investing activities for the nine months ended September 30, 2017 was primarily related to capital expenditures necessary for maintaining our mining operations. Net cash provided by investing activities during the nine months ended September 30, 2016 was significantly impacted by non-recurring payments by the Company totaling $4.5 million to a third-party to acquire a majority interest in Rhino during the period and by proceeds from the Elk Horn sale.

 

Net cash provided by financing activities for the nine months ended September 30, 2017 was $0.0 million. Net cash used in financing activities during the nine months ended September 30, 2016 was $13.7 million, which was attributable to net repayments on Rhino’s revolving credit facility partially offset by $2.2 million in proceeds from convertible debt issued by Royal during this period and proceeds from issuance of common stock of $1.2 million.

 

Capital Expenditures

 

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

 

Actual maintenance capital expenditures for the nine months ended September 30, 2017 were approximately $9.2 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the nine months ended September 30, 2017 were approximately $5.1 million and primarily related to purchases of additional equipment to be used to expand our met coal production capacity in Central Appalachia.

 

 

Amended and Restated Credit Agreement

 

On July 29, 2011, we executed the Amended and Restated Credit Agreement. The maximum availability under the amended and restated credit facility was $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million was available for letters of credit. In April 2015, the Amended and Restated Credit Agreement was amended and the borrowing commitment under the facility was reduced to $100.0 million and the amount available for letters of credit was reduced to $50.0 million. As described below, in March 2016 and May 2016, the borrowing commitment under the facility was further reduced to $80.0 million and $75.0 million, respectively, and the amount available for letters of credit was reduced to $30.0 million. In addition, as described below, the borrowing commitment under the facility was further reduced by amendments in July 2016 and December 2016 to $44.3 million as of September 30, 2017. The amount available for letters of credit was unchanged from these amendments.

 

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

 

Our Amended and Restated Credit Agreement requires us to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock.

 

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

 

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

 

 

The Fifth Amendment required that on or before March 31, 2017, we solicit bids for the potential sale of certain non-core assets, satisfactory to the administrative agent, and provided the administrative agent, and any other lender upon its request, with a description of the solicitation process, interested parties and any potential bids. The Fifth Amendment limits any payments by us to our General Partner to: (i) the usual and customary payroll and benefits of the our management team so long as our management team remains employees of our General Partner, (2) the usual and customary board fees of our General Partner, and (3) the usual and customary general and administrative costs and expenses of our General Partner incurred in connection with the operation of its business in an amount not to exceed $0.3 million per fiscal year. The Fifth Amendment limits asset sales to a maximum of $5.0 million unless we receive consent from the lenders. The Fifth Amendment removes the $5.0 million minimum liquidity requirement and requires us to have any deposit, securities or investment accounts with a member of the lending group.

 

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

 

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

 

On March 23, 2017, we entered into an Eighth Amendment (“Eighth Amendment”) of our amended and restated credit agreement that allows the annual auditor’s report for the years ending December 31, 2016 and 2015 to contain a qualification with respect to the short-term classification of our credit facility balance without creating a default under the credit agreement.

 

On June 9, 2017, we entered into a ninth amendment (the “Ninth Amendment”) of our amended and restated credit agreement that permitted outstanding letters of credit to be replaced with different counterparties without affecting the revolving credit commitments under the credit agreement. The Ninth Amendment also permits certain lease and sale leaseback transactions under the credit agreement that do not affect the revolving credit commitments under the credit agreement for asset dispositions and also do into factor in the calculation of the maximum capital expenditures allowed under the credit agreement.

 

 

As of and for the twelve months ended September 30, 2017, we are in compliance with respect to all covenants contained in the credit agreement.

 

At September 30, 2017, Rhino had borrowings outstanding (excluding letters of credit) of $9.9 million at a variable interest rate of PRIME plus 3.50% (7.75% at September 30, 2017). In addition, the Operating Company had outstanding letters of credit of approximately $26.1 million at a fixed interest rate of 5.00% at September 30, 2017. Based upon a maximum borrowing capacity of 3.50 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had available borrowing capacity of approximately $8.2 million at September 30, 2017. During the three months ended September 30, 2017, we had average borrowings outstanding of approximately $12.6 million under our credit agreement.

 

Off-Balance Sheet Arrangements

 

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

 

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

 

As of September 30, 2017, we had $26.1 million in letters of credit outstanding, of which $20.7 million served as collateral for surety bonds.

 

Critical Accounting Policies and Estimates

 

Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates and judgments on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Nevertheless, actual results may differ from the estimates used and judgments made.

 

The accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are fully described in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no significant changes in these policies and estimates as of September 30, 2017.

 

Recent Accounting Pronouncements

 

Refer to Item 1. Note 2 of the notes to the unaudited condensed consolidated financial statements for a discussion of recent accounting pronouncements, which is incorporated herein by reference. There are no known future impacts or material changes or trends of new accounting guidance beyond the disclosures provided in Note 2.

 

 

ITEM 3: Quantitative and Qualitative Disclosures About Market Risk

 

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

 

Commodity Price Risk

 

We manage our commodity price risk for coal sales through the use of supply contracts. As of September 30, 2017, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

 

Year		Tons (in thousands)				Number of customers
2017-Q4			1,329				14
2018			1,825				6
2019			700				2

 

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

 

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

 

A hypothetical increase of $0.10 per gallon for diesel fuel would have increased net loss before income taxes by $0.1 million for the three months ended September 30, 2017 and would have decreased net income before income taxes by $0.3 million for the nine months ended September 30, 2017. A hypothetical increase of 10% in steel prices would have increased net loss before income taxes by $0.2 million for the three months ended September 30, 2017 and would have decreased net income before income taxes by $0.7 million for the nine months ended September 30, 2017. A hypothetical increase of 10% in explosives prices would have increased net loss before income taxes by $0.1 million for the three months ended September 30, 2017 and would have reduced net income before income taxes by $0.3 million for the nine months ended September 30, 2017.

 

Interest Rate Risk

 

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $25,000 for the three months ended September 30, 2017 and would have reduced net income before income taxes by $75,000 for the nine months ended September 30, 2017.

 

ITEM 4: Controls and Procedures

 

(a) Evaluation of Disclosure Controls and Procedures

 

Under the PCAOB standards, a control deficiency exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent or detect misstatements on a timely basis. A significant deficiency is a deficiency, or a combination of deficiencies, in internal control over financial reporting that is less severe than a material weakness, yet important enough to merit the attention by those responsible for oversight of the Company’s financial reporting. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

 

 

Under the supervision and with the participation of our management, including our principal executive officer and chief financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act), as of September 30, 2017. Based on that evaluation, our chief executive officer and chief financial officer concluded that, as of the evaluation date, such controls and procedures were not effective.

 

(b) Changes in Internal Controls

 

We have made no change in internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act) during the nine months ended September 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. However, in our Form 10-K for the year ended December 31, 2016, we disclosed that our internal control over financial reporting was not effective in the following areas:

 

Segregation of Duties: We do not have sufficient controls over financial reporting due to a lack of segregation of duties. Specifically:

 

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

 

Financial Close, Consolidation and Reporting: Royal (exclusive of Rhino) does not have effective internal controls over our financial close, consolidation and reporting process. During 2016, beginning with the acquisition of controlling interest in Rhino, our financial reporting complexities increased significantly without a corresponding increase in our resources dedicated to maintenance of a control structure and the preparation of financial information to be included in its public filings.

 

We are evaluating various plans to restructure our financial closing process, including engaging additional personnel experienced in financial reporting and evaluating the time commitment and responsibilities of those currently assigned such responsibilities. Although we have begun the process of establishing the necessary controls and procedures, these changes have not yet been fully implemented at September 30, 2017.

 

PART II - OTHER INFORMATION

 

Item 1: Legal Proceedings

 

None

 

ITEM 1A: Risk Factors

 

In addition to the other information set forth in this Report, you should carefully consider the risks under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016, which risks could materially affect our business, financial condition or future results. There has been no material change in our risk factors from those described in the Annual Report on Form 10-K for the year ended December 31, 2016. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

 

ITEM 2: Unregistered Sales of Equity Securities and Use of Proceeds

 

During the three months ending September 30, 2017, the Company issued 914,797 shares of common stock to Rhino in conversion of two notes held by Rhino with a balance of $4.1 million. The shares were issued pursuant to an exemption from registration provided by Section 4(a)(2) of the Securities Act of 1933, as amended.

 

ITEM 3: Defaults upon Senior Securities.

 

None.

 

 

ITEM 4: Mine Safety Disclosures.

 

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the three months ended September 30, 2017 is included in Exhibit 95.1 to this report.

 

ITEM 5: Other Information.

 

None.

 

ITEM 6: Exhibits

 

	Exhibit No.		Description
	31.1*		Certification pursuant to 18 U.S.C. Section 1350 Section 302 of the Sarbanes-Oxley Act of 2002
	31.2*		Certification pursuant to 18 U.S.C. Section 1350 Section 302 of the Sarbanes-Oxley Act of 2002
	32.1*		Certification pursuant to 18 U.S.C. Section 1350 Section 906 of the Sarbanes-Oxley Act of 2002
	32.2*		Certification pursuant to 18 U.S.C. Section 1350 Section 906 of the Sarbanes-Oxley Act of 2002
	95*		Mine Safety Disclosure
	101.INS**		XBRL Instance Document
	101.SCH**		XBRL Taxonomy Extension Schema Document
	101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
	101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document
	101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
	101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

 

*Filed herewith.

 

**In accordance with Regulation S-T, the XBRL-formatted interactive data files that comprise Exhibit 101 in this Quarterly Report on Form 10-Q shall be deemed “furnished” and not “filed”

 

 

SIGNATURES

 

Pursuant to the requirements 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.

 

Date: November 14, 2017	Royal Energy Resources, Inc.
	By:	/s/ William L. Tuorto
		William L. Tuorto
		CEO, Principal Executive Officer
	By:	/s/ Douglas C. Holsted
		Douglas C. Holsted
		CFO, Principal Financial Officer