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EX-95.1 - Royal Energy Resources, Inc.ex95-1.htm
EX-32.2 - Royal Energy Resources, Inc.ex32-2.htm
EX-32.1 - Royal Energy Resources, Inc.ex32-1.htm
EX-31.2 - Royal Energy Resources, Inc.ex31-2.htm
EX-31.1 - Royal Energy Resources, Inc.ex31-1.htm

 

 

 

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: June 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: 17,164,496 shares of common stock issued and outstanding as of August 10, 2017.

 

 

 

   

 

 

TABLE OF CONTENTS

 

PART I – FINANCIAL INFORMATION 4
     
ITEM 1: Financial Statements 4
     
ITEM 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations 30
     
ITEM 3: Quantitative and Qualitative Disclosures About Market Risk 60
     
ITEM 4: Controls and Procedures 61
     
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 62
     
ITEM 3: Defaults upon Senior Securities. 62
     
ITEM 4: Mine Safety Disclosures. 62
     
ITEM 5: Other Information. 62
     
ITEM 6: Exhibits 62
     
SIGNATURES 63

 

 2 

 

 

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; the consummation of the acquisition of Armstrong Energy, Inc. from, and the transfer of 51% of our general partnership interest in Rhino Resource Partners, LP to, Yorktown Partners LLC; our ability to realize the expected benefits of an acquisition of Armstrong Energy, Inc.; 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.

 

 3 

 

 

PART I.—FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands)

 

   June 30, 2017   December 31, 2016 
   (Unaudited)   (Audited) 
ASSETS          
CURRENT ASSETS:          
Cash and cash equivalents  $1,903   $86 
Accounts receivable, less allowance for bad debts of $0 as of June 30, 2017 and December 31, 2016   19,579    13,893 
Inventories   10,471    8,050 
Advance royalties, current portion   931    898 
Investment in available for sale securities   10,580    3,532 
Prepaid expenses and other   4,764    4,929 
Total current assets   48,228    31,388 
PROPERTY, PLANT AND EQUIPMENT:          
At cost, including coal properties, mine development and construction costs   244,079    69,684 
Less accumulated depreciation, depletion and amortization   (34,076)   (4,572)
Net property, plant and equipment   210,003    65,112 
Advance royalties, net of current portion   7,767    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   27,576    27,591 
TOTAL  $315,454   $166,242 
LIABILITIES AND EQUITY          
CURRENT LIABILITIES:          
Accounts payable   12,888    10,447 
Accrued expenses and other   15,763    11,405 
Notes payable-related party   504    504 
Current portion of long-term debt   12,290    12,040 
Current portion of asset retirement obligations   917    917 
Related party advance and accrued interest payable   78    71 
Total current liabilities   42,440    35,384 
NON-CURRENT LIABILITIES:          
Deferred tax liability   44,031    - 
Long-term debt, net of current portion   2,500    - 
Asset retirement obligations, net of current portion   20,102    26,503 
Other non-current liabilities   39,958    39,073 
Total non-current liabilities   106,591    65,576 
Total liabilities   149,031    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 June 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; 17,184,095 shares issued and outstanding at June 30, 2017 and authorized 500,000,000; 17,212,278 shares issued and outstanding at December 31, 2016.   1    1 
Additional paid-in capital   47,715    47,295 
Stock subscription receivable   -    (213)
Accumulated other comprehensive income   1,978    874 
Retained earnings (accumulated deficit)   87,183    (20,579)
Total stockholders’ equity owned by common shareholders   136,877    27,378 
Non-controlling interest   29,546    37,904 
Total stockholders’ equity owned by common shareholders   166,423    65,282 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY  $315,454   $166,242 

 

See notes to unaudited condensed consolidated financial statements.

 

 4 

 

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands, except per unit data)

 

   Three Months   Six Months 
   Ended June 30,   Ended June 30, 
   2017   2016   2017   2016 
REVENUES:                    
Coal sales  $54,710   $39,106   $106,491   $45,684 
Freight and handling revenues   187    581    318    682 
Other revenues   1,638    1,926    3,276    1,406 
Total revenues   56,535    41,613    110,085    47,772 
COSTS AND EXPENSES:                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   46,592    33,361    91,522    37,400 
Freight and handling costs   228    516    997    603 
Depreciation, depletion and amortization   6,978    1,319    30,117    1,377 
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)   3,277    4,505    6,671    6,779 
Loss on sale/disposal of assets—net   71    -    70    - 
Total costs and expenses   57,146    39,701    129,377    46,159 
(LOSS)/INCOME FROM OPERATIONS   (611)   1,912    (19,292)   1,613 
INTEREST AND OTHER (EXPENSE)/INCOME:                    
Interest income                    
Other   -    31    -    37 
Related party   -    2    -    3 
Interest expense             -    - 
Other   (1,012)   (1,759)   (2,228)   (2,094)
Related Party   (3)   (3)   (6)   (6)
Equity in net income/(loss) of unconsolidated affiliates   40    (26)   36    (65)
Gain on bargain purchase   -    -    171,151    - 
Total interest and other (expense)/income   (975)   (1,755)   168,953    (2,125)
NET (LOSS)/INCOME BEFORE INCOME TAXES FROM CONTINUING OPERATIONS   (1,586)   157    149,661    (512)
INCOME TAXES   -    -    44,031    - 
NET (LOSS)/INCOME FROM CONTINUING OPERATIONS   (1,586)   157    105,630    (512)
DISCONTINUED OPERATIONS (NOTE 4)        -         - 
Income from discontinued operations   -    420    -    1,339 
NET (LOSS)/INCOME BEFORE NON-CONTROLLING INTEREST   (1,586)   577    105,630    827 
Less net (loss)/income attributable to non-controlling interest   (452)   84    (9,273)   121 
NET (LOSS)/INCOME ATTRIBUTABLE TO COMPANY’S STOCKHOLDERS   (1,134)   493    114,903    706 
Other comprehensive income:                    
Fair market value adjustment for available-for-sale investment   554    -    2,021    - 
Less comprehensive income attributable to non-controlling interest   252    -    915    - 
COMPREHENSIVE (LOSS)/INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS  $(832)  $493   $116,009   $706 
                     
Net (loss)/income per share, basic and diluted                    
Continuing operations  $(0.07)  $0.01   $6.68   $(0.03)
Discontinued operations   -    0.02    -    0.07 
   $(0.07)  $0.03   $6.68   $0.05 
                     
Weighted average shares outstanding, basic and diluted   17,207,883    16,699,036    17,203,109    15,624,438 

 

See notes to unaudited condensed consolidated financial statements.

 

 5 

 

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

   Six Months Ended June 30, 
   2017   2016 
CASH FLOWS FROM OPERATING ACTIVITIES:          
Net income  $105,630   $827 
Adjustments to reconcile net income to net cash provided by operating activities:          
Depreciation, depletion and amortization   30,117    1,703 
Accretion on asset retirement obligations   860    382 
Amortization of deferred revenue   -    (555)
Amortization of advance royalties   567    351 
Amortization of debt issuance costs   720    435 
Loss on retirement of advance royalties   140    27 
(Gain) on sale/disposal of assets—net   70    - 
(Gain) on bargain purchase   (171,151)   - 
Equity in net loss of unconsolidated affiliates   (36)   26 
Equity-based compensation   260    803 
Value of common shares issued for services   250    - 
Accrued interest income-related party   -    (3)
Accrued interest expense-related party   -    6 
Changes in assets and liabilities:          
Accounts receivable   (5,933)   (777)
Inventories   (2,421)   (2,419)
Advance royalties   (855)   (88)
Prepaid expenses and other assets   (1,378)   (1,605)
Accounts payable   2,229    2,223 
Accounts payable-related party   6    9 
Accrued expenses and other liabilities   3,470    1,420 
Deferred income taxes   44,031    - 
Asset retirement obligations   (34)   (72)
Net cash provided by operating activities   6,542    2,693 
CASH FLOWS FROM INVESTING ACTIVITIES:          
Investment in Rhino Resource Partners, LP   -    (4,500)
Investment in Blaze Mining royalty   -    (200)
Cash acquired in acquisitions   -    969 
Sale of Rhino preferred and common units   2,300    - 
Proceeds from business disposal   890    - 
Additions to property, plant, and equipment   (10,612)   (1,855)
Proceeds from sales of property, plant, and equipment   404    - 
Net cash used in investing activities   (7,018)   (5,586)
CASH FLOWS FROM FINANCING ACTIVITIES:          
Borrowings on line of credit   64,750    48,500 
Repayments on line of credit   (62,500)   (54,250)
Payments on debt issuance costs   (227)   (1,148)
Proceeds from related party loans   85    - 
Repayments of loans from related party   (2,085)   - 
Proceeds from issuance of common stock   120    900 
Repayment of notes payable and long-term debt   -    (56)
Net proceeds from loan -Cedarview   2,150    - 
Proceeds from issuance of convertible notes   -    2,150 
Net cash provided by/(used in) financing activities   2,293    (3,904)
NET (DECREASE) IN CASH AND CASH EQUIVALENTS   1,817    (6,797)
CASH AND CASH EQUIVALENTS—Beginning of period   86    7,104 
CASH AND CASH EQUIVALENTS—End of period  $1,903   $307 

 

See notes to unaudited condensed consolidated financial statements.

 

 6 

 

 

ROYAL ENERGY RESOURCES, INC. AND SUBSIDIARIES

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

June 30, 2017

 

(Unaudited)

 

1BASIS 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,” “we,” or “our” ) 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, 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 June 30, 2017, condensed consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2017 and 2016 and the condensed consolidated statements of cash flows for the six months ended June 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 six months ended June 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.

 

 7 

 

 

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. See discussion below.

 

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.

 

 8 

 

 

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.

 

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”).

 

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.

 

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.

 

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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 June 30, 2017 to determine whether this debt liability should be classified as a long-term or current liability. On May 13, 2016 Rhino entered into a fifth amendment (the “Fifth Amendment”) of its amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less as of December 31, 2016. As of December 31, 2016, 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 June 30, 2017 and December 31, 2016 of $12.3 million and $10.0 million, respectively, 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. Since the credit facility has an expiration date of December 31, 2017, Rhino will have to secure alternative financing to replace its credit facility by the expiration date of December 31, 2017 in order to continue its normal business operations and meet its obligations as they come due. The financial statements do not include any adjustments relating to the recoverability and classification of 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.

 

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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 six months ended June 30, 2017 of approximately $40,000 and $36,000, respectively. The Partnership recorded its proportionate share of the operating (loss) for Sturgeon for the three and six months ended June 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 June 30, 2017, the Partnership owned 568,794 shares of Mammoth Inc.

 

As of June 30, 2017 and December 31, 2016, the Partnership recorded a fair market value adjustment of $2.0 million and $1.6 million, respectively, for its available-for-sale investment in Mammoth Inc. based on the market value of the shares at June 30, 2017 and December 31, 2016, respectively, which was recorded in Other Comprehensive Income. As of June 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 currently evaluating the requirements of this new accounting guidance.

 

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

 

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

 

In 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.

 

3ACQUISITIONS

 

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 June 30, 2017, the Company’s investment in Rhino consists of $11,250,213 in cash and $4,000,000 in notes payable. 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.

 

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   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 six months ended June 30, 2017 and 2016 are as follows.

 

   Three months ended June 30,   Six months ended June 30, 
   2017   2016   2017   2016 
   (in thousands)   (in thousands) 
Revenues  $56,535   $41,613   $110,085   $80,943 
                     
Comprehensive income/(loss)   844    (121,953)   282    (127,972)
                     
Net loss per unit, basic and fully diluted  $(0.08)  $(13.42)  $(0.30)  $(26.57)

 

The previous 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 previous 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 previous 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 previous quarter. The Company has no current income tax expense.

 

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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.

 

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 20th 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 six months ended June 30, 2016.

 

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

 

   Three Months Ended June 30,   Six Months Ended June 30, 
   2017   2016   2017   2016 
   (in thousands) 
Major line items constituting (loss)/income from discontinued operations for the Elk Horn disposal:                    
Other revenues  $-   $1,127   $-   $2,226 
Total revenues   -    1,127         2,226 
                     
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   -    499    -    454 
Depreciation, depletion and amortization   -    121    -    326 
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)   -    82    -    97 
Interest expense and other   -    5    -    10 
Total costs and expenses   -    707    -    887 
Income from discontinued operations before income taxes for the Elk Horn disposal   -    420    -    1,339 
Income taxes   -    -    -    - 
Net income from discontinued operations  $-   $420   $-   $1,339 

 

5PREPAID EXPENSES AND OTHER CURRENT ASSETS

 

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

 

   June 30, 2017   December 31, 2016 
   (in thousands) 
Other prepaid expenses  $1,254   $761 
Debt issuance costs—net   488    981 
Escrow deposit   350    - 
Prepaid insurance   2,011    1,432 
Prepaid leases   96    77 
Supply inventory   565    614 
Deposits   -    164 
Note receivable-current portion   -    900 
Total Prepaid expenses and other  $4,764   $4,929 

 

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Debt issuance costs were included in Prepaid expenses and other current assets as of June 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 June 30, 2017.

 

6PROPERTY, PLANT AND EQUIPMENT

 

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

 

   Useful Lives  June 30, 2017   December 31, 2016 
      (in thousands) 
Coal properties, including mining and other equipment  1 - 20 Years  $244,079   $69,684 
Total      244,079    69,684 
Less accumulated depreciation, depletion and amortization      (34,076)   (4,572)
Net     $210,003   $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 six months ended June 30, 2017 and 2016 were as follows:

 

   Three Months Ended June 30,   Six Months Ended June 30, 
   2017   2016   2017   2016 
   (in thousands)   (in thousands) 
Depreciation expense-mining and other equipment and related facilities  $6,791   $1,313   $29,435   $1,361 
Depletion expense for coal properties and oil and natural gas properties   162    -    718    - 
Amortization of mine development costs   8    -    30    - 
Amortization expense for intangible assets   17    25    34    42 
Amortization expense for asset retirement costs   -    (19)   (100)   (26)
Total depreciation, depletion and amortization  $6,978   $1,319   $30,117   $1,377 

 

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.

 

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7OTHER NON-CURRENT ASSETS

 

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

 

   June 30, 2017   December 31, 2016 
   (in thousands) 
Deposits and other  $219   $218 
Non-current receivable   27,157    27,157 
Deferred expenses   200    216 
Total  $27,576   $27,591 

 

Non-current receivable. The non-current receivable balance of $27.2 million as of June 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 Call Option was valued at $21.8 million based upon the closing price of the Partnership’s publicly traded common units on the date the Option Agreement was executed.

 

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. Because facts and circumstances, including the likelihood of consummation of the contemplated transaction, have not changed substantially since the agreement was executed, the Company has concluded that there has been no substantial change in the value of the Call Option.

 

8ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

 

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

 

   June 30, 2017   December 31, 2016 
   (in thousands) 
Payroll, bonus and vacation expense  $2,191   $1,721 
Non income taxes   3,608    2,669 
Royalty expenses   2,235    1,617 
Accrued interest   605    601 
Health claims   713    630 
Workers’ compensation & pneumoconiosis   2,450    2,450 
Preferred unit distribution   2,473    - 
Other   1,488    1,717 
Total  $15,763   $11,405 

 

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9NOTES PAYABLE – RELATED PARTY

 

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

 

   June 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 $28,463 at June 30, 2017 and $22,372 at December 31, 2016. For the three and six months ended June 30, 2017, the Company expensed $3,046 and $6,091, respectively, in interest from the related party loans.

 

10DEBT

 

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

 

   June 30, 2017   December 31, 2016 
   (in thousands) 
Senior secured credit facility with PNC Bank, N.A.  $12,290   $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   14,790    12,040 
Less current portion   (12,290)   (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.

 

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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 $46.3 million as of June 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 to be 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. As of June 30, 2017 and December 31, 2016, the Partnership was in compliance with respect to all covenants contained in its credit agreement.

 

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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 June 30, 2017, the Partnership had borrowed $12.3 million at a variable interest rate of PRIME plus 3.50% (7.75% at June 30, 2017). In addition, the Partnership had outstanding letters of credit of $26.1 million at a fixed interest rate of 5.00% at June 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 $7.9 million of the borrowing availability at June 30, 2017.

 

11ASSET RETIREMENT OBLIGATIONS

 

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

 

   Six months ended   Year ended 
   June 30, 2017   December 31, 2016 
   (in thousands) 
Balance at beginning of period (including current portion)  $27,420   $- 
Acquired   -    28,200 
Accretion expense   860    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   21,019    27,420 
Less current portion of asset retirement obligation   (917)   (917)
Long-term portion of asset retirement obligation  $20,102   $26,503 

 

12STOCKHOLDERS’ 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.

 

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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.

 

13RELATED PARTY TRANSACTIONS

 

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

 

GS Energy, LLC is owned by Ian and Gary Ganzer (See Note 16) and is a creditor of Blue Grove. Ian Ganzer was the chief operating officer of the Company from June 2015 to September 2016. (See Note 22 for further discussion of these related party payables).

 

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

 

   June 30, 2017   December 31, 2016 
   (thousands) 
Due to E-Starts Money Co          
Expense advances  $11   $11 
Accrued interest   29    22 
    40    33 
Due to GS Energy, LLC   18    18 
Due to Ian Ganzer   10    10 
Due to Gary Ganzer   10    10 
   $78   $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. Our President and Secretary, Ronald Phillips, owns a minority interest in Wellston, and is the manager of Wellston. On September 13, 2016, Wellston sold its assets to an unrelated third party, and the Company received rights to 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.

 

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14EMPLOYEE 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 six months ended June 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 June 30,   Six months ended June 30, 
   2017   2016   2017   2016 
   (in thousands) 
401(k) plan expense  $350   $402   $720   $706 

 

15EQUITY-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 June 30, 2017. There were 123,691 shares issued from the Employee, Consultant and Advisor Stock Compensation Plan. As of June 30, 2017, there are 1,000,000 shares available under the Stock Option Plan and 876,309 shares available under the Employee, Consultant and Advisor Stock Compensation Plan. The shares issued under the Employee, Consultant and Advisor Stock Compensation Plan were expensed at their market value on the date of issuance.

 

In October 2010, the General Partner 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.

 

As discussed in Note 1, on March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of the General Partner as well as 945,525 issued and outstanding subordinated units from Wexford Capital. Royal obtained control of, and a majority limited partner interest, in the Partnership with the completion of this transaction, which constituted a change in control of the Partnership. The language in the Partnership’s phantom unit and restricted unit grant agreements states that all outstanding, unvested units would become immediately vested upon a change in control. For the three months ended March 31, 2016, the Partnership recognized approximately $10,000 of expense from the vesting of these units as a result of the change in control.

 

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16COMMITMENTS AND CONTINGENCIES

 

Coal Sales Contracts and Contingencies—As of June 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 Q3-Q4   1,884    15 
2018   1,001    5 
2019   300    1 

 

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 six months ended June 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 six months ended June 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 June 30,   Six months ended June 30, 
   2017   2016   2017   2016 
   (in thousands) 
Lease expense  $978   $1,049   $2,491   $2,078 
Royalty expense  $3,950   $2,606   $7,327   $4,948 

 

Joint Ventures—The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012. The Partnership did not make any capital contributions to the Timber Wolf joint venture during the six months ended June 30, 2017 or 2016.

 

The Partnership made an initial capital contribution of $5.0 million during the third quarter ended September 30, 2014 to Sturgeon based upon its proportionate ownership interest. The Partnership did not make any capital contributions to the Sturgeon joint venture during the six months ended June 30, 2017 or 2016. See Note 2 for discussion on the contribution of Sturgeon to Mammoth, Inc.

 

Blue Grove Coal, LLC (“Blue Grove”). On June 10, 2015, the Company acquired Blue Grove in exchange for 350,000 shares of its common stock. Blue Grove was owned 50% by Ian Ganzer, our chief operating officer at that time, and 50% by Gary Ganzer, Ian Ganzer’s father (the “Members”). Simultaneous with the Company’s acquisition of Blue Grove, Blue Grove entered into an operator agreement with GS Energy, LLC, under which Blue Grove has an exclusive right to mine the coal properties of GS Energy for a two year period. During the term of the Operator Agreement, Blue Grove is entitled to all revenues from the sale of coal mined from GS Energy’s properties, and is responsible for all costs associated with the mining of the properties or the properties themselves, including operating costs, lease, rental or royalty payments, insurance and bonding costs, property taxes, licensing costs, etc. Simultaneous with the acquisition of Blue Grove, Blue Grove also entered into a Management Agreement with Black Oak Resources, LLC (“Black Oak”), a company owned by the Members. Under the Management Agreement, Blue Grove subcontracted all of its responsibilities under the Management Agreement with GS Energy to Black Oak. In consideration, Black Oak was entitled to 75% of all net profits generated by the mining of the coal properties of GS Energy. Subsequently, the agreement with Black Oak was amended to provide that Black Oak was entitled to 100% of the first $400,000 and 50% of the next $1,000,000, for a maximum of $900,000 of net profits generated by the mining of the coal properties of GS Energy. Please see Note 22 for additional discussion of the Blue Grove transaction.

 

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

 

On December 23, 2015, the Company and the Members entered into an Amendment to Securities Exchange Agreement (“Amendment”) originally entered into on June 8, 2015. Pursuant to the Amendment, the consideration for the acquisition of Blue Grove was reduced from 350,000 shares of the Company’s common stock to 10,000 shares (See Note 22 for further discussion).

 

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17MAJOR CUSTOMERS

 

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

 

   June 30   December 31   Six months   Six months 
   2017   2016   ended   ended 
   Receivable   Receivable   June 30   June 30 
   Balance   Balance   2017 Sales   2016 Sales 
   (in thousands) 
LG&E and KU  $2,210   $1,496   $21,162   $- 
PacifiCorp Energy   1,560    1,509    7,777    10,511 
Big Rivers Electric Corporation   947    -    13,234    10,119 
PPL Corporation   -    -    -    20,624 

 

18FAIR 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:

 

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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 June 30, 2017. The book value of the Company’s secured promissory note is considered to be representative of its fair value as of June 30, 2017 since only a brief time period has elapsed since the note was entered on May 31, 2017.

 

As of June 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 June 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.

 

19SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

 

The unaudited condensed consolidated statement of cash flows for the six months ended June 30, 2017 and 2016 excludes approximately $1.1 million and $1.2 million, respectively, of property additions, which are recorded in accounts payable.

 

20SEGMENT 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 June 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.

 

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

 

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   Central   Northern   Rhino   Illinois       Total 
   Appalachia   Appalachia   Western   Basin   Other   Consolidated 
   (in thousands) 
Total revenues  $25,675   $4,489   $8,763   $17,604   $4   $56,535 
DD&A   2,424    520    1,493    2,424    117    6,978 
Interest expense   -    -    -    -    1,015    1,015 
Net income (loss) from continuing operations  $(720)  $(126)  $(246)  $(494)  $(0)  $(1,586)

 

Reportable segment results of operations for the six months ended June 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  $5,629   $11,581   $8,324   $16,000   $79   $41,613 
DD&A   289    195    337    448    50    1,319 
Interest expense   691    101    102    256    612    1,762 
Net income (loss) from continuing operations  $-   $-   $-   $-   $157   $157 

 

Reportable segment results of operations for the six months ended June 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  $48,988   $10,615   $16,061   $34,412   $9   $110,085 
DD&A   10,446    2,440    6,169    10,532    530    30,117 
Interest expense   -    -    -    -    2,234    2,234 
Net income (loss) from continuing operations  $47,006   $10,185   $15,411   $33,019   $9   $105,630 

 

Reportable segment results of operations for the six months ended June 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  $5,559   $13,518   $9,972   $18,628   $95   $47,772 
DD&A   162    219    396    527    73    1,377 
Interest expense   790    117    117    293    783    2,100 
Net income (loss) from continuing operations  $-   $-   $-   $-   $(512)  $(512)

 

21PARENT 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.

 

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PART I.—FINANCIAL INFORMATION

 

Item 1. Financial Statements (Unaudited)

 

ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED STATEMENTS OF FINANCIAL POSITION

(in thousands)

 

   June 30, 2017   December 31, 2016 
ASSETS          
CURRENT ASSETS:          
Cash and cash equivalents  $1,866   $39 
Prepaid expenses and other   424    54 
Total current assets   2,290    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   204,622    61,136 
Intangible assets, less accumulated amortization of  $101 and $67, respectively   -    34 
TOTAL  $218,344   $72,695 
LIABILITIES AND EQUITY          
CURRENT LIABILITIES:          
Accounts payable   34    29 
Accrued expenses and other   734    769 
Note payable-related parties   504    2,504 
Note payable-Rhino   4,040    4,040 
Related party advance and accrued interest payable   78    71 
Total current liabilities   5,390    7,413 
NON-CURRENT LIABILITIES:          
Deferred tax liability   44,031    - 
Long-term debt   2,500    - 
Total non-current liabilities   46,531    - 
Total liabilities   51,921    7,413 
           
STOCKHOLDERS' EQUITY          
Preferred stock: $0.00001 par value; authorized 5,000,000 shares; 51,000 issued and outstanding at June 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; 17,184,095 shares issued and outstanding at June 30, 2017 and authorized 500,000,000; 17,212,278 shares issued and outstanding at December 31, 2016.   1    1 
Additional paid-in capital   47,715    47,295 
Stock subscription receivable   -    (213)
Accumulated other comprehensive income   1,978    874 
Accumulated earnings (accumulated deficit)   88,098    (20,579)
Total stockholders' equity owned by common shareholders   137,792    27,378 
Total non-controlling interest   28,631    37,904 
Total stockholders' equity   166,423    65,282 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY  $218,344   $72,695 

 

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ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands, except per unit data)

 

   Three Months   Six Months 
   Ended June 30,   Ended June 30, 
   2017   2016   2017   2016 
REVENUES:                    
Revenues  $-   $-   $-   $- 
Total revenues   -    -    -    - 
COSTS AND EXPENSES:                    
Amortization   17    17    34    34 
Selling, general and administrative (exclusive of Amortization shown separately above)   545    625    887    1,051 
(Gain) on sale/disposal of assets—net   -    -    -    - 
Total costs and expenses   562    642    921    1,085 
(LOSS)/INCOME FROM OPERATIONS   (562)   (642)   (921)   (1,085)
INTEREST AND OTHER (EXPENSE)/INCOME:                    
Interest income                    
Other   -    -    -    1 
Related party   -    2    -    3 
Interest expense                    
Other   (29)   (39)   (58)   (39)
Related Party   (3)   (3)   (6)   (6)
Gain on bargain purchase   -    -    171,151    - 
Equity in net (loss)/income from Rhino   (992)   1,259    (20,505)   1,953 
Total interest and other (expense)/income   (1,024)   1,219    150,582    1,912 
NET (LOSS)/INCOME FROM OPERATIONS BEFORE INCOME TAXES   (1,586)   577    149,661    827 
INCOME TAXES   -    -    44,031    - 
NET (LOSS)/INCOME FROM OPERATIONS   (1,586)   577    105,630    827 
NET (LOSS/ INCOME BEFORE NON-CONTROLLING INTEREST   (1,586)   577    105,630    827 
Less net (loss)/income attributable to non-controlling interest   (452)   84    (9,273)   121 
NET (LOSS)/INCOME ATTRIBUTABLE TO COMPANY'S STOCKHOLDERS  $(1,134)  $493   $114,903   $706 
                     
Net (loss)/income per share, basic and diluted  $(0.07)  $0.03   $6.68   $0.05 
                     
Weighted average shares outstanding, basic and diluted   17,207,883    16,699,036    17,203,109    15,624,438 

 

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ROYAL ENERGY RESOURCES, INC.

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

 

   Six Months Ended June 30, 
   2017   2016 
CASH FLOWS FROM OPERATING ACTIVITIES:          
Net income  $105,630   $827 
Adjustments to reconcile net income to net cash used in operating activities:          
Depreciation, depletion and amortization   34    34 
Bargain purchase gain   (171,151)   - 
Equity in net loss of Rhino   20,505    (1,953)
Deferred income taxes   44,031    - 
Value of common shares issued for services   250    283 
Accrued interest income-related party   -    (3)
Accrued interest expense-related party   6    6 
Equity in net loss/(income) of consolidated affiliates   (7)   15 
Changes in assets and liabilities:          
Prepaid expenses and other assets   (13)   36 
Accounts payable   2    (24)
Accrued expenses and other liabilities   (30)   282 
Net cash used in operating activities   (743)   (497)
CASH FLOWS FROM INVESTING ACTIVITIES:          
Investment in Rhino Resource Partners, LP   -    (4,500)
Investment in Blaze Mining royalty   -    (200)
Sale of Rhino preferred and common units   2,300    - 
Cash acquired in acquisitions   -    335 
Net cash provided by/(used in) investing activities   2,300    (4,365)
CASH FLOWS FROM FINANCING ACTIVITIES:          
Proceeds from related party loans   85    - 
Repayments on related party loans   (2,085)   (5,000)
Proceeds from issuance of common stock   120    900 
Proceeds from issuance of convertible notes   -    2,150 
Net proceeds from note payable   2,150    - 
Net cash provided by/(used in) financing activities   270    (1,950)
NET (DECREASE) IN CASH AND CASH EQUIVALENTS   1,827    (6,812)
CASH AND CASH EQUIVALENTS—Beginning of period   39    7,104 
CASH AND CASH EQUIVALENTS—End of period  $1,866   $292 

 

22 SUBSEQUENT EVENTS

 

Blue Grove Transaction

 

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.

 

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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., 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, the 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 six months ended June 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.

 

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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

 

Rhino is 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 six months ended June 30, 2017, we generated revenues of approximately $56.5 million and $110.1 million, respectively, and we generated net loss of $1.6 million for the three months ended June 30, 2017 and net income of $105.6 million for the six months ended June 30, 2017. For the three months ended June 30, 2017, we produced and sold approximately 1.0 million tons of coal, of which approximately 80% were sold pursuant to supply contracts. For the six months ended June 30, 2017, we produced and sold approximately 2.0 million tons of coal, of which approximately 81% were sold pursuant to supply contracts.

 

Current Liquidity and Outlook

 

As of June 30, 2017, our available liquidity was $9.8 million, including cash on hand of $1.9 million and $7.9 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 credit 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.

 

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As of June 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 are unable to demonstrate that we have sufficient liquidity to operate our business over the next twelve months from the date of filing our Annual Report on Form 10-K and thus substantial doubt is raised about our ability to continue as a going concern.

 

Since our credit facility has an expiration date of December 2017, we determined that our credit facility debt liability at June 30, 2017 of $12.3 million should be classified as a current liability on our unaudited condensed consolidated statements of financial position and the $10.0 million outstanding balance at December 31, 2016 as well. 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 considering alternative financing options that could result in a new long-term credit facility. However, we may be unable to complete such a transaction on terms acceptable to us or at all. If we are unable to extend the expiration date of our credit facility, we will have to secure alternative financing to replace our credit facility by the expiration date of December 2017 in order to continue our business operations. If we are unable to extend the expiration date of our credit facility or secure a replacement facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including amounts that may become due under our credit facility.

 

Furthermore, although met coal prices and demand have improved in recent months, if weak demand and low prices for steam coal persist and if met coal prices and demand weaken, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement.

 

Although we believe our lenders’ loans are well secured under the terms of our amended and restated credit agreement, there is no assurance that the lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern. For more information about our liquidity and our credit facility, please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources.”

 

Recent Developments

 

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.

 

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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.

 

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.

 

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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 the 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.

 

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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 June 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.

 

 35 

 

 

We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of June 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
2017Q3-Q4   1,884   15
2018   1,001   5
2019   300   1

 

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 six months ended June 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 six months ended June 30, 2017, the Company’s only operating activities consisted of Rhino.

 

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

 

   Three Months   Six Months 
   Ended June 30,   Ended June 30, 
   2017   2016   2017   2016 
REVENUES:                    
Coal sales  $54,710   $39,106   $106,491   $45,684 
Freight and handling revenues   187    581    318    682 
Other revenues   1,638    1,926    3,276    1,406 
Total revenues  $56,535   $41,613   $110,085   $47,772 

 

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

 

   Three Months   Six Months 
   Ended June 30,   Ended June 30, 
COSTS AND EXPENSES:   2017    2016    2017    2016 
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $46,592   $33,361   $91,522   $37,400 
Freight and handling costs   228    516    997    603 
Depreciation, depletion and amortization   6,978    1,319    30,117    1,377 
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)   3,277    4,505    6,671    6,779 
(Gain)/loss on sale/disposal of assets—net   71    -    70    - 
Total costs and expenses  $57,146   $39,701   $129,377   $46,159 

 

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

 

   Three Months   Six Months 
   Ended June 30,   Ended June 30, 
   2017   2016   2017   2016 
   (in thousands) 
INTEREST AND OTHER INCOME/(EXPENSE):                    
Interest expense - related party  $(3)  $(3)  $(6)  $(6)
Interest expense - other   (1,012)   (1,759)   (2,228)   (2,094)
Interest income - related party        2         3 
Interest income - other        31         37 
Bargain purchase gain             171,151      
Equity in net loss/(income) of unconsolidated affiliates   40    (26)   36    (65)
Total interest and other Income/(Expense)  $(975)  $(1,755)  $168,953   $(2,125)

 

Results of Operations of Rhino

 

The following information shows the results of operation of Rhino for each period presented. The results have not been adjusted to give effect to the changes in depreciation, depletion and amortization which resulted when Royal revalued Rhino’s property, plant and equipment.

 

In this section “Results of Operations of Rhino”, the terms “Rhino,” “we” and “our” refer exclusively to Rhino unless specifically indicated otherwise.

 

As of June 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 June 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 June 30, 2017. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of June 30, 2017. 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.

 

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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 six months ended June 30, 2017 and 2016:

 

   Three months ended June 30,   Six months ended June 30, 
   2017   2016   2017   2016 
   (in millions) 
Statement of Operations Data:                    
Total revenues  $56.5   $41.6   $110.1   $80.9 
Costs and expenses:                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)   46.7    33.4    91.6    62.9 
Freight and handling costs   0.2    0.5    0.9    1.0 
Depreciation, depletion and amortization   5.6    5.8    11.3    11.9 
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)   2.7    3.9    5.8    7.9 
Loss/(gain) on sale/disposal of assets-net   0.1    -    0.1    (0.3)
Income/(loss) from operations   1.2    (2.0)   0.4    (2.5)
Interest and other (expense)/income:                    
Interest expense   (0.9)   (1.7)   (2.1)   (3.3)
Interest income   -    0.1    -    0.1 
Equity in net (loss)/income of unconsolidated affiliates   -    (0.1)   -    (0.1)
Total interest and other (expense)   (0.9)   (1.7)   (2.1)   (3.3)
Net income/(loss) from continuing operations   0.3    (3.7)   (1.7)   (5.8)
Net (loss) from discontinued operations   -    (118.3)   -    (117.4)
Net income/(loss)*  $0.3   $(121.9)  $(1.7)  $(123.2)
                     
Other Financial Data                    
Adjusted EBITDA from continuing operations  $6.9   $3.9   $11.7   $9.3 
Adjusted EBITDA from discontinued operations   -    0.6    -    1.8 
Total Adjusted EBITDA  $6.9   $4.5   $11.7   $11.1 

 

* Totals may not foot due to rounding

 

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

 

Summary. For the three months ended June 30, 2017, our total revenues increased to $56.5 million from $41.6 million for the three months ended June 30, 2016, which is a 35.9% increase. We sold approximately 1.0 million tons of coal for the three months ended June 30, 2017, which is a 31.2% increase compared to the tons of coal sold for the three months ended June 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 in 2017.

 

Net income from continuing operations was $0.3 million for the three months ended June 30, 2017 compared to net loss of $3.7 million for the three months ended June 30, 2016. Our net income from continuing operations improved during the three months ended June 30, 2017 compared to 2016 primarily due to increased coal revenues from improved demand for met and steam coal in our Central Appalachia segment discussed earlier.

 

Adjusted EBITDA from continuing operations increased to $6.9 million for the three months ended June 30, 2017 from $4.5 million for the three months ended June 30, 2016. Adjusted EBITDA from continuing operations increased period to period due to an increase in net income during the three months ended June 30, 2017 compared to a net loss generated for the three months ended June 30, 2016.

 

Including the net loss from discontinued operations of $118.3 million, our total net loss and Adjusted EBITDA for the three months ended June 30, 2016 were $121.9 million and $4.5 million, respectively. We did not incur a gain or loss from discontinued operations for the three months ended June 30, 2017.

 

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

 

   Three months   Three months   Increase/     
   ended   ended   (Decrease)     
Segment  June 30, 2017   June 30, 2016   Tons   % * 
   (in thousands, except %) 
Central Appalachia   385.6    88.2    297.4    337.2%
Northern Appalachia   75.8    161.2    (85.4)   (53.0%)
Rhino Western   228.7    215.1    13.6    6.3%
Illinois Basin   357.0    333.5    23.5    7.1%
Total *   1,047.1    798.0    249.1    31.2%

 

* 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 1.0 million tons of coal for the three months ended June 30, 2017, which was a 31.2% increase compared to the three months ended June 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 337.2% to approximately 0.4 million tons for the three months ended June 30, 2017 compared to the three months ended June 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 53.0% for the three months ended June 30, 2017 compared to the three months ended June 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 6.3% for the three months ended June 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 7.1% for the three months ended June 30, 2017 compared to the three months ended June 30, 2016 as we increased production and sales period over period from our Pennyrile mine in western Kentucky to meet our contracted sales commitments.

 

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

 

   Three months   Three months         
   ended   ended   Increase/(Decrease) 
Segment  June 30, 2017   June 30, 2016   $   %* 
   (in millions, except per ton data and %) 
Central Appalachia                    
Coal revenues  $25.6   $5.6   $20.0    360.7%
Freight and handling revenues   -    -    -    n/a 
Other revenues   -    -    -    n/a 
Total revenues  $25.6   $5.6   $20.0    356.1%
Coal revenues per ton*  $66.42   $63.03   $3.39    5.4%
Northern Appalachia                    
Coal revenues  $2.7   $9.2   $(6.5)   (70.3%)
Freight and handling revenues   0.2    0.6    (0.4)   (67.8%)
Other revenues   1.6    1.8    (0.2)   (11.9%)
Total revenues  $4.5   $11.6   $(7.1)   (61.2%)
Coal revenues per ton*  $36.10   $57.21   $(21.11)   (36.9%)
Rhino Western                    
Coal revenues  $8.8   $8.3   $0.5    5.3%
Freight and handling revenues   -    -    -    n/a 
Other revenues   -    -    -    n/a 
Total revenues  $8.8   $8.3   $0.5    5.3%
Coal revenues per ton*  $38.31   $38.70   $(0.39)   (1.0%)
Illinois Basin                    
Coal revenues  $17.6   $16.0   $1.6    10.0%
Freight and handling revenues   -    -    -    n/a 
Other revenues   -    -    -    n/a 
Total revenues  $17.6   $16.0   $1.6    10.0%
Coal revenues per ton*  $49.30   $47.98   $1.32    2.8%
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   -    0.1    (0.1)   (94.8%)
Total revenues  $-   $0.1   $(0.1)   (94.8%)
Coal revenues per ton*    n/a      n/a      n/a     n/a 
Total                    
Coal revenues  $54.7   $39.1   $15.6    39.9%
Freight and handling revenues   0.2    0.6    (0.4)   (67.8%)
Other revenues   1.6    1.9    (0.3)   (14.9%)
Total revenues  $56.5   $41.6   $14.9    35.9%
Coal revenues per ton*  $52.25   $49.01   $3.24    6.6%

 

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Our coal revenues for the three months ended June 30, 2017 increased by approximately $15.6 million, or 39.9%, to approximately $54.7 million from approximately $39.1 million for the three months ended June 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 current period. Coal revenues per ton was $52.25 for the three months ended June 30, 2017, an increase of $3.24, or 6.6%, from $49.01 per ton for the three months ended June 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 $20.0 million, or 360.7%, to approximately $25.6 million for the three months ended June 30, 2017 from approximately $5.6 million for the three months ended June 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 $3.39, or 5.4%, to $66.42 per ton for the three months ended June 30, 2017 as compared to $63.03 for the three months ended June 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 $2.7 million for the three months ended June 30, 2017, a decrease of approximately $6.5 million, or 70.3%, from approximately $9.2 million for the three months ended June 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 June 30, 2017. Coal revenues per ton decreased by $21.11 or 36.9% per ton for the three months ended June 30, 2017 as compared to $57.21 for the three months ended June 30, 2016, which was primarily due to the larger mix of lower priced tons being sold from our Sands Hill complex compared to higher priced tons sold from our Hopedale complex.

 

For our Rhino Western segment, coal revenues increased by approximately $0.5 million, or 5.3%, to approximately $8.8 million for the three months ended June 30, 2017 from approximately $8.3 million for the three months ended June 30, 2016 primarily due to an increase in tons sold from the Castle Valley mine. Coal revenues per ton for our Rhino Western segment decreased by $0.39 or 1.0% per ton for the three months ended June 30, 2017 as compared to $38.70 per ton for the three months ended June 30, 2016.

 

For our Illinois Basin segment, coal revenues of approximately $17.6 million for the three months ended June 30, 2017 increased by approximately $1.6 million, or 10.3%, compared to $16.0 million for the three months ended June 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 $49.30 for the three months ended June 30, 2017, an increase of $1.32, or 2.8%, from $47.98 for the three months ended June 30, 2016. The increase in coal revenues per ton was due to higher contracted prices for tons sold.

 

Other revenues for our Other category was relatively flat at approximately $0.1 million for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016.

 

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

 

(In thousands, except per ton data and %)  Three months ended
June 30, 2017
   Three months ended
June 30, 2016
   Increase (Decrease) %* 
Met coal tons sold   182.5    30.7    494.6%
Steam coal tons sold   203.1    57.5    253.2%
Total tons sold   385.6    88.2    337.2%
                
Met coal revenue  $15,229   $2,569    492.7%
Steam coal revenue  $10,380   $2,990    247.2%
Total coal revenue  $25,609   $5,559    360.7%
                
Met coal revenues per ton  $83.45   $83.72    (0.3%)
Steam coal revenues per ton  $51.11   $51.99    (1.7%)
Total coal revenues per ton  $66.42   $63.03    5.4%
                
Met coal tons produced   171.7    41.8    311.1%
Steam coal tons produced   227.6    70.2    224.2%
Total tons produced   399.3    112.0    256.6%

 

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

 

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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 June 30, 2017 and 2016:

 

   Three months   Three months         
   ended   ended   Increase/(Decrease) 
Segment  June 30, 2017   June 30, 2016   $   %* 
   (in millions, except per ton data and %) 
Central Appalachia                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $20.5   $6.1   $14.4    235.6%
Freight and handling costs   -    -    -    n/a 
Depreciation, depletion and amortization   2.0    1.6    0.4    22.9%
Selling, general and administrative   -    -    -    n/a 
Cost of operations per ton*  $53.05   $69.12   $(16.07)   (23.2%)
                     
Northern Appalachia                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $5.4   $7.8   $(2.4)   (31.4%)
Freight and handling costs   0.2    0.5    (0.3)   (55.8%)
Depreciation, depletion and amortization   0.4    0.8    (0.4)   (48.5%)
Selling, general and administrative   -    -    -    n/a 
Cost of operations per ton*  $71.04   $48.66   $22.38    46.0%
                     
Rhino Western                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $6.7   $6.4   $0.3    4.9%
Freight and handling costs   -    -    -    n/a 
Depreciation, depletion and amortization   1.2    1.4    (0.2)   (14.5%)
Selling, general and administrative   -    -    -    n/a 
Cost of operations per ton*  $29.13   $29.54   $(0.41)   (1.4%)
                     
Illinois Basin                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $14.6   $13.8   $0.8    5.7%
Freight and handling costs   -    -    -    n/a 
Depreciation, depletion and amortization   1.9    1.9    -    4.4%
Selling, general and administrative   0.1    0.1    -    n/a 
Cost of operations per ton*  $40.85   $41.38   $(0.53)   (1.3%)
                     
Other                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $(0.5)  $(0.7)  $0.2    (43.4%)
Freight and handling costs   -    -    -    n/a 
Depreciation, depletion and amortization   0.1    0.1    -    (34.6%)
Selling, general and administrative   2.6    3.8    (1.2)   (31.4%)
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)  $46.7   $33.4   $13.3    39.9%
Freight and handling costs   0.2    0.5    (0.3)   (55.8%)
Depreciation, depletion and amortization   5.6    5.8    (0.2)   (3.5%)
Selling, general and administrative   2.7    3.9    (1.2)   (30.0%)
Cost of operations per ton*  $44.57   $41.81   $2.76    6.6%

 

* 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.

 

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Cost of Operations. Total cost of operations was $46.7 million for the three months ended June 30, 2017 as compared to $33.4 million for the three months ended June 30, 2016. Our cost of operations per ton was $44.57 for the three months ended June 30, 2017, an increase of $2.76, or 6.6%, from the three months ended June 30, 2016. Total cost of operations in Central Appalachia increased by $14.4 million, primarily due to an increase in production in Central Appalachia during the three months ended June 30, 2107 due to increased demand for met and steam coal from this region. 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 in Northern Appalachia for the three months ended June 30, 2017 compared to the prior period.

 

Our cost of operations for the Central Appalachia segment increased by $14.4 million, or 235.6%, to $20.5 million for the three months ended June 30, 2017 from $6.1 million for the three months ended June 30, 2016. Total cost of operations increased period over period as we increased production in this region during the three months ended June 30, 2017 due to increased demand for met and steam coal from this region. Our cost of operations per ton of $53.05 for the three months ended June 30, 2017 was a reduction of 23.2% compared to $69.12 per ton for the three months ended June 30, 2016. We increased production and 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 as fixed costs were allocated to more tons of coal sold.

 

In our Northern Appalachia segment, our cost of operations decreased by $2.4 million, or 31.4%, to $5.4 million for the three months ended June 30, 2017 from $7.8 million for the three months ended June 30, 2016. Our cost of operations per ton was $71.04 for the three months ended June 30, 2017, an increase of $22.38, or 46.0%, compared to $48.66 for the three months ended June 30, 2016. The decrease in total cost of operations in Northern Appalachia was due to a decrease in production 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 $0.3 million, or 4.9%, to $6.7 million for the three months ended June 30, 2017 from $6.4 million for the three months ended June 30, 2016. Total cost of operations increased for the three months ended June 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 $29.13 for the three months ended June 30, 2017, a decrease of $0.41, or 1.4%, compared to $29.54 for the three months ended June 30, 2016. Cost of operations per ton decreased for the three months ended June 30, 2017 compared to the same period in 2016 due to an increase in production from our Castle Valley mine in the current period.

 

Cost of operations in our Illinois Basin segment was $14.6 million while cost of operations per ton was $40.85 for the three months ended June 30, 2017, both of which related to our Pennyrile mining complex in western Kentucky. For the three months ended June 30, 2016, cost of operations in our Illinois Basin segment was $13.8 million and cost of operations per ton was $41.38. The increase in cost of operations was primarily the result of an increase in production. The decrease in the cost of operations per ton was primarily the result of fixed operating costs being allocated to more tons of coal sold during the current period.

 

Freight and Handling. Total freight and handling cost decreased to $0.2 million for the three months ended June 30, 2017 as compared to $0.5 million for the three months ended June 30, 2016. The decrease in freight and handling costs were primarily the result of decreased production and sales at our Northern Appalachia operations due to weak market demand in the region.

 

Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization (“DD&A”) expense for the three months ended June 30, 2017 was $5.6 million as compared to $5.8 million for the three months ended June 30, 2016.

 

For the three months ended June 30, 2017, our depreciation cost decreased to $4.4 million compared to $5.0 million for the three months ended June 30, 2016. This decrease primarily resulted from lower depreciation costs in our Northern Appalachia segment in the current quarter compared to the prior year as we have fully depreciated assets in this region.

 

For the three months ended June 30, 2017 and 2016 our depletion cost remained flat at $0.4 million.

 

For the three months ended June 30, 2017, our amortization cost was $0.8 million compared to $0.4 million for the three months ended June 30, 2016. The increase period over period was due to an increase in amortization of mine development cost, which was the result of increased mining operations in Central Appalachia compared to the prior period.

 

Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the three months ended June 30, 2017 decreased to $2.7 million as compared to $3.9 million for the three months ended June 30, 2016. This decrease was primarily attributable to lower corporate overhead.

 

Interest Expense. Interest expense for the three months ended June 30, 2017 decreased to $1.0 million as compared to $1.7 million for the three months ended June 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 June 30, 2017.

 

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

 

 

 

   Three months ended   Three months ended   Increase 
Segment  June 30, 2017   June 30, 2016   (Decrease) 
   (in millions) 
Central Appalachia  $3.3   $(2.3)  $5.6 
Northern Appalachia   (1.6)   2.3    (3.9)
Rhino Western   0.7    0.5    0.2 
Illinois Basin   1.0    0.2    0.8 
Other   (3.1)   (4.4)   1.3 
Total  $0.3   $(3.7)  $4.0 

 

For the three months ended June 30, 2017, total net income from continuing operations was approximately $0.3 million compared to net loss from continuing operations of approximately $3.7 million for the three months ended June 30, 2016. For the three months ended June 30, 2017, our net income from continuing operations was positively impacted by increased production and sales from our Central Appalachia operations compared to the prior period.

 

For our Central Appalachia segment, net income from continuing operations was approximately $3.3 million for the three months ended June 30, 2017, an increase of $5.6 million in net income from continuing operations as compared to the three months ended June 30, 2016. The increase in net income from continuing operations was primarily due to increased production and sales from the Central Appalachia mining operations in the second quarter of 2017 due to increased demand for met and steam coal from this region. Net loss from continuing operations in our Northern Appalachia segment was $1.6 million for the three months ended June 30, 2017 compared to net income from continuing operations of $2.3 million for the three months ended June 30, 2016. The decrease in net income from continuing operations was primarily the result of lower sales from the Northern Appalachia region due to weak market demand.

 

Net income from continuing operations in our Rhino Western segment was $0.7 million for the three months ended June 30, 2017, compared to $0.5 million for the three months ended June 30, 2016. This increase in net income from continuing operations was primarily the result of more tons sold at our Castle Valley operation. For our Illinois Basin segment, we generated net income from continuing operations of $1.0 million for the three months ended June 30, 2017, which was an improvement of $0.8 million compared to the three months ended June 30, 2016. This increase in net income was primarily the result of increased coal sales at our Pennyrile mining complex as we fulfilled our customer contracts. For the Other category, we had a net loss from continuing operations of $3.1 million for the three months ended June 30, 2017 as compared to net loss from continuing operations of $4.4 million for the three months ended June 30, 2016. This decrease in net loss period over period was primarily attributable to lower corporate overhead charges.

 

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

 

   Three months ended   Three months ended   Increase 
Segment  June 30, 2017   June 30, 2016   (Decrease) 
   (in millions) 
Central Appalachia  $5.3   $(0.5)  $5.8 
Northern Appalachia   (1.2)   3.2    (4.4)
Rhino Western   1.9    1.9    - 
Illinois Basin   2.9    2.2    0.7 
Other   (2.0)   (2.9)   0.9 
Total  $6.9   $3.9   $3.0 

 

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Adjusted EBITDA from continuing operations for the three months ended June 30, 2017, was $6.9 million, an increase of $3.0 million from the three months ended June 30, 2016. Adjusted EBITDA from continuing operations increased period over period primarily due to the increase in net income at our Central Appalachia segment resulting from an increase in met and steam coal tons sold due to increased demand for met and steam coal from this region during the current period. Adjusted EBITDA for the three months ended June 30, 2016 was $4.5 million once the results from discontinued operations were included. We did not incur a gain or loss from discontinued operations for the three months ended June 30, 2017. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA from continuing operations to net income on a segment basis.

 

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

 

Summary. For the six months ended June 30, 2017, our total revenues increased to $110.1 million from $80.9 million for the six months ended June 30, 2016, which is a 36.0% increase. We sold approximately 2.0 million tons of coal for the six months ended June 30, 2017, which is a 27.2% increase compared to the tons of coal sold for the six months ended June 30, 2016. The increase in revenue and tons sold was primarily the result of increased production and sales in Central Appalachia due to recent increases in coal prices and demand for met and steam coal produced in this region.

 

We generated net loss from continuing operations of approximately $1.7 million for the six months ended June 30, 2017 compared to a net loss from continuing operations of approximately $5.8 million for the six months ended June 30, 2016. Our net loss from continuing operations improved during the six months ended June 30, 2017 compared to 2016 due to higher coal revenues from the increased demand for met and steam coal in our Central Appalachia segment.

 

Adjusted EBITDA from continuing operations increased to $11.7 million for the six months ended June 30, 2017 from $9.3 million for the six months ended June 30, 2016. Adjusted EBITDA from continuing operations increased primarily due to the decrease in net loss during the six months ended June 30, 2017 compared to the six months ended June 30, 2016 resulting from the increase in production and sales at our Central Appalachia operation. Adjusted EBITDA for the six months ended June 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 loss from discontinued operations of approximately $117.4 million, our total net loss and Adjusted EBITDA for the six months ended June 30, 2016 were $123.2 million and $11.1 million, respectively. We did not incur a gain or loss from discontinued operations for the six months ended June 30, 2017.

 

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

 

   Six months   Six months   Increase/     
   ended   ended   (Decrease)     
Segment  June 30, 2017   June 30, 2016   Tons   % * 
   (in thousands, except %) 
Central Appalachia   709.1    188.3    520.8    276.7%
Northern Appalachia   194.0    283.7    (89.7)   (31.6%)
Rhino Western   419.7    467.0    (47.3)   (10.1%)
Illinois Basin   697.8    649.2    48.6    7.5%
Total *   2,020.6    1,588.2    432.4    27.2%

 

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

 

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We sold approximately 2.0 million tons of coal for the six months ended June 30, 2017, which was a 27.2% increase compared to the six months ended June 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 276.7% to approximately 0.7 million tons for the six months ended June 30, 2017 compared to the six months ended June 30, 2016, primarily due to an increase in met and steam coal tons sold in the six months ended June 30, 2017 compared to 2016 due to increased market demand for met and steam coal from this region. For our Northern Appalachia segment, tons of coal sold decreased by approximately 31.6% for the six months ended June 30, 2017 compared to the six months ended June 30, 2016 as we experienced a decrease in tons sold from our Northern Appalachia segment due to weak demand for coal in this region. Coal sales from our Rhino Western segment decreased by approximately 10.1% for the six months ended June 30, 2017 compared to the same period in 2016 due to losing approximately two weeks of production during the first quarter of 2017 resulting from maintenance issues at our Castle Valley operation. The maintenance issues have been corrected, production has resumed to previous levels and we believe Castle Valley will ship additional tons in the remainder of 2017 to make up for the lower tons sold in the first three months of the year. For our Illinois Basin segment, tons of coal sold increased by approximately 7.5% for the six months ended June 30, 2017 compared to the six months ended June 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 six months ended June 30, 2017 and 2016:

 

   Six months   Six months         
   ended   ended   Increase/(Decrease) 
Segment  June 30, 2017   June 30, 2016   $   %* 
   (in millions, except per ton data and %) 
Central Appalachia                    
Coal revenues  $48.9   $11.2   $37.7    338.1%
Freight and handling revenues   -    -    -    n/a 
Other revenues   0.1    -    0.1    10.7%
Total revenues  $49.0   $11.2   $37.8    335.8%
Coal revenues per ton*  $68.96   $59.29   $9.67    16.3%
Northern Appalachia                    
Coal revenues  $7.1   $15.9   $(8.8)   (55.1%)
Freight and handling revenues   0.3    1.2    (0.9)   (73.8%)
Other revenues   3.2    3.6    (0.4)   (12.9%)
Total revenues  $10.6   $20.7   $(10.1)   (48.8%)
Coal revenues per ton*  $36.71   $55.95   $(19.24)   (34.4%)
Rhino Western                    
Coal revenues  $16.1   $17.9   $(1.8)   (10.4%)
Freight and handling revenues   -    -    -    n/a 
Other revenues   -    -    -    n/a 
Total revenues  $16.1   $17.9   $(1.8)   (10.4%)
Coal revenues per ton*  $38.26   $38.37   $(0.11)   (0.3%)
Illinois Basin                    
Coal revenues  $34.4   $30.9   $3.5    11.6%
Freight and handling revenues   -    -    -    n/a 
Other revenues   -    -    -    n/a 
Total revenues  $34.4   $30.9   $3.5    11.6%
Coal revenues per ton*  $49.31   $47.49   $1.82    3.8%
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)   (94.5%)
Total revenues  $-   $0.2   $(0.2)   (94.5%)
Coal revenues per ton*    n/a      n/a      n/a     n/a 
Total                    
Coal revenues  $106.5   $75.9   $30.6    40.5%
Freight and handling revenues   0.3    1.2    (0.9)   (73.8%)
Other revenues   3.3    3.8    (0.5)   (17.0%)
Total revenues  $110.1   $80.9   $29.2    36.0%
Coal revenues per ton*  $52.70   $47.72   $4.98    10.4%

 

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

 

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Our coal revenues for the six months ended June 30, 2017 increased by approximately $30.6 million, or 40.5%, to approximately $106.5 million from approximately $75.9 million for the six months ended June 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 current period. Coal revenues per ton was $52.70 for the six months ended June 30, 2017, an increase of $4.98, or 10.4%, from $47.72 per ton for the six months ended June 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 increased by approximately $37.7 million, or 338.1%, to approximately $48.9 million for the six months ended June 30, 2017 from approximately $11.2 million for the six months ended June 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 $9.67, or 16.3%, to $68.96 per ton for the six months ended June 30, 2017 as compared to $59.29 for the six months ended June 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 $7.1 million for the six months ended June 30, 2017, a decrease of approximately $8.8 million, or 55.1%, from approximately $15.9 million for the six months ended June 30, 2016. This decrease was primarily due to a decrease in tons sold from our Northern Appalachia segment due to weak market demand in the region. Coal revenues per ton for our Northern Appalachia segment decreased by $19.24, or 34.4%, to $36.71 per ton for the six months ended June 30, 2017 as compared to $55.95 per ton for the six months ended June 30, 2016. This decrease was primarily due to the larger mix of lower priced tons being sold from our Sands Hill complex compared to higher priced tons sold from our Hopedale complex.

 

For our Rhino Western segment, coal revenues decreased by approximately $1.8 million, or 10.4%, to approximately $16.1 million for the six months ended June 30, 2017 from approximately $17.9 million for the six months ended June 30, 2016, primarily due to a decrease in tons sold resulting from the maintenance issues at our Castle Valley operation in the first quarter of 2017. Coal revenues per ton for our Rhino Western segment remained relatively flat at $38.26 for the six months ended June 30, 2017, compared to $38.37 for the six months ended June 30, 2016.

 

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For our Illinois Basin segment, coal revenues of approximately $34.4 million for the six months ended June 30, 2017 increased by approximately $3.5 million, or 11.6%, compared to $30.9 million for the six months ended June 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 $49.31 for the six months ended June 30, 2017, an increase of $1.82, or 3.8%, from $47.49 for the six months ended June 30, 2016. The increase in coal revenues per ton was due to higher contracted prices for tons sold.

 

Other revenues for our Other category remained relatively flat for the six months ended June 30, 2017 as compared to the same period in 2016.

 

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

 

(In thousands, except per ton data and %)  Six months
ended
June 30, 2017
   Six months
ended
June 30, 2016
   Increase (Decrease) %* 
Met coal tons sold   378.4    47.0    705.4%
Steam coal tons sold   330.7    141.3    134.1%
Total tons sold   709.1    188.3    276.7%
             
Met coal revenue  $31,846   $3,899    716.8%
Steam coal revenue  $17,055   $7,263    134.8%
Total coal revenue  $48,901   $11,162    338.1%
             
Met coal revenues per ton  $84.16   $82.99    1.4%
Steam coal revenues per ton  $51.57   $51.41    0.3%
Total coal revenues per ton  $68.96   $59.29    16.3%
             
Met coal tons produced   352.7    57.7    511.5%
Steam coal tons produced   378.0    138.7    172.6%
Total tons produced   730.7    196.4    272.1%

 

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

 

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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 six months ended June 30, 2017 and 2016:

 

   Six months   Six months         
   ended   ended   Increase/(Decrease) 
Segment  June 30, 2017   June 30, 2016   $   %* 
   (in millions, except per ton data and %) 
Central Appalachia                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $38.8   $12.9   $25.9    200.2%
Freight and handling costs   0.6    -    0.6    n/a 
Depreciation, depletion and amortization   3.9    3.3    0.6    18.5%
Selling, general and administrative   0.1    -    0.1    158.7%
Cost of operations per ton*  $54.77   $68.72   $(13.95)   (20.3%)
                     
Northern Appalachia                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $11.6   $10.7   $0.9    8.4%
Freight and handling costs   0.4    1.1    (0.7)   (62.2%)
Depreciation, depletion and amortization   0.9    1.8    (0.9)   (48.1%)
Selling, general and administrative   0.1    0.1    -    (11.0%)
Cost of operations per ton*  $59.76   $37.70   $22.06    58.5%
                     
Rhino Western                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $13.4   $14.5   $(1.1)   (7.8%)
Freight and handling costs   -    -    -    n/a 
Depreciation, depletion and amortization   2.3    2.8    (0.5)   (17.7%)
Selling, general and administrative   -    -    -    n/a 
Cost of operations per ton*  $31.92   $31.13   $0.79    2.6%
                     
Illinois Basin                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $28.7   $26.5   $2.2    8.6%
Freight and handling costs   -    -    -    n/a 
Depreciation, depletion and amortization   4.0    3.7    0.3    7.4%
Selling, general and administrative   0.1    0.1    -    (2.1%)
Cost of operations per ton*  $41.19   $40.79   $0.40    1.0%
                     
Other                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $(0.9)  $(1.8)  $0.9    (46.1%)
Freight and handling costs   -    -    -    n/a 
Depreciation, depletion and amortization   0.2    0.3    (0.1)   (29.5%)
Selling, general and administrative   5.5    7.7    (2.2)   (28.9%)
Cost of operations per ton**   n/a    n/a    n/a    n/a 
                     
Total                    
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  $91.6   $62.8   $28.8    45.7%
Freight and handling costs   1.0    1.1    (0.1)   (6.5%)
Depreciation, depletion and amortization   11.3    11.9    (0.6)   (4.6%)
Selling, general and administrative   5.8    7.9    (2.1)   (27.2%)
Cost of operations per ton*  $45.34   $39.58   $5.76    14.6%

 

* 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.

 

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Cost of Operations. Total cost of operations was $91.6 million for the six months ended June 30, 2017 as compared to $62.8 million for the six months ended June 30, 2016. Our cost of operations per ton was $45.34 for the six months ended June 30, 2017, an increase of $5.76, or 14.6%, from the six months ended June 30, 2016. Total cost of operations increased primarily due to higher costs in Central Appalachia due to an increase in production in as we increased production in the region during the six months ended June 30, 2017.

 

Our cost of operations for the Central Appalachia segment increased by $25.9 million, or 200.2%, to $38.8 million for the six months ended June 30, 2017 from $12.9 million for the six months ended June 30, 2016. Total cost of operations increased year-to-year as we increased production in our Central Appalachia segment in response to increased demand for met and steam coal from this region. Our cost of operations per ton of $54.77 for the six months ended June 30, 2017 was a decrease of 20.3% compared to $68.72 per ton for the six months ended June 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 increased by $0.9 million, or 8.4%, to $11.6 million for the six months ended June 30, 2017 from $10.7 million for the six months ended June 30, 2016. Our cost of operations per ton was $59.76 for the six months ended June 30, 2017, an increase of $22.06, or 58.5%, compared to $37.70 for the six months ended June 30, 2016. The cost of operations for the six months ended June 30, 2016 was decreased by a prior service cost benefit of $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation during the 2016 period. 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 six months ended June 30, 2017.

 

Our cost of operations for the Rhino Western segment decreased by $1.1 million, or 7.8%, to $13.4 million for the six months ended June 30, 2017 from $14.5 million for the six months ended June 30, 2016. Our cost of operations per ton was $31.92 for the six months ended June 30, 2017, an increase of $0.79, or 2.6%, compared to $31.13 for the six months ended June 30, 2016. Total cost of operations per ton increased for the six months ended June 30, 2017 compared to the same period in 2016 due to fixed operating costs being allocated to lower sales tons at our Castle Valley operation resulting from the maintenance issues previously discussed.

 

Cost of operations in our Illinois Basin segment was $28.7 million while cost of operations per ton was $41.19 for the six months ended June 30, 2017, both of which related to our Pennyrile mining complex in western Kentucky. For the six months ended June 30, 2016, cost of operations in our Illinois Basin segment was $26.5 million and cost of operations per ton was $40.79. The increase in cost of operations was primarily the result of increased production year-to-year at the Pennyrile complex, while cost of operations per ton remained relatively flat.

 

Freight and Handling. Total freight and handling cost was relatively flat at $1.0 million for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016.

 

Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization (“DD&A”) expense for the six months ended June 30, 2017 was $11.3 million as compared to $11.9 million for the six months ended June 30, 2016.

 

For the six months ended June 30, 2017, our depreciation cost decreased to $8.8 million compared to $10.3 million for the six months ended June 30, 2016. This decrease primarily resulted from lower depreciation costs in our Central Appalachia segment in the current period compared to the prior year as we disposed of excess equipment in this region.

 

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For the six months ended June 30, 2017, our depletion cost was flat at $0.8 million compared to the six months ended June 30, 2016.

 

For the six months ended June 30, 2017, our amortization cost increased to $1.7 million compared to $0.8 million for the six months ended June 30, 2016. The increase is a result of increased production in our Central Appalachia segment during the six months ended June 30, 2017 compared to the same period in 2016.

 

Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the six months ended June 30, 2017 decreased to $5.8 million as compared to $7.9 million for the six months ended June 30, 2016. This decrease was primarily attributable to lower corporate overhead expenses for the six months ended June 30, 2017 compared to the prior period.

 

Interest Expense. Interest expense for the six months ended June 30, 2017 decreased to $2.1 million as compared to $3.3 million for the six months ended June 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 six months ended June 30, 2017 and 2016:

 

   Six months Ended   Six months Ended   Increase 
Segment  June 30, 2017   June 30, 2016   (Decrease) 
   (in millions) 
Central Appalachia  $5.6   $(5.3)  $10.9 
Northern Appalachia   (2.4)   7.0    (9.4)
Rhino Western   0.2    0.5    (0.3)
Illinois Basin   1.6    0.5    1.1 
Other   (6.7)   (8.5)   1.8 
Total  $(1.7)  $(5.8)  $4.1 

 

For the six months ended June 30, 2017, total net loss from continuing operations was approximately $1.7 million compared to net loss from continuing operations of approximately $5.8 million for the six months ended June 30, 2016. For the six months ended June 30, 2017, our net loss from continuing operations was positively impacted by increased production and sales from our Central Appalachia operations compared to the prior period. For the six months ended June 30, 2016, our total net loss from continuing operations was impacted by a prior service cost benefit of $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation during the 2016 period.

 

For our Central Appalachia segment, net income from continuing operations was approximately $5.6 million for the six months ended June 30, 2017, a $10.9 million increase in net income from continuing operations as compared to the six months ended June 30, 2016, which was primarily related to the increase in sales at our Central Appalachia operation.

 

Net loss from continuing operations in our Northern Appalachia segment was $2.4 million for the six months ended June 30, 2017 compared to net income of $7.0 million for the same period in 2016. The decrease in net income from continuing operations for the six months ended June 30, 2017 was primarily due to decreased coal sales in our Northern Appalachia segment. The net income from continuing operations for the six months ended June 30, 2016 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.

 

Net income from continuing operations in our Rhino Western segment was $0.2 million for the six months ended June 30, 2017, compared to net income from continuing operations of $0.5 million for the six months ended June 30, 2016. This decrease in net income from continuing operations was primarily the result of lower production and sales at our Castle Valley operation during the six months ended June 30, 2017 compared to 2016 due to the maintenance issues discussed earlier.

 

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For our Illinois Basin segment, we generated net income from continuing operations of $1.6 million for the six months ended June 30, 2017, which was an improvement of $1.1 million compared to the six months ended June 30, 2016. This increase in net income from continuing operations was primarily the result of increased coal sales at our Pennyrile mining complex.

 

For the Other category, we had a net loss from continuing operations of $6.7 million for the six months ended June 30, 2017 as compared to a net loss from continuing operations of $8.5 million for the six months ended June 30, 2016. This decrease in results period over period was primarily attributable to lower corporate overhead charges.

 

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

 

   Six months Ended   Six months Ended   Increase 
Segment  June 30, 2017   June 30, 2016   (Decrease) 
   (in millions)         
Central Appalachia  $9.6   $(1.6)  $11.2 
Northern Appalachia   (1.4)   8.9    (10.3)
Rhino Western   2.5    3.4    (0.9)
Illinois Basin   5.6    4.4    1.2 
Other   (4.6)   (5.8)   1.2 
Total  $11.7   $9.3   $2.4 

 

Adjusted EBITDA from continuing operations increased to $11.7 million for the six months ended June 30, 2017 from $9.3 million for the six months ended June 30, 2016. Adjusted EBITDA from continuing operations increased period over period primarily due to the decrease in net loss during the six months ended June 30, 2017 compared to the six months ended June 30, 2016. The decrease in net loss from continuing operations was primarily due to the increase in coal sales revenue at our Central Appalachia operation. Adjusted EBITDA for the six months ended June 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. Adjusted EBITDA for the six months ended June 30, 2016 was $11.1 million, respectively, once the results from discontinued operations were included. We did not incur a gain or loss from discontinued operations for the six months ended June 30, 2017. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA from continuing operations to net income on a segment basis.

 

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 June 30, 2017  Appalachia   Appalachia   Western   Basin   Other   Total 
   (in millions) 
Net income/(loss) from continuing operations  $3.3   $(1.6)  $0.7   $1.0   $(3.1)  $0.3 
Plus:                              
DD&A   2.0    0.4    1.2    1.9    0.1    5.6 
Interest expense   -    -    -    -    1.0    1.0 
EBITDA from continuing operations†  $5.3   $(1.2)  $1.9   $2.9   $(2.0)  $6.9 
Adjusted EBITDA from continuing operations†   5.3    (1.2)   1.9    2.9    (2.0)   6.9 
Adjusted EBITDA †  $5.3   $(1.2)  $1.9   $2.9   $(2.0)  $6.9 

 

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   Central   Northern   Rhino   Illinois         
Three months ended June 30, 2016  Appalachia   Appalachia   Western   Basin   Other*   Total* 
   (in millions) 
Net income/(loss) from continuing operations  $(2.3)  $2.3   $0.5   $0.2   $(4.4)  $(3.7)
Plus:                              
DD&A   1.6    0.8    1.4    1.9    0.1    5.8 
Interest expense   0.2    0.1    -    0.1    1.3    1.7 
EBITDA from continuing operations†  $(0.5)  $3.2   $1.9   $2.2   $(2.9)  $3.9 
Adjusted EBITDA from continuing operations†   (0.5)   3.2    1.9    2.2    (2.9)   3.9 
EBITDA from discontinued operations   0.6    -    -    -    -    0.6 
Adjusted EBITDA  $0.1   $3.2   $1.9   $2.2   $(2.9)  $4.5 

 

   Central   Northern   Rhino   Illinois         
Six months ended June 30, 2017  Appalachia *   Appalachia   Western   Basin   Other*   Total* 
   (in millions) 
Net income/(loss) from continuing operations*  $5.6   $(2.4)  $0.2   $1.6   $(6.8)  $(1.7)
Plus:                              
DD&A   3.9    0.9    2.3    4.0    0.2    11.3 
Interest expense   -    -    -    -    2.1    2.1 
EBITDA from continuing operations†  $9.6   $(1.4)  $2.5   $5.6   $(4.6)  $11.7 
Adjusted EBITDA from continuing operations†   9.6    (1.4)   2.5    5.6    (4.6)   11.7 
Adjusted EBITDA †  $9.6   $(1.4)  $2.5   $5.6   $(4.6)  $11.7 

 

   Central   Northern   Rhino   Illinois         
Six months ended June 30, 2016  Appalachia   Appalachia*   Western   Basin*   Other*   Total* 
   (in millions) 
Net income/(loss) from continuing operations  $(5.3)  $7.0   $0.5   $0.5   $(8.5)  $(5.8)
Plus:                              
DD&A   3.3    1.8    2.8    3.7    0.3    11.9 
Interest expense   0.4    0.2    0.1    0.1    2.5    3.3 
EBITDA from continuing operations†  $(1.6)  $8.9   $3.4   $4.4   $(5.8)  $9.3 
Adjusted EBITDA from continuing operations†   (1.6)   8.9    3.4    4.4    (5.8)   9.3 
EBITDA from discontinued operations   1.8    -    -    -    -    1.8 
Adjusted EBITDA †  $0.2   $8.9   $3.4   $4.4   $(5.8)  $11.1 

 

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

 

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   Three months ended June 30,   Six months ended June 30, 
   2017   2016   2017   2016 
   (in millions) 
Net cash provided by operating activities  $6.0   $5.3   $7.3   $4.1 
Plus:                    
Increase in net operating assets   1.4    -    4.9    1.0 
Gain on sale of assets   -    0.1    -    0.3 
Amortization of deferred revenue   -    0.6    -    0.7 
Amortization of actuarial gain   -    -    -    4.8 
Interest expense   1.0    1.7    2.1    3.3 
Equity in net income of unconsolidated affiliate   0.1    -    0.1    - 
Less:                    
Decrease in net operating assets   -    1.4    -    - 
Amortization of advance royalties   0.3    0.3    0.6    0.6 
Amortization of debt issuance costs   0.4    0.4    0.7    1.0 
Loss on retirement of advanced royalties   -    -    0.1    0.1 
Loss on sale of assets   0.1    -    0.1    - 
Provision for doubtful accounts   -    0.1    -    0.1 
Equity-based compensation   0.3    0.5    0.3    0.5 
Accretion on asset retirement obligations   0.5    0.4    0.9    0.7 
Equity in net loss of unconsolidated affiliates   -    0.1    -    0.1 
EBITDA†  $6.9   $4.5   $11.7   $11.1 
Adjusted EBITDA†   6.9    4.5    11.7    11.1 
Less: EBITDA from discontinued operations   -    0.6    -    1.8 
Adjusted EBITDA from continuing operations †  $6.9   $3.9   $11.7   $9.3 

 

  EBITDA is calculated based on actual amounts and not the rounded amounts presented in this table.

 

Liquidity and Capital Resources

 

Liquidity

 

Our principal indicators of our liquidity are our cash on hand and availability under our amended and restated credit agreement. As of June 30, 2017, our available liquidity was $8.0 million, including cash on hand of $0.1 million and $7.9 million available under our credit facility. On May 13, 2016, we entered into a Fifth Amendment of our amended and restated agreement that initially extended the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the term of the credit facility automatically extended to December 31, 2017 when the revolving credit commitments were reduced to $55 million or less 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.”

 

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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.

 

At December 31, 2016, beyond the operations of Rhino, the Company has not established sources of revenues sufficient to fund the development of its business, or to pay projected operating expenses and commitments for the next year. Also as discussed above, the classification of Rhino’s credit facility balance as a current liability resulted in a working capital deficit. 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.

 

Since our credit facility has an expiration date of December 2017, we determined that our credit facility debt liability at June 30, 2017 of $12.3 million should be classified as a current liability on our unaudited condensed consolidated statements of financial position and the $10.0 million outstanding balance at December 31, 2016 as well. The classification of our credit facility balance as a current liability raises substantial doubt of our ability to continue as a going concern for the next twelve months. We are also considering alternative financing options that could result in a new long-term credit facility. However, we may be unable to complete such a transaction on terms acceptable to us or at all. If we are unable to extend the expiration date of our amended and restated credit facility, we will have to secure alternative financing to replace our credit facility by the expiration date of December 2017 in order to continue our business operations. If we are unable to extend the expiration date of our amended and restated credit facility or secure a replacement facility, we will lose a primary source of liquidity, and we may not be able to generate adequate cash flow from operations to fund our business, including amounts that may become due under our credit facility.

 

Furthermore, although met coal prices and demand have improved in recent months, if weak demand and low prices for steam coal persist and if met coal prices and demand weaken, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit facility. If we violate any of the covenants or restrictions in our amended and restated credit agreement, including the maximum leverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our amended and restated credit agreement.

 

Although we believe our lenders’ loans are well secured under the terms of our amended and restated credit agreement, there is no assurance that the lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern.

 

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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.

 

Cash Flows (Consolidated Basis)

 

Net cash provided by operating activities was $6.5 million for the six months ended June 30, 2017 as compared to cash provided by operating activities of $2.7 million for the six months ended June 30, 2016. This increase in cash provided by operating activities for the six months ended June 30, 2017 was primarily the result of the increase in production and sales in our Central Appalachia segment for the six months ended June 30, 2017 as compared to 2016 due to increased met coal demand from this region.

 

Net cash used for investing activities was $7.0 million for the six months ended June 30, 2017 as compared to cash used for investing activities of $5.6 million for the six months ended June 30, 2016. Net cash used in investing activities for the six months ended June 30, 2017 was primarily related to capital expenditures necessary for maintaining our mining operations. Net cash used for investing activities for the six months ended June 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.

 

Net cash provided by financing activities for the six months ended June 30, 2017 was $2.3 million, which was primarily attributable to net borrowings on Rhino’s revolving credit facility and a $2.5 million loan entered into by Royal during this period. Net cash used in financing activities for the six months ended June 30, 2016 was $3.9 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.

 

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 six months ended June 30, 2017 were approximately $5.8 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the six months ended June 30, 2017 were approximately $4.8 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 $46.3 million as of June 30, 2017. The amount available for letters of credit was unchanged from these amendments.

 

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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 as outlined below. The Fifth Amendment requires Royal to contribute $2 million each quarter beginning September 30, 2016 through September 30, 2017 and $1 million on December 1, 2017, for a total of $11 million. The Fifth Amendment further reduces the revolving credit commitments as follows:

 

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

 

The Fifth Amendment 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.

 

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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 June 30, 2017, we are in compliance with respect to all covenants contained in the credit agreement.

 

At June 30, 2017, the Operating Company had borrowings outstanding (excluding letters of credit) of $12.3 million at a variable interest rate of PRIME plus 3.50% (7.75% at June 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 June 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 $7.9 million at June 30, 2017. During the three months ended June 30, 2017, we had average borrowings outstanding of approximately $12.9 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 June 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.

 

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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 June 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 June 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
2017Q3-Q4    1,884   15
2018    1,001   5
2019    300   1

 

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

 

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

 

A hypothetical increase of $0.10 per gallon for diesel fuel would have increased net loss by $0.1 million for the three months ended June 30, 2017 and would have decreased net income by $0.2 million for the six months ended June 30, 2017. A hypothetical increase of 10% in steel prices would have increased net loss by $0.3 million for the three months ended June 30, 2017 and would have decreased net income by $0.5 million for the six months ended June 30, 2017. A hypothetical increase of 10% in explosives prices would have increased net loss by $0.1 million for the three months ended June 30, 2017 and would have reduced net income by $0.2 million for the six months ended June 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 June 30, 2017 and would have reduced net income by $50,000 for the six months ended June 30, 2017.

 

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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 June 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 six months ended June 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: We do not have effective internal controls over its financial close, consolidation and reporting process. During 2016, beginning with the acquisition of controlling interest in Rhino Resource Partners, LP our financial reporting complexities increased significantly without a corresponding increase in our resources dedicated to maintenance of a control structure and the preparation of financial information to be included in its public filings.

 

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

 

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

 

None.

 

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 June 30, 2017 is included in Exhibit 95.1 to this report.

 

ITEM 5: Other Information.

 

None.

 

ITEM 6: Exhibits

 

  Exhibit No.   Description
       
  10.1*   Ninth Amendment to Amended and Restated Credit Agreement, dated June 9, 2017 by and among Rhino Energy LLC, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets and Union Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners, Union Bank, N.A., as Syndication Agent, Raymond James Bank, FSB, Wells Fargo Bank, National Association and the Huntington National Bank, as Co-Documentation Agents and the guarantors and lenders party thereto
       
  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”

 

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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: August 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

 

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