UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

[X]QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31,September 30, 2019

 

OR

 

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

 

For the transition period from ________ to ________

 

Commission file number 001-34892

 

RHINO RESOURCE PARTNERS LP
(Exact name of registrant as specified in its charter)

 

Delaware 27-2377517

(State or other jurisdiction of

incorporation or organization)

 

(IRS Employer

Identification No.)

 

424 Lewis Hargett Circle, Suite 250

Lexington, KY

 40503
(Address of principal executive offices) (Zip Code)

 

(859) 389-6500

(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. [X] Yes [  ] No

 

Indicate by check mark whether the registrant has submitted electronically 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 such files). [X] Yes [  ] No

 

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

Title of each classTrading Symbol(s)Name of each Exchange on which registered
n/an/an/a

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

 

Large accelerated filer [  ]Accelerated filer [  ]
  
Non-accelerated filer [  ] (Do not check if a smaller reporting company)Smaller reporting company [X]
  
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 Exchange Act). [  ] Yes [X] No

 

As of May 3,November 1, 2019, 13,098,353 common units, 1,143,171 subordinated units and 1,500,000 Series A preferred units were outstanding.

 

 

  

 

TABLE OF CONTENTS

 

Cautionary Note Regarding Forward-Looking Statements3
Part I.—Financial Information (Unaudited)4
ITEM 1. FINANCIAL STATEMENTS4
Condensed Consolidated Statements of Financial Position as of March 31,September 30, 2019 and December 31, 20184
Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended March 31,September 30, 2019 and 20185
Consolidated Statements of Partners’ Capital for the Nine Months Ended September 30, 2019 and 20186
Condensed Consolidated Statements of Cash Flows for the ThreeNine Months Ended March 31,September 30, 2019 and 20187
Notes to Condensed Consolidated Financial Statements8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations2429
Item 4. Controls and Procedures4055
PART II—Other Information4055
Item 1. Legal Proceedings4055
Item 1A. Risk Factors4156
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds4156
Item 3. Defaults upon Senior Securities4157
Item 4. Mine Safety Disclosure4157
Item 5. Other Information4157
Item 6. Exhibits4257
SIGNATURES4359

 

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, 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; 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; our ability to comply with the qualifying income requirement necessary to maintain our status as a partnership for U.S. federal income tax purposes; declines in demand for electricity and coal; current and future environmental laws and regulations, which could materially increase operating costs or limit our ability to produce and sell coal; extensive government regulation of mine operations, especially with respect to mine safety and health, which imposes significant actual and potential costs; difficulties in obtaining and/or renewing permits necessary for operations; a variety of operating risks, such as unfavorable geologic conditions, adverse weather conditions and natural disasters, mining and processing equipment unavailability, failures and unexpected maintenance problems and accidents, including fire and explosions from methane; poor mining conditions resulting from the effects of prior mining; the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives; fluctuations in transportation costs or disruptions in transportation services, which could increase competition or impair our ability to supply coal; a shortage of skilled labor, increased labor costs or work stoppages; our ability to secure or acquire new or replacement high-quality coal reserves that are economically recoverable; material inaccuracies in our estimates of coal reserves and non-reserve coal deposits; existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds, which could affect coal consumers and reduce demand for coal; federal and state laws restricting the emissions of greenhouse gases; our ability to acquire or failure to maintain, obtain or renew surety bonds used to secure obligations to reclaim mined property; our dependence on a few customers and our ability to find and retain customers under favorable supply contracts; changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices; changes in governmental regulation of the electric utility industry; defects in title in properties that we own or losses of any of our leasehold interests; our ability to retain and attract senior management and other key personnel; material inaccuracy of assumptions underlying reclamation and mine closure obligations; and weakness in global economic conditions. Other factors that could cause our actual results to differ from our projected results are described elsewhere in (1) this Form 10-Q, (2) our Annual Report on Form 10-K for the year ended December 31, 2018, (3) our reports and registration statements filed from time to time with the Securities and Exchange Commission and (4) other announcements we make from time to time. In addition, we may be subject to unforeseen risks that may have a materially adverse effect on us. Accordingly, no assurances can be given that the actual events and results will not be materially different from the anticipated results described in the forward-looking statements.

 

The forward-looking statements speak only as of the date made, and, other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I.—FINANCIAL INFORMATION

 

Item 1. Financial Statements (Unaudited)

 

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands)

 

 September 30, December 31, 
 March 31, 2019  December 31, 2018  2019  2018 
ASSETS                
CURRENT ASSETS:                
Cash and cash equivalents $4,201  $6,172  $8,004  $6,170 
Accounts receivable, net of allowance for doubtful accounts ($0.7 million as of March 31, 2019 and December 31, 2018).  16,981   15,126 
Accounts receivable, net of allowance for doubtful accounts ($-0- and $0.7 million as of September 30, 2019 and December 31, 2018, respectively.)  11,788   12,481 
Receivable-other  2,960   - 
Inventories  11,420   6,573   18,410   6,118 
Advance royalties, current portion  366   548   4   8 
Investment in available for sale securities  -   1,872 
Investment in equity securities  -   1,872 
Prepaid expenses and other  2,132   2,766   3,272   2,660 
Current assets held for sale  1,602   3,748 
Total current assets  35,100   33,057   46,040   33,057 
PROPERTY, PLANT AND EQUIPMENT:                
At cost, including coal properties, mine development and construction costs  450,591   450,888   376,640   367,184 
Less accumulated depreciation, depletion and amortization  (282,437)  (277,029)  (254,754)  (247,662)
Net property, plant and equipment  168,154   173,859   121,886   119,522 
Operating lease right-of-use assets (net)  13,523   -   11,926   - 
Advance royalties, net of current portion  8,366   8,026   6,644   6,587 
Deposits - Workers’ Compensation and Surety Programs  8,266   8,266   7,943   8,266 
Other non-current assets  25,160   25,410   24,849   24,967 
Non-current assets held for sale  6,517   56,219 
TOTAL $258,569  $248,618  $225,805  $248,618 
LIABILITIES AND EQUITY                
CURRENT LIABILITIES:                
Accounts payable $20,814  $14,185  $21,821  $10,413 
Accrued expenses and other  10,840   10,107   11,833   8,650 
Accrued preferred distributions  300   3,210   900   3,210 
Current portion of lease liabilities  3,175   - 
Current portion of operating lease liabilities  3,260   - 
Current portion of long-term debt  3,057   2,174   4,445   2,174 
Current portion of asset retirement obligations  465   465   465   465 
Current liabilities held for sale  6,921   5,229 
Total current liabilities  38,651   30,141   49,645   30,141 
NON-CURRENT LIABILITIES:                
Long-term debt, net  21,208   22,458   28,447   22,458 
Asset retirement obligations, net of current portion  18,388   18,084   20,565   17,116 
Operating lease liabilities, net of current portion  9,971   -   8,300   - 
Other non-current liabilities  41,495   41,500   42,164   41,500 
Non-current liabilities held for sale  -   968 
Total non-current liabilities  91,062   82,042   99,476   82,042 
Total liabilities  129,713   112,183   149,121   112,183 
COMMITMENTS AND CONTINGENCIES (NOTE 13)        
COMMITMENTS AND CONTINGENCIES (NOTE 15)        
PARTNERS’ CAPITAL:                
Limited partners  107,958   115,505   56,004   115,505 
General partner  8,760   8,792   8,542   8,792 
Preferred partners  15,000   15,000   15,000   15,000 
Investment in Royal common stock (NOTE 11)  (4,126)  (4,126)
Investment in Royal common stock (NOTE 13)  (4,126)  (4,126)
Common unit warrants  1,264   1,264   1,264   1,264 
Total partners’ capital  128,856   136,435   76,684   136,435 
TOTAL $258,569  $248,618  $225,805  $248,618 

 

See notes to unaudited condensed consolidated financial statements.

4

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(In thousands, except per unit data)

 

 Three Months Ended March 31,  Three Months Ended
September 30,		  

Nine Months Ended 

September 30,

 
 2019 2018  2019 2018 2019 2018 
REVENUES:                        
Coal sales $57,863  $54,272  $41,821  $59,338  $138,687  $142,635 
Other revenues  874   528   445   699   1,816   1,905 
Total revenues  58,737   54,800   42,266   60,037   140,503   144,540 
COSTS AND EXPENSES:                        
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  54,646   49,653   38,389   47,061   124,662   120,923 
Freight and handling costs  1,155   904   1,373   5,849   4,305   8,225 
Depreciation, depletion and amortization  5,549   5,427   3,525   3,655   10,511   10,841 
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)  2,743   2,696   5,450   2,705   11,588   8,120 
Loss/(gain) on sale/disposal of assets, net  222   (2,937)
(Gain) on sale/disposal of assets, net  9   (788)  (6,651)  (7,222)
Total costs and expenses  64,315   55,743   48,746   58,482   144,415   140,887 
(LOSS) FROM OPERATIONS  (5,578)  (943)
INCOME/(LOSS) FROM OPERATIONS  (6,480)  1,555   (3,912)  3,653 
INTEREST AND OTHER (EXPENSE)/INCOME:                        
Interest expense and other  (1,701)  (1,885)  (1,872)  (2,831)  (5,308)  (6,629)
Interest income and other  -   7   8   -   8   7 
Total interest and other (expense)  (1,701)  (1,878)  (1,864)  (2,831)  (5,300)  (6,622)
(LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS  (7,279)  (2,821)
NET (LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS  (8,344)  (1,276)  (9,212)  (2,969)
INCOME TAXES  -   -   -   -   -   - 
NET (LOSS) FROM CONTINUING OPERATIONS  (8,344)  (1,276)  (9,212)  (2,969)
DISCONTINUED OPERATIONS (NOTE 4)                
Loss from discontinued operations  (43,340)  (3,254)  (49,639)  (7,417)
NET (LOSS)  (7,279)  (2,821)  (51,684)  (4,530)  (58,851)  (10,386)
Other comprehensive income:                        
Fair value adjustment for investment  -   4,182   -   (506)  -   3,874 
Reclass for disposition  -   (2,644)  -   -   -   (6,621)
Total other comprehensive income  -   1,538   -   (506)  -   (2,747)
COMPREHENSIVE (LOSS) $(7,279) $(1,283) $(51,684) $(5,036) $(58,851) $(13,133)
                        
General partner’s interest in net (loss) $(32) $(13)
Common unitholders’ interest in net (loss) $(6,941) $(2,856)
Subordinated unitholders’ interest in net (loss) $(606) $(252)
General partner’s interest in net (loss)/income:                
Net (loss) from continuing operations $(36) $(10) $(42) $(20)
Net (loss) from discontinued operations  (181)  (14)  (207)  (31)
General partner’s interest in net (loss)/income $(217) $(24) $(249) $(51)
Common unitholders’ interest in net (loss)/income:                
Net (loss) from continuing operations $(7,917) $(2,248) $(9,262) $(4,355)
Net (loss) from discontinued operations  (39,695)  (2,980)  (45,463)  (6,789)
Common unitholders’ interest in net (loss)/income: $(47,612) $(5,228) $(54,725) $(11,144)
Subordinated unitholders’ interest in net (loss)/income:                
Net (loss) from continuing operations $(691) $(197) $(808) $(382)
Net (loss) from discontinued operations  (3,464)  (260)  (3,969)  (597)
Subordinated unitholders’ interest in net (loss)/income: $(4,155) $(457) $(4,777) $(979)
Preferred unitholders’ interest in net income:                
Net income from continuing operations $300  $1,179  $900  $1,788 
Net income from discontinued operations  -   -   -   - 
Preferred unitholders’ interest in net income $300  $300  $300  $1,179  $900  $1,788 
Net (loss)/income per limited partner unit, basic:        
Net (loss) per limited partner unit, basic:                
Common units:                
Net (loss) per unit from continuing operations $(0.60) $(0.17) $(0.71) $(0.34)
Net (loss) per unit from discontinued operations  (3.03)  (0.23)  (3.47)  (0.52)
Net (loss) per common unit, basic $(3.63) $(0.40) $(4.18) $(0.86)
Subordinated units                
Net (loss) per unit from continuing operations $(0.60) $(0.17) $(0.71) $(0.34)
Net (loss) per unit from discontinued operations  (3.03)  (0.23)  (3.47)  (0.52)
Net (loss) per subordinated unit, basic $(3.63) $(0.40) $(4.18) $(0.86)
Preferred units                
Net income per unit from continuing operations $0.20  $0.79  $0.60  $1.19 
Net income per unit from discontinued operations  -   -   -   - 
Net income per preferred unit, basic $0.20  $0.79  $0.60  $1.19 
Net (loss) per limited partner unit, diluted:                
Common units $(0.53) $(0.22)                
Net (loss)/income per unit from continuing operations $(0.60) $(0.17) $(0.71) $(0.34)
Net (loss) per unit from discontinued operations  (3.03)  (0.23)  (3.47)  (0.52)
Net (loss) per common unit, diluted $(3.63) $(0.40) $(4.18) $(0.86)
Subordinated units $(0.53) $(0.22)                
Net (loss) per unit from continuing operations $(0.60) $(0.17) $(0.71) $(0.34)
Net (loss) per unit from discontinued operations  (3.03)  (0.23)  (3.47)  (0.52)
Net (loss) per subordinated unit, diluted $(3.63) $(0.40) $(4.18) $(0.86)
Preferred units $0.20  $0.20                 
Net (loss)/income per limited partner unit, diluted:        
Common units $(0.53) $(0.22)
Subordinated units $(0.53) $(0.22)
Preferred units $0.20  $0.20 
Net income per unit from continuing operations $0.20  $0.79  $0.60  $1.19 
Net income per unit from discontinued operations  -   -   -   - 
Net income per preferred unit, diluted $0.20  $0.79  $0.60  $1.19 
                        
Weighted average number of limited partner units outstanding, basic:                        
Common units  13,098   12,994   13,098   13,098   13,098   13,035 
Subordinated units  1,144   1,146   1,143   1,146   1,143   1,146 
Preferred units  1,500   1,500   1,500   1,500   1,500   1,500 
Weighted average number of limited partner units outstanding, diluted:                        
Common units  13,098   12,994   13,098   13,098   13,098   13,035 
Subordinated units  1,144   1,146   1,143   1,146   1,143   1,146 
Preferred units  1,500   1,500   1,500   1,500   1,500   1,500 

 

See notes to unaudited condensed consolidated financial statements.

5

RHINO RESOURCE PARTNERS LP

UNAUDITED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED MARCH 31, 2019 and 2018

(In thousands)

 

             Accumulated                  Accumulated     
 Limited Partners General Preferred Other   Total  Limited Partners General Preferred Other   Total 
 Common Subordinated Partner Partner Comprehensive   Partners’  Common Subordinated Partner Partner Comprehensive   Partners’ 
 Units Capital Units Capital Capital Capital Income/(Loss) Other Capital  Units Capital Units Capital Capital Capital Income/(Loss) Other Capital 
                                      
BALANCE - December 31, 2018  13,098  $39,324   1,144  $76,181  $8,792  $15,000  $         -  $(2,862) $136,435   13,098  $39,324   1,144  $76,181  $8,792  $15,000  $                -  $(2,862) $136,435 
Net (loss)/income      (6,941)      (606)  (32)  300           (7,279)  -   (6,941)  -   (606)  (32)  300   -   -   (7,279)
Preferred partner distribution earned  -   -   -   -   -   (300)  -   -   (300)  -   -   -   -   -   (300)  -   -   (300)
BALANCE - March 31, 2019  13,098  $32,383   1,144  $75,575  $8,760  $15,000  $-  $(2,862) $128,856   13,098   32,383   1,144   75,575   8,760   15,000   -   (2,862)  128,856 
Net (loss)/income  -   (172)  -   (15)  (1)  300   -   -   112 
Preferred partner distribution earned  -   -   -   -   -   (300)  -   -   (300)
BALANCE - June 30, 2019  13,098  $32,211   1,144  $75,560  $8,759  $15,000  $-  $(2,862) $128,668 
Net (loss)/income  -   (47,612)  -   (4,155)  (217)  300   -   -   (51,684)
Preferred partner distribution earned  -   -   -   -   -   (300)  -   -   (300)
BALANCE -September 30, 2019  13,098  $(15,401)  1,144  $71,405  $8,542  $15,000   -  $(2,862) $76,684 

 

             Accumulated                  Accumulated     
 Limited Partners General Preferred Other   Total  Limited Partners General Preferred Other   Total 
 Common Subordinated Partner Partner Comprehensive   Partners’  Common Subordinated Partner Partner Comprehensive   Partners’ 
 Units Capital Units Capital Capital Capital Income/(Loss) Other Capital  Units Capital Units Capital Capital Capital Income/(Loss) Other Capital 
BALANCE - December 31, 2017  12,994  $52,850   1,146  $77,383  $8,855  $15,000  $      4,220  $(2,862) $155,446   12,994  $52,850   1,146  $77,383  $8,855  $15,000  $4,220  $(2,862) $155,446 
Net (loss)/income  -   (2,856)      (252)  (13)  300           (2,821)  -   (2,856)  -   (252)  (13)  300   -   -   (2,821)
Preferred distribution earned  -   -   -   -   -   (300)  -   -   (300)
Preferred partner distribution earned  -   -   -   -   -   (300)               -   -   (300)
Reclass of disposition of Mammoth shares  -   -   -   -   -   -   (2,644)  -   (2,644)  -   -   -   -   -   -   (2,644)  -   (2,644)
Mark-to-market investment in Mammoth  -   -   -   -   -   -   4,182   -   4,182   -   -   -   -   -   -   4,182   -   4,182 
BALANCE - March 31, 2018  12,994  $49,994   1,146  $77,131  $8,842  $15,000  $5,758  $(2,862) $153,863   12,994   49,994   1,146   77,131   8,842   15,000   5,758   (2,862)  153,863 
Net (loss)/income  -   (3,061)  -   (269)  (14)  309   -   -   (3,035)
Preferred partner distribution earned  -   -   -   -   -   (309)  -   -   (309)
Issuance of units  104   230   -   -   -   -   -   -   230 
Reclass of disposition of Mammoth shares  -   -   -   -   -   -   (3,977)  -   (3,977)
Mark-to-market investment in Mammoth  -   -   -   -   -   -   198   -   198 
BALANCE - June 30, 2018  13,098  $47,163  $1,146  $76,862  $8,828  $15,000  $1,979  $(2,862) $146,970 
Net (loss)/income  -   (5,228)  -   (457)  (24)  1,179   -   -   (4,530)
Preferred partner distribution earned  -   -   -   -   -   (1,179)  -   -   (1,179)
Miscellaneous adjustment  -   -   -   (1)  -   -   1   -   - 
Mark-to-market investment in Mammoth  -   -   -   -   -   -   (506)  -   (506)
BALANCE - September 30, 2018  13,098  $41,935   1,146  $76,404  $8,804  $15,000  $1,474  $(2,862) $140,755 

See notes to consolidated financial statements.

 

6
 

 

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(inIn thousands)

 

 Three Months Ended March 31,  Nine Months Ended September 30, 
 2019 2018  2019 2018 
CASH FLOWS FROM OPERATING ACTIVITIES:                
Net (loss) $(7,279) $(2,821) $(58,851) $(10,386)
Adjustments to reconcile net (loss) to net cash provided by operating activities:        
Adjustments to reconcile net (loss) to net cash (used in)/provided by operating activities:        
Depreciation, depletion and amortization  5,549   5,427   16,470   16,733 
Accretion on asset retirement obligations  319   315   957   954 
Amortization of advance royalties  407   185   1,534   502 
Amortization of debt issuance costs  516   395   1,582   1,432 
Provision for doubtful accounts  -   294 
Amortization of debt discount  105   105   316   316 
Loss on retirement of advance royalties  112   108   244   108 
(Gain)/loss on sale/disposal of assets—net  655   (31)  (6,220)  (719)
(Gain) on sale of Mammoth shares  (433)  (2,906)  (433)  (6,498)
Loss on impairment of assets  38,633   - 
Equity based compensation  -   230 
Changes in assets and liabilities:                
Accounts receivable  (1,855)  3,268   5,775   (5,223)
Inventories  (4,847)  107   (11,837)  3,319 
Advance royalties  (677)  (288)  (2,380)  (904)
Prepaid expenses and other assets  537   369   (658)  (1,618)
Accounts payable  6,463   3,503   9,134   8,865 
Accrued expenses and other liabilities  977   638   2,492   391 
Asset retirement obligations  (15)  (19)  (66)  (259)
Net cash provided by operating activities  534   8,355 
Net cash (used in)/provided by operating activities  (3,308)  7,537 
CASH FLOWS FROM INVESTING ACTIVITIES:                
Additions to property, plant, and equipment  (2,001)  (9,179)  (9,263)  (20,525)
Asset acquisition  (1,385)  - 
Proceeds from sales of property, plant, and equipment  1,401   3   1,756   4,802 
Proceeds from sale of Pennyrile assets  7,263   - 
Proceeds from sale of Mammoth shares  2,304   4,823   2,304   11,887 
Net cash provided by/(used in) investing activities  1,704   (4,353)  675   (3,836)
CASH FLOWS FROM FINANCING ACTIVITIES:                
Repayments on long-term debt  (375)  (5,100)  (1,125)  (10,208)
Repayments on other debt  (522)  -   (1,224)  (540)
Repayments on finance leases  (1)  -   (3)  - 
Proceeds from financing agreement  10,000   5,000 
Proceeds from issuance of other debt  1,772   1,622 
Deposit for workers’ compensation and surety programs  -   (5,209)  323   (8,209)
Payments of debt issuance costs  (101)  (56)  (2,068)  (879)
Preferred distributions paid  (3,210)  (6,038)  (3,210)  (6,039)
Net cash (used in) by financing activities  (4,209)  (16,403)
NET (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH  (1,971)  (12,401)
Net cash provided by/(used in) financing activities  4,465   (19,253)
NET (DECREASE) IN CASH, CASH EQUIVALENTS  1,832   (15,552)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH—Beginning of period  6,172   21,120   6,172   21,120 
CASH, CASH EQUIVALENTS AND RESTRICTED CASH—End of period $4,201  $8,719  $8,004  $5,568 
        
Summary Statement of Financial Position:        
Cash and cash equivalents $4,201  $4,991 
Restricted cash  -   3,728 
 $4,201  $8,719 

 

See notes to unaudited condensed consolidated financial statements.

 

7
 

 

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31,SEPTEMBER 30, 2019 AND DECEMBER 31, 2018 AND FOR THE THREE AND NINE MONTHS ENDED

MARCH 31, SEPTEMBER 30, 2019 AND 2018

 

1. BASIS OF PRESENTATION AND ORGANIZATION

 

Basis of Presentation and Principles of Consolidation.The accompanying unaudited interim financial statements include the accounts of Rhino Resource Partners LP and its subsidiaries (the “Partnership”). Intercompany transactions and balances have been eliminated in consolidation.

 

Cash, Cash Equivalents and Restricted Cash. The Partnership considers all highly liquid investments purchased with original maturities of three months or less to be cash equivalents. The Partnership early adopted ASU No. 2016-18,Statement of Cash Flows-Restricted Cash as of December 31, 2017 and as such its unaudited condensed consolidated statement of cash flows for all historical periods reflect restricted cash combined with cash and cash equivalents. The Partnership did not have any other material impact from the early adoption of this ASU.

 

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 March 31,September 30, 2019, unaudited consolidated statement of partners’ capital for the three months ended March 31, 2019 and 2018, condensed consolidated statements of operations and comprehensive income for the three and nine months ended March 31,September 30, 2019 and 2018, consolidated statements of partners’ capital for the nine months ended September 30, 2019 and 2018 and the condensed consolidated statements of cash flows for the threenine months ended March 31,September 30, 2019 and 2018 include all adjustments that the Partnership considers necessary for a fair presentation of the financial position, partners’ capital, operating results and cash flows for the periods presented. The condensed consolidated statement of financial position as of December 31, 2018 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America (“U.S.”). The Partnership filed its Annual Report on Form 10-K for the year ended December 31, 2018 with the Securities and Exchange Commission (“SEC”), which included all information and notes necessary for such presentation. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the year or any future period. These unaudited interim financial statements should be read in conjunction with the audited financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC.

 

Organization.Rhino Resource Partners LP is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Operating Company”). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Kentucky, Ohio, West Virginia and Utah. The majority of sales are made to electric utilities, coal brokers, domestic and non-U.S. steel producers and other coal-related organizations in the United States. In addition, the Partnership continues its sales focus to U.S. export customers through brokers and direct end-user relationships.

 

Through a series of transactions completed in the first quarter of 2016, Royal Energy Resources, Inc. (“Royal”) acquired a majority ownership and control of the Partnership and 100% ownership of the Partnership’s general partner. The Partnership’s common units trade on the OTCQB Marketplace under the ticker symbol “RHNO.”

 

8

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

 

Revenue Recognition. The Partnership adopted ASU 2014-09-Revenue2014-09-Revenue from Contracts with Customers (Topic 606) on January 1, 2018, using the modified retrospective method. The adoption of Topic 606 had no impact on revenue amounts recorded on the Partnership’s financial statements (See Note 1517 for additional discussion). Most of the Partnership’s revenues are generated under coal sales contracts with electric utilities, coal brokers, domestic and non-U.S. steel producers, industrial companies or other coal-related organizations. Revenue is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable, the title or risk of loss has passed in accordance with the terms of the sales agreement and collectability is reasonably assured. Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, when the coal is loaded on the rail, barge, truck or other transportation source that delivers coal to its destination. Advance payments received are deferred and recognized in revenue as coal is shipped and title has passed.passes.

Freight and handling costs paid directly to third-party carriers and invoiced separately to coal customers are recorded as freight and handling costs and freight and handling revenues, respectively. Freight and handling costs billed to customers as part of the contractual per ton revenue of customer contracts is included in coal sales revenue.

 

Other revenues generally consist of coal royalty revenues, coal handling and processing revenues, rebates and rental income. With respect to other revenues recognized in situations unrelated to the shipment of coal, the Partnership carefully reviews the facts and circumstances of each transaction and does not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the seller’s price to the buyer is fixed or determinable and collectability is reasonably assured.

Debt Issuance Costs. Debt issuance costs reflect fees incurred to obtain financing and are amortized (included in interest expense) using the straight-line method over the life of the related debt, which approximates the effective interest method. Debt issuance costs are presented as a direct deduction from long-term debt as of March 31,September 30, 2019 and December 31, 2018. The effective interest rate for the threenine months ended March 31,September 30, 2019 was 21.93%22.12% and 18.79%24.18% for the threenine months ended March 31,September 30, 2018.

 

Recently Issued Accounting Standards.Standards.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. In July 2018, the FASB issued additional authoritative guidance providing companies with an optional prospective transition method to apply the provisions of this guidance. The Partnership adopted ASU 2016-02 in the first quarter of 2019 and elected the transition method to apply the standard prospectively and also elected the “package of practical expedients” within the standard which permits the Partnership not to reassess its prior conclusions about lease identification, lease classification and initial direct costs. Additionally, the Partnership made an election to not separate lease and non-lease components for all leases and will not use hindsight. Finally, the Partnership will continue its current policy for accounting for land easements as executory contracts. The standard had a material impact on our unaudited condensed Consolidated Statements of Financial Position, but did not have an impact on our unaudited condensed Consolidated Statements of Operations.Operations and Comprehensive Income. Please refer to Note 57 for disclosures related to the new standard.

 

In July 2017, the FASB issued ASU 2017-11, “Earnings“Earnings Per Share (Topic 260): Distinguishing Liabilities from Equity (Topic 480), I. Derivatives and Hedging (Topic 815): Accounting for Certain Financial Instruments with Down Round Features and II. Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception.”Part I of ASU 2017-11 will result in freestanding equity-linked financial instruments, such as warrants, and conversion options in convertible debt or preferred stock to no longer be accounted for as a derivative liability at fair value as a result of the existence of a down round feature. For freestanding equity-classified financial instruments, the amendments require entities that present earnings per share (EPS) in accordance with Topic 260 to recognize the effect of the down round feature when it is triggered. That effect is treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The amendments in Part II recharacterize the indefinite deferral of certain provisions of Topic 480 that now are presented as pending content in the Codification. The amendments in Part II do not require any transition guidance as the amendments do not have an accounting effect. The amendments in ASU 2017-11 will be effective on January 1, 2020, and the Part I amendments must be applied retrospectively. Early application is permitted. The Partnership early adopted ASU 2017-11, which did not have any material impact.

9

3. ACQUISTION

Blackjewel Assignment Agreement

On August 14, 2019, Jewell Valley Mining LLC (“Jewell Valley”), a wholly owned subsidiary of the Partnership, entered into a general assignment and assumption agreement and bill of sale (the “Assignment Agreement”) with Blackjewel L.L.C., Blackjewel Holdings L.L.C., Revelation Energy Holdings, LLC, Revelation Management Corp., Revelation Energy, LLC, Dominion Coal Corporation, Harold Keene Coal Co. LLC, Vansant Coal Corporation, Lone Mountain Processing LLC, Powell Mountain Energy, LLC, and Cumberland River Coal LLC (together, “Blackjewel”) to purchase certain assets from Blackjewel for cash consideration of $850,000 plus an additional royalty of $250,000 that is payable within one year from the date of the purchase, as well as the assumption of associated reclamation obligations. The transaction costs associated with the Assignment Agreement were $103,577. The assets that are subject of the Assignment Agreement consist of three underground mines in Virginia that were actively producing coal prior to Blackjewel’s filing for relief under Chapter 11 of the United States Bankruptcy Code, along with a preparation plant, rail loadout facility, related mineral and surface rights and infrastructure and certain purchase contracts to be assumed at Jewell Valley’s option.

As of September 30, 2019, the Partnership is still in the process of hiring qualified personnel to operate the assets purchased from Blackjewel since the Partnership did not retain any of the existing Blackjewel workforce. The Partnership is also still refurbishing the assets before resuming mining operations. The Partnership plans to resume mining operations at one of the mines in the fourth quarter of 2019. The operating results for Jewell Valley will be reported as part of the Partnership’s Central Appalachia business segment. The Partnership reviewed the appropriate guidance regarding ASU 2017-01,Business Combinations (Topic 805)and determined that this transaction was an asset purchase.

The Assignment Agreement was funded by borrowings from the Partnership’s delayed draw feature of the Financing Agreement (as defined below). Please refer to Note 10 for additional details of the Financing Agreement. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date:

  (in thousands) 
Property, plant and equipment $3,853 
Land  378 
Asset retirement obligation  (2,596)
Net assets acquired $1,635 
Initial cash consideration $850 
Mineral cure payments  431 
Transaction costs  104 
Cash consideration  1,385 
Royalty payable  250 
Total consideration $1,635 

4. DISCONTINUED OPERATIONS

Pennyrile Asset Purchase Agreement

On September 6, 2019, the Partnership and Alliance Coal, LLC (“Buyer”) and Alliance Resource Partners, L.P. (“Buyer Parent”) entered into an Asset Purchase Agreement (the “Pennyrile APA”) pursuant to which the Partnership sold to Buyer all of the real property, permits, equipment and inventory and certain other assets associated with its Pennyrile mine complex, as well as the buyer’s assumption of the Pennyrile reclamation obligation, in exchange for approximately $3.7 million, subject to certain adjustments.

Pursuant to the Pennyrile APA, the Partnership retains liability for certain employee claims, subsidence claims arising from pre-closing mining operations, MSHA liabilities and certain other matters. The Pennyrile APA also provides that the Buyer shall have the right to conduct diligence on the Pennyrile mine complex and may contest the fair market value of the purchased assets or the estimate of the costs of the assumed liabilities following such diligence investigation. In the event the Buyer does contest such amounts, the parties will attempt to resolve the dispute and to the extent they cannot, will submit the matter to a third party to make a final determination with respect to such matters, and will adjust the purchase price accordingly.

The parties have made customary representations, warranties and covenants in the Pennyrile APA. The closing of the transactions contemplated by the Asset Purchase Agreement are subject to a number of closing conditions, including, among others, the performance of applicable covenants and accuracy of representations and warranties and absence of material adverse changes in the condition of the Pennyrile mine complex. Subject to the satisfaction of closing conditions, the transaction contemplated by the Pennyrile APA is expected to close in the fourth quarter of 2019.

Coal Supply Asset Purchase Agreement

On September 6, 2019, the Partnership, the Buyer and the Buyer Parent entered into an Asset Purchase Agreement for the sale and assignment of certain coal supply agreements associated with the Pennyrile mine complex (the “Coal Supply APA”) in exchange for approximately $7.3 million. The Coal Supply APA includes customary representations of the parties thereto and indemnification for losses arising from the breaches of such representations and for liabilities arising during the period in which the relevant parties were not party to the coal supply agreements. The transactions contemplated by the Coal Supply APA closed upon the execution thereof.

Discontinued Operations

The Pennyrile operating results for the three and nine months ended September 30, 2019 and 2018 are recorded as discontinued operations on the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income including a $38.6 million impairment loss for the three and nine months ended September 30, 2019 associated with the sale. The current and non-current assets and liabilities previously related to Pennyrile have been reclassified to the appropriate held for sale categories on the Partnership’s unaudited condensed consolidated statement of financial position at December 31, 2018.

Major assets and liabilities of discontinued operations for Pennyrile Energy LLC as of September 30, 2019 and December 31, 2018 are summarized as follows:

  September 30, 2019  December 31, 2018 
  (in thousands) 
Carrying amount of major classes of assets included as part
of discontinued operations:		  
Cash and cash equivalents $-  $1 
Accounts receivable  1,428   2,645 
Accounts receivable-other  174   - 
Inventories  -   455 
Advance royalties  -   540 
Prepaid expenses and other  -   107 
Total current assets of the disposal group classified as held for sale in the statement of financial position $1,602  $3,748 
         
Property and equipment (net) $6,517  $54,338 
Advance royalties, net of current portion  -   1,438 
Other non-current assets  -   443 
Total non-current assets of the disposal group classified as held for sale in the statement of financial position $6,517  $56,219 
         
Carrying amount of major classes of liabilities included as part
of discontinued operations:		        
Accounts payable $3,389  $3,772 
Accrued expenses and other  1,332   1,457 
Asset retirement obligations, current portion  2,200   - 
Total current liabilities of the disposal group classified as held for sale in the statement of financial position $6,921  $5,229 
         
Asset retirement obligations, net of current portion $-  $968 
Total non-current liabilities of the disposal group classified as held for sale in the statement of financial position $-  $968 

Major components of net loss from discontinued operations for Pennyrile Energy LLC for three months ended September 30, 2019 and 2018 are summarized as follows:

  Three Months Ended
September 30,		  Nine Months Ended
September 30,		 
  2019  2018  2019  2018 
  (in thousands) 
Major line items constituting loss from discontinued operations for the Pennyrile Energy LLC disposal:                
Coal sales $8,920  $12,529  $35,009  $37,748 
Total revenues  8,920   12,529   35,009   37,748 
                 

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)

  11,797   13,725   39,928   39,108 
Depreciation, depletion and amortization  1,778   1,974   5,959   5,892 

Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)

  52   80   130   161 
Asset impairment and related charges  38,633   -   38,633   - 
(Gain) on sale/disposal of assets, net  -   4   (2)  4 
Total costs, expenses and other  52,260   15,783   84,648   45,165 
(Loss) from discontinued operations before income taxes for the Pennyrile Energy LLC disposal  (43,340)  (3,254)  (49,639)  (7,417)
Income taxes  -   -   -   - 
Net (loss) from discontinued operations $(43,340) $(3,254) $(49,639) $(7,417)

Cash Flows. The depreciation, depletion and amortization amounts for Pennyrile for each period presented are listed in the previous table. The Partnership had capital expenditures of $0.4 million and $1.1 million for the three months ended September 30, 2019 and 2018, respectively, related to Pennyrile. The Pennyrile capital expenditures for the nine months ended September 30, 2019 and 2018 were $1.4 million and $3.0 million, respectively. The asset impairment loss of $38.6 million is the only material non-cash operating item for all periods presented related to Pennyrile. Pennyrile did not have any material non-cash investing items for any periods presented.

5. PREPAID EXPENSES AND OTHER CURRENT ASSETS

 

Prepaid expenses and other current assets as of March 31,September 30, 2019 and December 31, 2018 consisted of the following:

 

 September 30, December 31, 
 

March 31, 2019

 December 31, 2018  2019 2018 
 (in thousands)  (in thousands) 
Other prepaid expenses $996  $971  $1,015  $865 
Prepaid insurance  741   1,397   1,869   1,397 
Prepaid leases  89   92   82   92 
Supply inventory  306   306   306   306 
Total $2,132  $2,766  $3,272  $2,660 

On June 28, 2019, the Partnership entered into a settlement agreement with a third party which allowed the third party to maintain certain pipelines pursuant to designated permits at our Central Appalachia operations. The agreement required the third party to pay the Partnership $7.0 million in consideration. The Partnership received $4.2 million on July 3, 2019 with the balance of $2.8 million due on or before February 29, 2020. At September 30, 2019, the $2.8 million receivable was recorded in Receivable –Other on the Partnership’s unaudited condensed consolidated statements of financial position. A gain of $6.9 million was recorded on the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income during the second quarter of 2019.

 

The Partnership acquired 568,794 shares of Mammoth Energy Services, Inc. (NASDAQ: TUSK)(“Mammoth Inc.”) through a series of transactions in years prior to 2018. As of December 31, 2018, the Partnership owned 104,100 shares of Mammoth Inc., which were recorded at fair market value as a current asset on the Partnership’s unaudited condensed consolidated statements of financial position. During the three months ended March 31,first quarter of 2019, the Partnership sold its 104,100 shares for net consideration of approximately $2.3 million.

 

4.6. PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment, including coal properties and mine development and construction costs, as of March 31,September 30, 2019 and December 31, 2018 are summarized by major classification as follows:

 

   September 30, December 31, 
 Useful Lives March 31, 2019 December 31, 2018  Useful Lives 2019 2018 
   (in thousands)    (in thousands) 
Land and land improvements   $10,872  $13,181    $10,082  $13,181 
Mining and other equipment and related facilities 2 - 20 Years  308,417   307,300  2 - 20 Years  256,582   253,489 
Mine development costs 1 - 15 Years  64,552   63,681  1 - 15 Years  41,560   39,967 
Coal properties 1 - 15 Years  63,527   63,527  1 - 15 Years  58,358   58,424 
Construction work in process    3,223   3,199     10,058   2,123 
Total    450,591   450,888     376,640   367,184 
Less accumulated depreciation, depletion and amortization    (282,437)  (277,029)    (254,754)  (247,662)
Net   $168,154  $173,859    $121,886  $119,522 

 

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties, amortization expense for mine development costs and amortization expense for asset retirement costs for the three and nine months ended March 31,September 30, 2019 and 2018 were as follows:

 

 Three Months Ended March 31,  Three Months Ended September 30, Nine Months Ended September 30, 
 2019 2018  2019 2018 2019 2018 
 (in thousands)  (in thousands) 
Depreciation expense-mining and other equipment and related facilities $4,163  $4,087  $2,525  $2,622  $7,526  $7,740 
Depletion expense for coal properties  466   472   419   418   1,247   1,264 
Amortization expense for mine development costs  844   749   517   515   1,543   1,506 
Amortization expense for asset retirement costs  76   119   64   100   195   331 
Total $5,549  $5,427  $3,525  $3,655  $10,511  $10,841 

 

5.7. LEASES

 

The Partnership leases various mining, transportation and other equipment under operating and finance leases. The leases have remaining lease terms of 1 year to 9 years, some of which include options to extend the leases for up to 15 years. The Partnership determines if an arrangement is a lease at inception. Some of the leases include both lease and non-lease components which are accounted for as a single lease component as the Partnership has elected the practical expedient to combine these components for all leases. Operating leases are included in operating lease right-of-use (“ROU”) assets, current liabilities and non-current liabilities on our unaudited condensed consolidated statements of financial position.liabilities. Finance leases are included in plant, property and equipment, current liabilities and long-term liabilities on our unaudited condensed consolidated statements of financial position.liabilities.

 

ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the Partnership’s obligation to make lease payments related to the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. The Partnership utilizes the implicit rate in the lease, if determinable, at the commencement date of the lease to determine the present value of the lease payments. If the implicit rate is not determinable, the Partnership utilizes its incremental borrowing rate at the commencement date of the lease to determine the present value of the lease payments. The Partnership’s lease terms may include options to extend or terminate the lease when it is reasonably certain that the Partnership will exercise the option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

 

Supplemental balance sheet information related to leases was as follows:

 

 March 31, 2019  September 30, 2019 
  (in thousands)  (in thousands) 
Operating leases        
Operating lease right-of use assets $13,523  $11,926 
        
Operating lease liabilities-current $3,175  $3,260 
Operating lease liabilities-long-term  9,971   8,300 
Total operating lease liabilities $13,146  $11,560 
        
Finance leases        
Property. Plant and Equipment, gross $10  $10 
Accumulated depreciation  (1)  (4)
Total Property, Plant and Equipment, net $9  $6 
        
Finance leases - current portion $4  $4 
Finance leases - noncurrent portion  5   3 
Total finance lease obligation $9  $7 

Weighted Average Discount Rates and Lease Terms

Weighted Average Discount RateSeptember 30, 2019
   
Weighted Average Discount RateMarch 31, 2019
    
Operating leases  7.0%
Finance leases  7.0%
Weighted Average Lease Term
Operating leases  5.45.01 years 
Finance leases  2.11.53 years 

Supplemental cash flow information related to leases was as follows:

 

 

Three months ended

March 31, 2019

  Nine months ended September 30, 2019 
 (in thousands)  (in thousands) 
Cash paid for amounts included in the measurement of lease liabilities:        
Operating cash flows for operating leases $977  $2,924 
Operating cash flows for finance leases $-  $- 
Financing cash flows for finance leases $1  $3 
        
Right-of-use assets obtained in exchange for lease obligations:        
Operating leases $13,896  $14,267 
Finance leases $10  $10 

 

Maturities of lease liabilities are as follows:

 

Year ending December 31, Operating leases Finance leases 
 Operating leases Finance leases  (in thousands) 
Year ending December 31, (in thousands) 
2019 (excluding the three months ended March 31, 2019) $2,986  $4 
2019 (excluding the nine months ended September 30, 2019) $982  $    2 
2020  3,903   5   3,730   5 
2021  2,842   4   2,908   - 
2022  1,819   -   1,895   - 
2023  911   -   929   - 
2024  908     
Thereafter  3,303   -   2,361   - 
Total lease payments  15,764   13   13,713   7 
Less imputed interest  2,618   4 
Less: imputed interest  (2,153)  - 
Total $13,146  $9  $11,560  $7 

 

The components of lease expense were as follows:

 

 Three months ended September 30, 2019 Nine months ended September 30, 2019 
 Three months ended March 31, 2019  (in thousands) 
 (in thousands)      
Operating lease cost $983  $981  $2,943 
            
Finance lease cost:            
Amortization of right-of-use assets $1  $1  $3 
Interest on lease liabilities  -   -   - 
Total finance lease cost $1  $1  $3 

 

1215
 

 

6.8. OTHER NON-CURRENT ASSETS

 

Other non-current assets as of March 31,September 30, 2019 and December 31, 2018 consisted of the following:

 

 March 31, 2019 December 31, 2018  September 30, 2019 December 31, 2018 
 (in thousands)  (in thousands) 
Deposits and other $856  $1,144  $704  $859 
Due (to) Rhino GP  (39)  (84)  (47)  (84)
Non-current receivable  24,192   24,192   24,192   24,192 
Deferred expenses  151   158 
Total $25,160  $25,410  $24,849  $24,967 

Non-current receivable. The non-current receivable balance of $24.2 million as of March 31,September 30, 2019 and December 31, 2018 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 $24.2 million is also included in the Partnership’s accrued workers’ compensation benefits liability balance, which is included in the other non-current liabilities section of the Partnership’s unaudited condensed consolidated statements of financial position. The Partnership presents this amount on a gross asset and liability basis since a right of setoff does not exist per the accounting guidance in ASC Topic 210,Balance Sheet. This presentation has no impact on the Partnership’s results of operations or cash flows.

 

7.9. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

 

Accrued expenses and other current liabilities as of March 31,September 30, 2019 and December 31, 2018 consisted of the following:

 

  March 31, 2019  December 31, 2018 
  (in thousands) 
Payroll, bonus and vacation expense $2,104  $2,151 
Non-income taxes  2,668   2,168 
Royalty expenses  2,001   1,669 
Accrued interest  55   35 
Health claims  907   868 
Workers’ compensation & pneumoconiosis  1,900   1,900 
Other  1,205   1,316 
Total $10,840  $10,107 

13

  September 30, 2019  December 31, 2018 
  (in thousands) 
Payroll, bonus and vacation expense $2,041  $1,529 
Non-income taxes  2,757   1,794 
Royalty expenses  2,266   1,368 
Accrued interest  85   35 
Health claims  905   868 
Workers’ compensation & pneumoconiosis  1,900   1,900 
Other  1,879   1,156 
Total $11,833  $8,650 

 

8.10. DEBT

 

Debt as of March 31,September 30, 2019 and December 31, 2018 consisted of the following:

 

 March 31, 2019 December 31, 2018  September 30, 2019 December 31, 2018 
 (in thousands)  (in thousands) 
Note payable -Financing Agreement $28,673  $29,048  $37,923  $29,048 
Note payable-other debt  -   522   1,070   522 
Finance lease obligation  9   -   7   - 
Net unamortized debt issuance costs  (3,679)  (4,095)  (5,581)  (4,095)
Net unamortized original issue discount  (738)  (843)  (527)  (843)
Total  24,265   24,632   32,892   24,632 
Less current portion  (3,057)  (2,174)  (4,445)  (2,174)
Long-term debt $21,208  $22,458  $28,447  $22,458 

16

Financing Agreement

 

On December 27, 2017, the Operating Company, a wholly-owned subsidiary of the Partnership, certain of the Operating Company’s subsidiaries identified as Borrowers (together with the Operating Company, the “Borrowers”), the Partnership and certain other Operating Company subsidiaries identified as Guarantors (together with the Partnership, the “Guarantors”), entered into a Financing Agreement (the “Financing Agreement”) with Cortland Capital Market Services LLC, as Collateral Agent and Administrative agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein (the “Lenders”), pursuant to which the Lenders agreed to provide the Borrowers with a multi-draw term loan in the original aggregate principal amount of $80 million, subject to the terms and conditions set forth in the Financing Agreement. The total principal amount is divided into a $40 million commitment, the conditions of which were satisfied at the execution of the Financing Agreement (the “Effective Date Term Loan Commitment”) and ana $40 million additional $35 million commitment that iswas contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). As of September 30, 2019, we have utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. Loans made pursuant to the Financing Agreement are secured by substantially all of the Borrowers’ and Guarantors’ assets. The Financing Agreement terminates onoriginally had a termination date of December 27, 2020.2020, which was amended to December 27, 2022 per the fifth amendment to the Financing Agreement discussed further below.

 

Loans made pursuant to the Financing Agreement are, at the Operating Company’s option, either “Reference Rate Loans” or “LIBOR Rate Loans.” Reference Rate Loans bear interest at the greatest of (a) 4.25% per annum, (b) the Federal Funds Rate plus 0.50% per annum, (c) the LIBOR Rate (calculated on a one-month basis) plus 1.00% per annum or (d) the Prime Rate (as published in the Wall Street Journal) or if no such rate is published, the interest rate published by the Federal Reserve Board as the “bank prime loan” rate or similar rate quoted therein, in each case, plus an applicable margin of 9.00% per annum (or 12.00% per annum if the Operating Company has elected to capitalize an interest payment pursuant to the PIK Option, as described below). LIBOR Rate Loans bear interest at the greater of (x) the LIBOR for such interest period divided by 100% minus the maximum percentage prescribed by the Federal Reserve for determining the reserve requirements in effect with respect to eurocurrency liabilities for any Lender, if any, and (y) 1.00%, in each case, plus 10.00% per annum (or 13.00% per annum if the Borrowers have elected to capitalize an interest payment pursuant to the PIK Option). Interest payments are due on a monthly basis for Reference Rate Loans and one-, two- or three-month periods, at the Operating Company’s option, for LIBOR Rate Loans. If there is no event of default occurring or continuing, the Operating Company may elect to defer payment on interest accruing at 6.00% per annum by capitalizing and adding such interest payment to the principal amount of the applicable term loan (the “PIK Option”).

 

Commencing December 31, 2018, the principal for each loan made under the Financing Agreement will be payable on a quarterly basis in an amount equal to $375,000 per quarter, with all remaining unpaid principal and accrued and unpaid interest originally due on December 27, 2020.2020 (see discussion of fifth amendment below). In addition, the Borrowers must make certain prepayments over the term of any loans outstanding, including: (i) the payment of 25% of Excess Cash Flow (as that term is defined in the Financing Agreement) of the Partnership and its subsidiaries for each fiscal year, commencing with respect to the year ending December 31, 2019, (ii) subject to certain exceptions, the payment of 100% of the net cash proceeds from the dispositions of certain assets, the incurrence of certain indebtedness or receipts of cash outside of the ordinary course of business, and (iii) the payment of the excess of the outstanding principal amount of term loans outstanding over the amount of the Collateral Coverage Amount (as that term is defined in the Financing Agreement). In addition, the Lenders are entitled to (i) certain fees, including 1.50% per annum of the unused Delayed Draw Term Loan Commitment for as long as such commitment exists, (ii) for the 12-month period following the execution of the Financing Agreement, a make-whole amount equal to the interest and unused Delayed Draw Term Loan Commitment fees that would have been payable but for the occurrence of certain events, including among others, bankruptcy proceedings or the termination of the Financing Agreement by the Operating Company, and (iii) audit and collateral monitoring fees and origination and exit fees.

The Financing Agreement requires the Borrowers and Guarantor to comply with several affirmative covenants at any time loans are outstanding, including, among others: (i) the requirement to deliver monthly, quarterly and annual financial statements, (ii) the requirement to periodically deliver certificates indicating, among other things, (a) compliance with terms of the Financing Agreement and ancillary loan documents, (b) inventory, accounts payable, sales and production numbers, (c) the calculation of the Collateral Coverage Amount (as that term is defined in the Financing Agreement), (d) projections for the Partnership and its subsidiaries and (e) coal reserve amounts; (iii) the requirement to notify the Administrative Agent of certain events, including events of default under the Financing Agreement, dispositions, entry into material contracts, (iv) the requirement to maintain insurance, obtain permits, and comply with environmental and reclamation laws (v) the requirement to sell up to $5.0 million of shares in Mammoth Energy Services Inc. and use the net proceeds therefrom to prepay outstanding term loans, which was completed during the first half of 2018 and (vi) establish and maintain cash management services and establish a cash management account and deliver a control agreement with respect to such account to the Collateral Agent. The Financing Agreement also contains negative covenants that restrict the Borrowers and Guarantors ability to, among other things: (i) incur liens or additional indebtedness or make investments or restricted payments, (ii) liquidate or merge with another entity, or dispose of assets, (iii) change the nature of their respective businesses; (iv) make capital expenditures in excess, or, with respect to maintenance capital expenditures, lower than, specified amounts, (v) incur restrictions on the payment of dividends, (vi) prepay or modify the terms of other indebtedness, (vii) permit the Collateral Coverage Amount to be less than the outstanding principal amount of the loans outstanding under the Financing Agreement or (viii) permit the trailing six month Fixed Charge Coverage Ratio of the Partnership and its subsidiaries to be less than 1.20 to 1.00 commencing with the six-month period ending June 30, 2018. See Note 19 for information relating to the lenders’ waiver of the Fixed Charge Coverage Ratio for the six-month period ending March 31, 2019.

 

The Financing Agreement contains customary events of default, following which the Collateral Agent may, at the request of lenders, terminate or reduce all commitments and accelerate the maturity of all outstanding loans to become due and payable immediately together with accrued and unpaid interest thereon and exercise any such other rights as specified under the Financing Agreement and ancillary loan documents. The Partnership entered into a warrant agreement with certain parties that are also parties to the Financing Agreement discussed above. (See Note 1113 for further discussion)

 

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

 

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

 

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

On December 20, 2018, the Partnership, entered into a limited waiver and consent (the “Waiver”) to the Financing Agreement. The Waiver relates to the sales by the Partnership of certain real property in Western Colorado, the net proceeds of which are required to be used to reduce the Partnership’s debt under the Financing Agreement. As of the date of the Waiver, the Partnership had sold 9 individual lots in smaller transactions. On December 31, 2018, the Partnership used the sale proceeds of approximately $379,000 to reduce the debt. Rather than transmitting net proceeds with respect to each individual transaction, the Partnership and Lenders agreed in principle to delay repayment until an aggregate payment could be made at the end of 2018. The Waiver (i) contains a ratification by the Lenders of the sale of the individual lots to date and waives the associated technical defaults under the Financing Agreement for not making immediate payments of net proceeds therefrom, (ii) permits the sale of certain specified additional lots and (iii) subject to Lender consent, permits the sale of other lots on a going forward basis. The net proceeds of future sales will be held by the Partnership until a later date to be determined by the Lenders.

 

On February 13, 2019, the Partnership entered into a second amendment (the “Amendment”) to the Financing Agreement. The Amendment provided the Lender’s consent for the Partnership to pay a one-time cash distribution on February 14, 2019 to the Series A Preferred Unitholders not to exceed approximately $3.2 million. The Amendment allowed the Partnership to sell its remaining shares of Mammoth Energy Services, Inc. and utilize the proceeds for payment of the one-time cash distribution to the Series A Preferred Unitholders and waived the requirement to use such proceeds to prepay the outstanding principal amount outstanding under the Financing Agreement.

 

The Amendment also waived any Event of Default that has or would otherwise arise under Section 9.01(c) of the Financing Agreement solely by reason of the Borrowers failing to comply with the Fixed Charge Coverage Ratio covenant in Section 7.03(b) of the Financing Agreement for the fiscal quarter ending December 31, 2018. The Amendment includes an amendment fee of approximately $0.6 million payable by the Partnership on May 13, 2019 and an exit fee equal to 1% of the principal amount of the term loans made under the Financing Agreement that is payable on the earliest of (w) the final maturity date of the Financing Agreement, (x) the termination date of the Financing Agreement, (y) the acceleration of the obligations under the Financing Agreement for any reason, including, without limitation, acceleration in accordance with Section 9.01 of the Financing Agreement, including as a result of the commencement of an insolvency proceeding and (z) the date of any refinancing of the term loan under the Financing Agreement. The Amendment amended the definition of the Make-Whole Amount under the Financing Agreement to extend the date of the Make-Whole Amount period to December 31, 2019.

 

AtOn May 8, 2019, the Partnership entered into a third amendment (“Third Amendment”) to the Financing Agreement. The Third Amendment includes the lenders agreement to waive any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended March 31, 2019. The Third Amendment increases the original exit fee of 3.0% to 6.0%. The original exit fee of 3% was included in the Financing Agreement at the execution date and the increase of the total exit fee to 6% was included as part of the amendment dated February 13, 2019 discussed above and this Third Amendment. The exit fee is applied to the principal amount of the loans made under the Financing Agreement that is payable on the earliest of (a) the final maturity date, (b) the termination date of the Financing agreement for any reason, (c) the acceleration of the obligations in the Financing Agreement for any reason and (d) the date of any refinancing of the term loan under the Financing Agreement.

On August 16, 2019, the Partnership entered into a fourth amendment (the “Fourth Amendment”) to the Financing Agreement. The Fourth Amendment provides a $5.0 million term loan provided by the Lenders to the Partnership under the delayed draw feature of the Financing Agreement and extends the period by which an applicable premium payable to the Lenders will be calculated to the final maturity date.

On September 6, 2019, the Partnership entered into a fifth amendment (the “Fifth Amendment”) to the Financing Agreement. The Fifth Amendment (i) extends the maturity of the Financing Agreement to December 27, 2022, (ii) provides a $5.0 million term loan provided by the Lenders to the Partnership under the delayed draw feature of the Financing Agreement, (iii) extends the period by which an applicable premium payable to the Lenders will be calculated to December 31, 2021, (iv) modifies certain definitions and concepts to account for the Partnership’s recent acquisition of properties from Blackjewel, (v) permits the disposition of the Pennyrile mining complex and (viii) provides for the payment of additional fees to the Lenders, including a consent fee of $1.0 million, an amendment fee of $825,000 and an increase in the lender exit fee of 1.00% to a total exit fee of 7.00% of the amount of term loans made under the Financing Agreement that is payable at final maturity of the Financing Agreement.

At September 30, 2019, the Partnership had $28.7$27.9 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (12.50%(12.13%), $5.0 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (12.17%) and $5.0 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (12.06%).

 

19

9.11. ASSET RETIREMENT OBLIGATIONS

 

The changes in asset retirement obligations for the threenine months ended March 31,September 30, 2019 and the year ended December 31, 2018 are as follows:

 

  March 31, 2019  December 31, 2018 
  (in thousands) 
Balance at beginning of period (including current portion) $18,549  $18,662 
Accretion expense  319   1,269 
Adjustments to the liability from annual recosting and other  -   (1,083)
Liabilities settled  (15)  (299)
Balance at end of period  18,853   18,549 
Less current portion of asset retirement obligation  (465)  (465)
Long-term portion of asset retirement obligation $18,388  $18,084 

16
  September 30, 2019  December 31, 2018 
  (in thousands) 
Balance at beginning of period (including current portion) $17,581  $18,662 
Accretion expense  957   1,269 
Adjustments to the liability from annual recosting and other  -   (1,083)
Jewell Valley LLC acquisition  2,596   - 
Reclassification to held for sale  (38)  (968)
Liabilities settled  (66)  (299)
Balance at end of period  21,030   17,581 
Less current portion of asset retirement obligation  (465)  (465)
Long-term portion of asset retirement obligation $20,565  $17,116 

 

10.12. EMPLOYEE BENEFITS

 

401(k) Plans

 

The Operating Company sponsors a defined contribution savings plans for all employees. Under the 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 Partnership’s discretion. The expense under these plans for the three and nine months ended March 31,September 30, 2019 and 2018 is included in Cost of operations and Selling, general and administrative expense in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income and was as follows:

 

  Three Months Ended March 31, 
  2019  2018 
  (in thousands) 
401(k) plan expense $489  $436 
  Three Months Ended
September 30,		  Nine months ended
September 30,		 
  2019  2018  2019  2018 
  (in thousands) 
401(k) plan expense $364  $323  $1,041  $903 

 

11.13. PARTNERS’ CAPITAL

 

Common Unit Warrants

 

In December 2017, the Partnership entered into a warrant agreement with certain parties that are also parties to the Financing Agreement discussed above. The warrant agreement included the issuance of a total of 683,888 warrants for common units (“Common Unit Warrants”) of the Partnership at an exercise price of $1.95 per unit, which was the closing price of the Partnership’s common units on the OTC market as of December 27, 2017. The Common Unit Warrants have a five year expiration date. The Common Unit Warrants and the Partnership’s common units after exercise are both transferable, subject to applicable US securities laws. The Common Unit Warrant exercise price is $1.95 per unit, but the price per unit will be reduced by future common unit distributions and other further adjustments in price included in the warrant agreement for transactions that are dilutive to the amount of the Partnership’s common units outstanding. The warrant agreement includes a provision for a cashless exercise whereby the warrant holders can receive a net number of common units. Per the warrant agreement, the warrants are detached from the Financing Agreement and fully transferable. The Partnership analyzed the Common Unit Warrants in accordance with the applicable accounting literature and concluded the Common Unit Warrants should be classified as equity. The Partnership allocated the $40.0 million initial proceeds from the Financing Agreement between the Common Unit Warrants and the Financing Agreement based upon their relative fair values. The allocation based upon relative fair values resulted in approximately $1.3 million being recorded for the Common Unit Warrants in the Partner’s Capital equity section and a corresponding reduction indiscount on Long-term debt, net on the Partnership’s unaudited condensed consolidated statements of financial position.

 

20

Series A Preferred Units

 

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

 

The Series A preferred units 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 are 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 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 on equity securities that rank junior to the Series A preferred units.

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

 

The Partnership has 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.

 

During the first quarter of 2019, wethe Partnership paid $3.2 million to the holders of Series A preferred units for distributions earned for the year ended December 31, 2018. During the first quarter of 2018, wethe Partnership paid the holders of Series A preferred units $6.0 million in distributions earned for the year ended December 31, 2017. We haveThe Partnership has accrued approximately $0.3$0.9 million for distributions to holders of the Series A preferred units for the threenine months ended March 31,September 30, 2019.

 

Investment in Royal Common Stock

 

On September 1, 2017, Royal elected to convert certain obligations to the Partnership totaling $4.1 million to shares of Royal common stock. Royal issued 914,797 shares of its common stock to the Partnership at a conversion price of $4.51 per share. The price per share was 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. The Partnership recorded the $4.1 million conversion as Investment in Royal common stock in the Partners’ Capital section of the Partnership’s unaudited condensed consolidated statements of financial position since Royal does not have significant economic activity apart from its investment in the Partnership.

 

Other Comprehensive Income

 

In accordance with Accounting Standards Codification (“ASU”) 2016-01, which was effective for fiscal years that began after December 15, 2017, the Partnership ceased recording fair market adjustments for the shares it owns in Mammoth Energy Services, Inc. (NASDAQ: TUSK) (“Mammoth Inc.”) in Other Comprehensive Income during the fourth quarter of 2018. Upon adoption during the fourth quarter of 2018, the Partnership recorded a $4.2 million reclassification from Other Comprehensive Income to Partners’ Capital relating to its Mammoth Inc. shares that had a readily determinable fair value.

 

Accumulated Distribution Arrearages

 

Pursuant to the Partnership’s partnership agreement, the Partnership’s common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended March 31,September 30, 2019, the Partnership has suspended the cash distribution on its common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, the Partnership announced cash distributions per common unit at levels lower than the minimum quarterly distribution. The Partnership has not paid any distribution on its subordinated units for any quarter after the quarter ended March 31, 2012. As of March 31,September 30, 2019, the Partnership had accumulated arrearages of $731.6$848.7 million.

18

12.14. EARNINGS PER UNIT (“EPU”)

 

The following table presents a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended March 31,September 30, 2019 and 2018:

 

Three Months Ended March 31, 2019 

General

Partner

 

Common

Unitholders

 

Subordinated

Unitholders

 

Preferred

Unitholders

 
Three months ended September 30, 2019 General
Partner		 Common Unitholders Subordinated Unitholders Preferred Unitholders 
 (in thousands, except per unit data)   
Numerator:  (in thousands, except per unit data)          
Interest in net (loss)/ income $(32) $(6,941) $(606) $300 
                
Interest in net (loss)/income:                
Net (loss)/income from continuing operations $(36) $(7,917) $(691) $300 
Net (loss) from discontinued operations  (181)  (39,695)  (3,464)  - 
Total interest in net (loss)/income $(217) $(47,612) $(4,155) $300 
Denominator:                                
Weighted average units used to compute basic EPU   n/a   13,098   1,144   1,500   n/a   13,098   1,143   1,500 
Weighted average units used to compute diluted EPU   n/a   13,098   1,144   1,500   n/a   13,098   1,143   1,500 
                                
Net (loss)/income per limited partner unit, basic:   n/a  $(0.53) $(0.53) $0.20 
Net (loss)/income per limited partner unit, basic                
Net (loss)/income per unit from continuing operations  n/a  $(0.60) $(0.60) $0.20 
Net (loss) per unit from discontinued operations  n/a   (3.03)  (3.03)  - 
Net (loss)/income per common unit, basic  n/a  $(3.63) $(3.63) $0.20 
Net (loss)/income per limited partner unit, diluted   n/a  $(0.53) $(0.53) $0.20                 
Net (loss)/income per unit from continuing operations  n/a  $(0.60) $(0.60)  0.20 
Net (loss) per unit from discontinued operations  n/a   (3.03)  (3.03)  - 
Net (loss)/income per common unit, diluted  n/a  $(3.63) $(3.63)  0.20 

Three months ended September 30, 2018 General
Partner		  Common Unitholders  Subordinated Unitholders  Preferred Unitholders 
 (in thousands, except per unit data) 
Numerator:   
Interest in net (loss)/income:                
Net (loss)/income from continuing operations $(10) $(2,248) $(197) $1,179 
Net (loss) from discontinued operations  (14)  (2,980)  (260)  - 
Total interest in net (loss)/income $(24) $(5,228) $(457)  1,179 
Denominator:                
Weighted average units used to compute basic EPU  n/a   13,098   1,146   1,500 
Weighted average units used to compute diluted EPU  n/a   13,098   1,146   1,500 
                 
Net (loss)/income per limited partner unit, basic                
Net (loss)/income per unit from continuing operations  n/a  $(0.17) $(0.17) $0.79 
Net (loss) per unit from discontinued operations  n/a   (0.23)  (0.23)  - 
Net (loss)/income per common unit, basic  n/a  $(0.40) $(0.40) $0.79 
Net (loss)/income per limited partner unit, diluted                
Net (loss)/income per unit from continuing operations  n/a  $(0.17) $(0.17) $0.79 
Net (loss) per unit from discontinued operations  n/a   (0.23)  (0.23)  - 
Net (loss)/income per common unit, diluted  n/a  $(0.40) $(0.40) $0.79 

 

Three Months Ended March 31, 2018 

General

Partner

 

Common

Unitholders

 

Subordinated

Unitholders

 

Preferred

Unitholders

 
Nine months ended September 30, 2019 General
Partner		 Common Unitholders Subordinated Unitholders Preferred Unitholders 
 (in thousands, except per unit data) 
Numerator:  (in thousands, except per unit data)        
Interest in net (loss)/income $(13) $(2,856) $(252) $300 
                
Interest in net (loss)/income:                
Net (loss)/income from continuing operations $(42) $(9,262) $(808) $900 
Net (loss) from discontinued operations  (207)  (45,463)  (3,969)  - 
Total interest in net (loss)/income $(249) $(54,725) $(4,777) $900 
Denominator:                                
Weighted average units used to compute basic EPU   n/a   12,994   1,146  $1,500   n/a   13,098   1,143   1,500 
Weighted average units used to compute diluted EPU   n/a   12,994   1,146  $1,500   n/a   13,098   1,143   1,500 
                                
Net (loss)/income per limited partner unit, basic   n/a  $(0.22) $(0.22) $0.20                 
Net (loss)/income per unit from continuing operations  n/a  $(0.71) $(0.71) $0.60 
Net (loss) per unit from discontinued operations  n/a   (3.47)  (3.47)  - 
Net (loss)/income per common unit, basic  n/a  $(4.18) $(4.18) $0.60 
Net (loss)/income per limited partner unit, diluted   n/a  $(0.22) $(0.22) $0.20                 
Net (loss)/income per unit from continuing operations  n/a  $(0.71) $(0.71)  0.60 
Net (loss) per unit from discontinued operations  n/a   (3.47)  (3.47)  - 
Net (loss)/income per common unit, diluted  n/a  $(4.18) $(4.18)  0.60 

 

Nine months ended September 30, 2018 General
Partner		  Common Unitholders  Subordinated Unitholders  Preferred Unitholders 
 (in thousands, except per unit data) 
Numerator:   
Interest in net (loss)/income:                
Net (loss)/income from continuing operations $(20) $(4,355) $(382)  1,788 
Net (loss) from discontinued operations  (31)  (6,789)  (597)  - 
Total interest in net (loss)/income $(51) $(11,144) $(979)  1,788 
Denominator:                
Weighted average units used to compute basic EPU  n/a   13,035   1,146   1,500 
Weighted average units used to compute diluted EPU  n/a   13,035   1,146   1,500 
                 
Net (loss)/income per limited partner unit, basic                
Net (loss)/income per unit from continuing operations  n/a  $(0.34) $(0.34) $1.19 
Net (loss) per unit from discontinued operations  n/a   (0.52)  (0.52)  - 
Net (loss)/income per common unit, basic  n/a  $(0.86) $(0.86) $1.19 
Net (loss)/income per limited partner unit, diluted                
Net (loss)/income per unit from continuing operations  n/a  $(0.34) $(0.34) $1.19 
Net (loss) per unit from discontinued operations  n/a   (0.52)  (0.52)  - 
Net (loss)/income per common unit, diluted  n/a  $(0.86) $(0.86) $1.19 

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. Since the Partnership incurred a total net losses for three and nine months ended March 31,September 30, 2019 and 2018, all potential dilutive units were excluded from the diluted EPU calculation for these periods because when an entity incurs a net loss in a period, potential dilutive units shall not be included in the computation of diluted EPU since their effect will always be anti-dilutive. There were 683,888 potential dilutive common units related to the Common Unit Warrants as discussed in Note 1113 for the threenine months ended March 31,September 30, 2019 and 2018.

 

13.15. COMMITMENTS AND CONTINGENCIES

 

Coal Sales Contracts and Contingencies—As of March 31,September 30, 2019, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

 

Year Tons (in thousands) Number of customers  Tons (in thousands) Number of customers
2019 Q2-Q4  3,360   19 
2019 Q4 762 13
2020  1,880   7  838 3
2021  852   3  120 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 2.0 million gallons of diesel fuel at fixed prices from January 2019 through December 2019 for approximately $4.3 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 incurred no purchase coal expense from coal purchase contracts or expense from OTC purchases for the three and nine months ended March 31,September 30, 2019 and 2018.

 

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. Please read Note 57 for additional discussion of leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the three and nine months ended March 31,September 30, 2019 and 2018 are included in Cost of operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income and was as follows:

 

 Three Months Ended March 31,  Three Months Ended September 30, Nine months ended September 30, 
 2019 2018  2019 2018 2019 2018 
 (in thousands)  (in thousands)     
Lease expense $1,254  $430  $1,239  $1,105  $3,621  $2,334 
Royalty expense $3,905  $3,644  $3,150  $2,564  $9,602  $8,022 

 

Guarantees/Indemnifications and Financial Instruments with Off-Balance Sheet Risk— In the normal course of business, the Partnership is a party to certain guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. No liabilities related to these arrangements are reflected in the unaudited condensed consolidated statements of financial position. The Partnership had no outstanding letters of credit at March 31,September 30, 2019. The Partnership had outstanding surety bonds with third parties of $42.3$41.6 million as of March 31,September 30, 2019 to secure reclamation and other performance commitments, which are secured by $3.0 million in cash collateral on deposit with the Partnership’s surety bond provider. Of the $42.3$41.6 million, approximately $0.4 million relates to surety bonds for Deane Mining, LLC, and approximately $3.4 million relates to surety bonds for Sands Hill Mining, LLC, which in each case have not been transferred or replaced by the buyersbuyer of Deane Mining, LLC or Sands Hill Mining LLC as was agreed to by the parties as part of the transactions.transaction. The Partnership can provide no assurances that a surety company will underwrite the surety bonds of the purchaserspurchaser of these entities,Deane Mining LLC, nor is the Partnership aware of the actual amount of reclamation at any given time. Further, if there was a claim under these surety bonds prior to the transfer or replacement of such bonds by the buyersbuyer of Deane Mining, LLC, or Sands Hill Mining, LLC, then the Partnership may be responsible to the surety company for any amounts it pays in respect of such claim. While the buyers arebuyer is required to indemnify the Partnership for damages, including reclamation liabilities, pursuant to the agreements governing the sales of these entities,this entity, the Partnership may not be successful in obtaining any indemnity or any amounts received may be inadequate.

Certain surety bonds for Sands Hill Mining LLC had not been transferred or replaced by the buyer of Sands Hill Mining LLC as was agreed to when the Partnership sold Sands Hill Mining LLC to the buyer in November 2017. On July 9, 2019, the Partnership entered into an agreement with a third party for the replacement of the Partnership’s existing surety bond obligations with respect to Sands Hill Mining LLC. The Partnership agreed to pay the third party $2.0 million to assume the Partnership’s surety bond obligations related to Sands Hill Mining LLC. At the time of closing, the third party delivered to the Partnership confirmation from its surety underwriter evidencing the release and removal of the Partnership, its affiliates and guarantors, from the surety bond obligations and all related obligations under the Partnership’s bonding agreements related to Sands Hill Mining LLC, which includes a release of all applicable collateral for the surety bond obligations. Further, such confirmation from the surety underwriter was specifically provided for their acceptance of the third party as a replacement obligor.

 

14.16. MAJOR CUSTOMERS

 

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

 

  

March 31, 2019 Receivable

Balance

  December 31, 2018 Receivable Balance  

Three months ended

March 31, 2019 Sales

  

Three months ended

March 31, 2018 Sales

 
  (in thousands) 
Javelin Global $2,036  $4,347  $12,911  $4,042 
Integrity Coal  -   937   2,664   6,528 
Dominion Energy  1,268   -   2,497   8,165 
Big Rivers  946   863   4,048   5,515 
Trafigura Trading  -   -   -   7,159 
  September 30, 2019 Receivable Balance  December 31, 2018 Receivable Balance  Nine months ended September 30, 2019 Sales  Nine months ended September 30, 2018 Sales 
  (in thousands) 
Javelin Global $2,261  $4,347  $36,442  $29,267 

 

15.17. REVENUE

 

The Partnership adopted ASC Topic 606 on January 1, 2018, using the modified retrospective method. The adoption of Topic 606 has no impact on revenue amounts recorded on the Partnership’s financial statements. The new disclosures required by ASC Topic 606, as applicable, are presented below. The majority of the Partnership’s revenues are generated under coal sales contracts. Coal sales accounted for approximately 99.0% of the Partnership’s total revenues for the three and nine months ended March 31,September 30, 2019 and 2018. Other revenues generally consist of coal royalty revenues, coal handling and processing revenues, rebates and rental income, which accounted for approximately 1.0% of the Partnership’s total revenues for the three and nine months ended March 31,September 30, 2019 and 2018.

The majority of the Partnership’s coal sales contracts have a single performance obligation (shipment or delivery of coal according to terms of the sales agreement) and as such, the Partnership is not required to allocate the contract’s transaction price to multiple performance obligations. All of the Partnership’s coal sales revenue is recognized when shipment or delivery to the customer has occurred, the title or risk of loss has passed in accordance with the terms of the coal sales agreement, prices are fixed or determinable and collectability is reasonably assured. With respect to other revenues recognized in situations unrelated to the shipment of coal, the Partnership carefully reviews the facts and circumstances of each transaction and does not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the seller’s price to the buyer is fixed or determinable and collectability is reasonably assured.

 

In the tables below, the Partnership has disaggregated its revenue by category for each reportable segment as required by ASC Topic 606.

 

The following table disaggregates revenue by type for each reportable segment for the three months ended March 31, 2019:

  Central Appalachia  Northern Appalachia  Rhino Western  Illinois Basin  Other  Total Consolidated 
  (in thousands) 
Coal sales                        
Steam coal $13,389  $6,065  $8,711  $13,000  $-  $41,165 
Met coal  16,698   -   -   -   -   16,698 
Other revenue  320   554   -   -   -   874 
Total $30,407  $6,619  $8,711  $13,000  $-  $58,737 
25

 

The following table disaggregates revenue by type for each reportable segment for the three months ended March 31,September 30, 2019:

  Central Appalachia  Northern Appalachia  Rhino Western  Other  Total Consolidated 
  (in thousands) 
Coal sales                    
Steam coal $10,746  $6,201  $10,613  $-  $27,560 
Met coal  14,261   -   -   -   14,261 
Other revenue  50   368   1   26   445 
Total $25,057  $6,569  $10,614  $26  $42,266 

The following table disaggregates revenue by type for each reportable segment for the three months ended September 30, 2018:

 

 Central Appalachia Northern Appalachia Rhino Western Illinois Basin Other Total Consolidated  Central Appalachia Northern Appalachia Rhino Western Other Total Consolidated 
 (in thousands)  (in thousands) 
Coal sales                                            
Steam coal $11,662  $3,687  $8,061  $11,611  $-  $35,021  $13,979  $5,229  $10,254  $-  $29,462 
Met coal  19,251   -   -   -   -   19,251   29,875   -   -   -   29,875 
Other revenue  62   457   9   -   -   528   36   602   -   62   700 
Total $30,975  $4,144  $8,070  $11,611  $-  $54,800  $43,890  $5,831  $10,254  $62  $60,037 

The following table disaggregates revenue by type for each reportable segment for the nine months ended September 30, 2019:

  Central Appalachia  Northern Appalachia  Rhino Western  Other  Total Consolidated 
  (in thousands) 
Coal sales                    
Steam coal $33,884  $20,662  $27,745  $-  $82,291 
Met coal  56,396   -   -   -   56,396 
Other revenue  406   1,382   1   27   1,816 
Total $90,686  $22,044  $27,746  $27  $140,503 

The following table disaggregates revenue by type for each reportable segment for the nine months ended September 30, 2018:

  Central Appalachia  Northern Appalachia  Rhino Western  Other  Total Consolidated 
  (in thousands) 
Coal sales                    
Steam coal $38,840  $12,821  $26,970  $-  $78,631 
Met coal  64,004   -   -   -   64,004 
Other revenue  154   1,576   10   165   1,905 
Total $102,998  $14,397  $26,980  $165  $144,540 

26

 

16.18. FAIR VALUE MEASUREMENTS

 

The Partnership 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 Partnership’s assumptions of what market participants would use.

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

 

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

 

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

 

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

 

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

 

The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership’s Financing Agreement was determined based upon a market approach and approximates the carrying value at March 31,September 30, 2019. The fair value of the Partnership’s Financing Agreement is a Level 2 measurement.

 

As of December 31, 2018, the Partnership had a recurring fair value measurement relating to its investment in Mammoth Inc. As discussed in Note 5, the Partnership sold the balance of its Mammoth Inc. shares (104,100 shares) during the first quarter of 2019. The Partnership’s shares of Mammoth Inc. were classified as an investment on the Partnership’s unaudited condensed consolidated statements of financial position as of December 31, 2018. Based on the availability of a quoted price, the recurring fair value measurement of the Mammoth Inc. shares was a Level 1 measurement.

 

17.19. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

 

Cash payments for interest were $1.1$3.3 million and $1.4$4.9 million for the threenine months ended March 31,September 30, 2019 and 2018, respectively.

 

The unaudited condensed consolidated statement of cash flows for the threenine months ended March 31,September 30, 2019 and 2018 excludes approximately $1.4$3.1 million and $2.8$1.1 million, respectively, of property, plant and equipment additions which are recorded in Accounts payable.

 

18.20. SEGMENT INFORMATION

 

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

 

As of March 31,September 30, 2019, the Partnership has fourhad three reportable business segments: Central Appalachia, Northern Appalachia and Rhino Western and Illinois Basin.Western. Additionally, the Partnership has an Other category that includes its ancillary businesses.

 

The Partnership has not provided disclosure of total expenditures by segment for long-lived assets, as the Partnership does not maintain discrete financial information concerning segment expenditures for long lived assets, and accordingly such information is not provided to the Partnership’s chief operating decision maker. The information provided in the following tables represents the primary measures used to assess segment performance by the Partnership’s chief operating decision maker.

Reportable segment results of operations for the three months ended March 31,September 30, 2019 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

 

 Central Appalachia Northern Appalachia Rhino Western Illinois Basin Other Total Consolidated  Central Appalachia Northern Appalachia Rhino Western Other Total Consolidated 
 (in thousands)  (in thousands) 
Total revenues $30,407  $6,619  $8,711  $13,000  $-  $58,737  $25,057  $6,569  $10,614  $26  $42,266 
DD&A  1,901   408   1,094   2,058   88   5,549   1,992   438   1,062   33   3,525 
Interest expense  -   -   -   -   1,701   1,701   -   -   -   1,872   1,872 
Net Income/(loss) $1,183  $(1,123) $(327) $(3,587) $(3,425) $(7,279)
Net (loss)/income $(1,226) $(2,157) $1,501  $(6,462) $(8,344)

 

Reportable segment results of operations for the three months ended March 31,September 30, 2018 are as followsfollows:

 

 Central Appalachia Northern Appalachia Rhino Western Illinois Basin Other Total Consolidated  Central Appalachia Northern Appalachia Rhino Western Other Total Consolidated 
 (in thousands)  (in thousands) 
Total revenues $30,975  $4,144  $8,070  $11,611  $-  $54,800  $43,890  $5,831  $10,254  $62  $60,037 
DD&A  2,196   140   1,061   1,939   91   5,427   2,200   385   978   92   3,655 
Interest expense  -   -   -   -   1,885   1,885   -   -   -   2,831   2,831 
Net Income/(loss) $930  $(1,117) $963  $(2,329) $(1,268) $(2,821)
Net income/(loss) $3,619  $(881) $56  $(4,070) $(1,276)

 

19. SUBSEQUENT EVENTSReportable segment results of operations for the nine months ended September 30, 2019 are as follows:

 

  Central Appalachia  Northern Appalachia  Rhino Western  Other  Total Consolidated 
  (in thousands) 
Total revenues $90,686  $22,044  $27,746  $27  $140,503 
DD&A  5,756   1,280   3,265   210   10,511 
Interest expense  -   -   -   5,308   5,308 
Net income/(loss) $6,517  $(3,971) $2,494  $(14,252) $(9,212)

On May 8, 2019, the Partnership entered into a consent with its Lenders related to the Financing Agreement. The consent includes the lenders agreement to waive any Event

Reportable segment results of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratiooperations for the sixnine months ended March 31, 2019.September 30, 2018 are as follows:

  Central Appalachia  Northern Appalachia  Rhino Western  Other  Total Consolidated 
  (in thousands) 
Total revenues $102,998  $14,397  $26,980  $165  $144,540 
DD&A  6,659   825   3,080   277   10,841 
Interest expense  1   -   -   6,628   6,629 
Net income/(loss) $5,546  $(3,473) $956  $(5,998) $(2,969)

 

2328
 

 

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 Rhino Resource Partners LP and its subsidiaries. References to “our 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 our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q as well as the audited consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2018 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 addition, this discussion includes forward looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. Please read the section “Cautionary Note Regarding Forward Looking Statements”. In addition, factors that could cause actual results to differ include those risks and uncertainties discussed in Part I, Item 1A. “Risk Factors” also included in our Annual Report on Form 10-K for the year ended December 31, 2018.

 

Overview

 

Through a series of transactions completed in the first quarter of 2016, Royal Energy Resources, Inc. (“Royal”) acquired a majority ownership and control of us and 100% ownership of our general partner.

 

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

 

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2018, we controlled an estimated 268.5 million tons of proven and probable coal reserves, consisting of an estimated 214.0 million tons of steam coal and an estimated 54.5 million tons of metallurgical coal. In addition, as of December 31, 2018, we controlled an estimated 164.1 million tons of non-reserve coal deposits.

 

We operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. We also acquired three underground mines in Virginia, which we are in the process of refurbishing before we resume mining operations. We plan to resume mining operations at one of the mines in the fourth quarter of 2019 (see Blackjewel discussion below). The number of mines that we operate may vary from time to time depending on a number of factors, including the 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 order to resume, and, over time, increase our quarterly cash distributions. In addition, we continue to seek opportunities to expand and diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets. We believe that such assets will allow us to grow our cash available for distribution and enhance stability of our cash flow.

 

For the three and nine months ended March 31,September 30, 2019, we generated revenues from continuing operations of approximately $58.7$42.3 million and a$140.5 million, respectively, and we generated net losslosses from continuing operations of approximately $7.3 million.$8.3 million and $9.2 million for the three and nine months ended September 30, 2019, respectively. For the three months ended March 31,September 30, 2019, we produced approximately 1.20.8 million tons of coal from continuing operations and sold approximately 1.10.7 million tons of coal from continuing operations, of which approximately 82%85% were sold pursuant to supply contracts. For the nine months ended September 30, 2019, we produced approximately 2.5 million tons of coal from continuing operations and sold approximately 2.3 million tons of coal from continuing operations, of which approximately 87% were sold pursuant to supply contracts.

29

Current Liquidity and Outlook

 

As of March 31,September 30, 2019, our available liquidity was $4.2$8.0 million. We also have a delayed draw term loan commitment in the amount of $35$25 million contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreementour financing agreement discussed below.

 

On December 27, 2017, we entered into a financing agreement (“Financing Agreement”), which provides us with a multi-draw loan in the original aggregate principal amount of $80 million. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement and ana $40 million additional $35 million commitment that iswas contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. As of September 30, 2019, we have utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. We used approximately $17.3 million of the initial Financing Agreement net proceeds thereof to repay all amounts outstanding and terminate the amended and restated credit agreement with PNC Bank, National Association, as Administrative Agent. The Financing Agreement terminates oninitially had a termination date of December 27, 2020.2020, which was amended to December 27, 2022 per the fifth amendment to the Financing Agreement discussed further below. For more information about our Financing Agreement, please read “— Liquidity and Capital Resources—Financing Agreement.”

Beginning in the later part of the third quarter of 2019, we have experienced weak market demand and have seen prices move lower for the qualities of met and steam coal we produce. If we continue to experience weak demand and prices continue to lower for our met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our Financing Agreement. If we violate any of the covenants or restrictions in our Financing Agreement, including the fixed-charge coverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders may not be willing to make any loans under the additional commitment available under our Financing Agreement. 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 under our Financing Agreement. Although we believe our lenders are well secured under the terms of our Financing 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 spending and 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.

 

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

 

Recent Developments

 

FinancingPennyrile Mine Complex (“Pennyrile”) Asset Purchase Agreement

On September 6, 2019, we entered into an Asset Purchase Agreement (the “Pennyrile APA”) with Alliance Coal, LLC (“Buyer”) and Alliance Resource Partners, L.P. (“Buyer Parent”) pursuant to which we sold to Buyer all of the real property, permits, equipment and inventory and certain other assets associated with Pennyrile in exchange for approximately $3.7 million, subject to certain adjustments.

Pursuant to the Pennyrile APA, we retain liability for certain employee claims, subsidence claims arising from pre-closing mining operations, MSHA liabilities and certain other matters. The Pennyrile APA also provides that Buyer shall have the right to conduct diligence on the Pennyrile and may contest the fair market value of the purchased assets or the estimate of the costs of the assumed liabilities following such diligence investigation. In the event Buyer does contest such amounts, the parties will attempt to resolve the dispute and to the extent they cannot, will submit the matter to a third party to make a final determination with respect to such matters, and will adjust the purchase price accordingly.

The parties have made customary representations, warranties and covenants in the Pennyrile APA. The closing of the transactions contemplated by the Asset Purchase Agreement are subject to a number of closing conditions, including, among others, the performance of applicable covenants and accuracy of representations and warranties and absence of material adverse changes in the condition of Pennyrile. Subject to the satisfaction of closing conditions, the transaction contemplated by the Pennyrile APA is expected to close in the fourth quarter of 2019.

Coal Supply Asset Purchase Agreement

On September 6, 2019, we entered into an Asset Purchase Agreement with the Buyer and Buyer Parent for the sale and assignment of certain coal supply agreements associated with Pennyrile (the “Coal Supply APA”) in exchange for approximately $7.3 million. The Coal Supply APA includes customary representations of the parties thereto and indemnification for losses arising from the breaches of such representations and for liabilities arising during the period in which the relevant parties were not party to the coal supply agreements. The transactions contemplated by the Coal Supply APA closed upon the execution thereof.

Discontinued Operations

The Pennyrile operating results for the three and nine months ended September 30, 2019 and 2018 are recorded as discontinued operations, including a $38.6 million impairment loss associated with the sale.

Blackjewel Assignment Agreement

 

On August 14, 2019, our wholly owned subsidiary Jewell Valley Mining LLC, entered into a general assignment and assumption agreement and bill of sale (the “Assignment Agreement”) with Blackjewel L.L.C., Blackjewel Holdings L.L.C., Revelation Energy Holdings, LLC, Revelation Management Corp., Revelation Energy, LLC, Dominion Coal Corporation, Harold Keene Coal Co. LLC, Vansant Coal Corporation, Lone Mountain Processing LLC, Powell Mountain Energy, LLC, and Cumberland River Coal LLC (together, “Blackjewel”) to purchase certain assets from Blackjewel for cash consideration of $850,000 plus an additional royalty of $250,000 that is payable within one year from the date of the purchase, as well as the assumption of associated reclamation obligations. The assets that are subject of the Assignment Agreement consist of three underground mines in Virginia that were actively producing coal prior to Blackjewel’s filing for relief under Chapter 11 of the United States Bankruptcy Code, along with a preparation plant, rail loadout facility, related mineral and surface rights and infrastructure and certain purchase contracts to be assumed at our option. We are in the process of hiring employees and refurbishing the assets before we resume mining operations. We plan to resume mining operations at one of the mines in the fourth quarter of 2019.

Financing Agreement

On September 6, 2019, we entered into a fifth amendment (the “Fifth Amendment”) to the Financing Agreement originally executed on December 27, 2017 with Cortland Capital Market Services LLC, as Collateral Agent and Administrative Agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein (the “Lenders”). The Fifth Amendment (i) extends the maturity of the Financing Agreement to December 27, 2022, (ii) provides a $5.0 million term loan provided by the Lenders to us under the delayed draw feature of the Financing Agreement, (iii) extends the period by which an applicable premium payable to the Lenders will be calculated to December 31, 2021, (iv) modifies the certain definitions and concepts to account for our recent acquisition of properties from Blackjewel, (v) permits the disposition of the Pennyrile Mining Complex and (viii) provides for the payment of additional fees to the Lenders, including a consent fee of $1.0 million, an amendment fee of $825,000 and an increase in the lender exit fee of 1.00% to a total exit fee of 7.0% of the amount of term loans made under the Financing Agreement that is payable at the maturity of the Financing Agreement.

On August 16, 2019, we entered into a fourth amendment (the “Fourth Amendment”) to the Financing Agreement originally executed on December 27, 2017 with the Lenders. The Fourth Amendment provides a $5.0 million term loan provided by the Lenders to us under the delayed draw feature of the Financing Agreement, and extends the period by which an applicable premium payable to the Lenders will be calculated to the final maturity date.

On May 8, 2019, we entered into a consent with our lenders relatedthird amendment (“Third Amendment”) to the Financing Agreement. The consentThird Amendment includes the lenders agreement to waive any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended March 31, 2019. The Third Amendment increased the original exit fee of 3.0% to 6.0%. The original exit fee of 3% was included in the Financing Agreement at the execution date and the increase of the total exit fee to 6% was included as part of the amendment dated February 13, 2019 discussed below and this ThirdAmendment. The exit fee is applied to the principal amount of the loans made under the Financing Agreement that is payable on the earliest of (a) the final maturity date, (b) the termination date of the Financing agreement for any reason, (c) the acceleration of the obligations in the Financing Agreement for any reason and (d) the date of any refinancing of the term loan under the Financing Agreement.

 

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

 

Settlement Agreement

On June 28, 2019, we entered into a settlement agreement with a third party which allows the third party to maintain certain pipelines pursuant to designated permits at our Central Appalachia operations. The agreement requires the third party to pay us $7.0 million in consideration. We received $4.2 million on July 3, 2019 with the balance of $2.8 million due on or before February 29, 2020. We recorded a gain of $6.9 million during the second quarter of 2019 related to this settlement agreement.

Distribution Suspension

 

Pursuant to the PartnershipPartnership’s limited partnership agreement, our common units accrue arrearages every quarter when the distribution level is below the minimum level of $4.45 per unit. Beginning with the quarter ended June 30, 2015 and continuing through the quarter ended March 31,September 30, 2019, we have suspended the cash distribution on our common units. For each of the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015, we announced cash distributions per common unit at levels lower than the minimum quarterly distribution. We have not paid any distribution on our subordinated units for any quarter after the quarter ended March 31, 2012. As of March 31,September 30, 2019, we had accumulated arrearages of $731.6$848.7 million.

Factors That Impact Our Business

 

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

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

 

We have historically sold a majority of our coal through long-term supply contracts, although we have starting selling a larger percentage of our coal under short-term and spot agreements. As of March 31,September 30, 2019, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

 

Year Tons (in thousands) Number of customers  Tons (in thousands) Number of customers
2019 Q2-Q4  3,360   19 
2019 Q4 762 13
2020  1,880   7  838 3
2021  852   3  120 1

 

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

 

Results of Operations

 

Segment Information

 

As of March 31,September 30, 2019, we have fourhad three reportable business segments: Central Appalachia, Northern Appalachia and Rhino Western and Illinois Basin.Western. Additionally, we have an Other category that includes our ancillary businesses. Our Central Appalachia segment consists of two mining complexes: Tug River and Rob Fork, which, as of March 31,September 30, 2019, together included one underground mine, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. The new Virginia assets as discussed above include three underground mines, a preparation plant and loadout facility. These mines and facilities were not active as of September 30, 2019 as we are still refurbishing the assets before we resume mining operations at these locations. We plan to resume mining operations at one of the mines in the fourth quarter of 2019. The operating results for Jewell Valley Mining LLC will be reported as part of the Central Appalachia business segment. Our Northern Appalachia segment consists of the Hopedale 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 March 31,September 30, 2019. Our Rhino Western segment includes one underground mine in the Western Bituminous region at our Castle Valley mining complex in Utah. OurDue to the Pennyrile disposal discussed earlier, our results from the previous Illinois Basin segment includes one underground mine, preparation plantbusiness have been reclassified to discontinued operations for the current and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our Taylorville field reserves located in central Illinois. Our Other category is comprised of our ancillary businesses.prior periods presented.

 

Evaluating Our Results of Operations

 

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

 

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

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

 

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

 

Summary. (Unless otherwise specified, the following discussion of the results of operations for the three months ended September 30, 2019 and 2018 exclude operating results relating to Pennyrile. The Pennyrile operating results are recorded as discontinued operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.)

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the three months ended March 31,September 30, 2019 and 2018:

 

 Three months ended Three months ended Increase/(Decrease)  Three months ended Three months ended Increase/(Decrease) 
 March 31, 2019 March 31, 2018 $ % *  September 30, 2019 September 30, 2018 $ % * 
 (in millions, except per ton data and %)  (in millions, except per ton data and %) 
Statement of Operations Data:                       
                         
Coal revenues $57.9  $54.3  $3.6   6.6% $41.8  $59.3  $(17.5)  (29.5)%
Other revenues  0.8   0.5   0.3   65.8%  0.4   0.7   (0.3)  (36.4)%
Total revenues  58.7   54.8   3.9   7.2%  42.2   60.0   (17.8)  (29.6)%
Costs and expenses:                                
Cost of operations (exclusive of DD&A shown separately below)  54.6   49.7   4.9   10.1%  38.4   47.1   (8.7)  (18.4)%
Freight and handling costs  1.2   0.9   0.3   27.8%  1.4   5.8   (4.4)  (76.5)%
Depreciation, depletion and amortization  5.5   5.4   0.1   2.3%  3.5   3.6   (0.1)  (3.6)%
Selling, general and administrative (exclusive of DD&A shown separately above)  2.8   2.7   0.1   1.7%  5.4   2.7   2.7   101.4%
Loss/(gain) on sale/disposal of assets  0.2   (2.9)  3.1   (107.6%)
(Loss) from operations  (5.6)  (1.0)  (4.6)  491.6%
Loss/(Gain) on sale/disposal of assets  -   (0.8)  0.8   (101.2)%
(Loss)/Income from operations  (6.5)  1.6   (8.1)  (516.7)%
Interest expense and other  1.7   1.9   (0.2)  (9.7%)  (1.9)  (2.8)  0.9   (33.9)%
Interest income and other  -   (0.1)  0.1   (99.6%)  -   -   -   n/a 
Total interest and other (income) expense  1.7   1.8   (0.1)  (9.4%)  (1.9)  (2.8)  0.9   (34.1)%
Net (loss) from continuing operations  (8.4)  (1.2)  (7.2)  554.0%
Net (loss) from discontinued operations  (43.3)  (3.3)  (40.0)  n/a 
Net (loss) $(7.3) $(2.8)  (4.5)  158.0% $(51.7) $(4.5)  (47.2)  n/a 
                                
Total tons sold  1,077.2   1,072.6   4.6   0.4%
Total tons sold (in thousands except %)  738.7   935.8   (197.1)  (21.1)%
Coal revenues per ton $53.71  $50.60  $3.11   6.2% $56.61  $63.41  $(6.80)  (10.7)%
Cost of operations per ton $50.73  $46.29  $4.44   9.6% $51.97  $50.29  $1.68   3.3%
                                
Other Financial Data                                
Adjusted EBITDA from continuing operations $(2.9) $5.5  $(8.4)  (153.2)%
Adjusted EBITDA from discontinued operations $(2.9) $(1.3) $(1.6)  128.8%
Adjusted EBITDA $0.6  $4.5  $(3.9)  (85.3%) $(5.8) $4.2  $(10.0)  (238.6)%

 

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

2734
 

Three Months Ended March 31,September 30, 2019 Compared to Three Months Ended March 31,September 30, 2018

 

Revenues.Our coal revenues for the three months ended March 31,September 30, 2019 increaseddecreased by approximately $3.6$17.5 million, or 6.6%29.5%, to approximately $57.9$41.8 million from approximately $54.3$59.3 million for the three months ended March 31,September 30, 2018. The increase in coal revenues was primarily due to an increase in tons sold from our Northern Appalachia operations as demand for steam coal increased in this region. Coal revenues per ton was $53.71$56.61 for the three months ended March 31,September 30, 2019, an increasea decrease of $3.11$6.80 or 6.2%10.7%, from $50.60$63.41 per ton for the three months ended March 31,September 30, 2018. This increaseThe decrease in coal revenues and coal revenues per ton was primarily the result of higher contractfewer tons sold and lower contracted sale prices for coal sold across all offrom our locationsCentral Appalachia operations during the firstthird quarter of 2019 compared to the same period in 2018.

 

Cost of Operations. Total cost of operations increaseddecreased by $4.9$8.7 million or 10.1%18.4% to $54.6$38.4 million for the three months ended March 31,September 30, 2019 as compared to $49.7$47.1 million for the three months ended March 31,September 30, 2018. Our cost of operations per ton was $50.73$51.97 for the three months ended March 31,September 30, 2019, an increase of $4.44,$1.68, or 9.6%3.3%, from the three months ended March 31,September 30, 2018. The increasedecrease in total cost of operations and cost of operations per ton was primarily due to increases in costs at several offewer tons produced and sold from our Central Appalachia operations for labor, contract services and roof support induring the firstthird quarter of 2019 compared to the same period in 2018.

 

Freight and Handling.Total freight and handling cost increaseddecreased to $1.2$1.4 million for the three months ended March 31,September 30, 2019 from approximately $0.9$5.8 million for the three months ended March 31,September 30, 2018. The increasedecrease in freight and handling costs was primarily the result of a newfewer export sales contract for coal shipped from our Northern Appalachia operation that requiresrequire us to pay the freight and handlingrailroad transportation to the customer’s destination.port of export during the third quarter of 2019. We also incurred $0.9 million in demurrage charges during the three months ended September 30, 2018.

 

Depreciation, Depletion and Amortization (“DD&A”). Total DD&A expense for the three months ended March 31,September 30, 2019 was $5.5$3.5 million as compared to $5.4$3.6 million for the three months ended March 31,September 30, 2018.

 

For the three months ended March 31,June 30, 2019, our depreciation expense remained relatively flat at approximately $4.2was $2.5 million compared to $4.1 millionand for the three months ended March 31, 2018.September 30, 2019 it was $2.6 million.

 

For the three months ended March 31,September 30, 2019 and 2018, our depletion expense remained relatively flat at approximately $0.4 million.

 

For the three months ended March 31,September 30, 2019 and 2018 our amortization expense remained relatively flat at approximately $0.9$0.6 million.

 

Selling, General and Administrative. SG&A expense for the three months ended March 31,September 30, 2019 increased slightly to $2.8$5.4 million as compared to $2.7 million for the three months ended March 31, 2018.September 30, 2018 as we experienced an increase in corporate overhead expense. SG&A was also impacted by a $2.0 million expense recorded as the result of an agreement reached with a third-party to assume the surety bonds associated with Sands Hill Mining LLC that had not been transferred from our bond portfolio by the purchaser of Sands Hill Mining LLC as required by the sale agreement executed with the purchaser in November 2017.

 

Interest Expense.Interest expense for the three months ended March 31,September 30, 2019 decreased to $1.7$1.9 million as compared to $1.9$2.8 million for the three months ended March 31,September 30, 2018. This decrease was primarily due to a lower average outstanding debt balance forduring the three months ended March 31,September 30, 2019 compared to the same period in 2018.

 

Net Income/Loss. Net loss was $7.3$8.4 million for the three months ended March 31,September 30, 2019 compared to net loss of $2.8$1.2 million for the three months ended March 31,September 30, 2018. The increase in net loss incurred during the three months ended March 31, 2019 was primarily due to an increasethe decrease in cost of operationscoal revenue as discussed above and the net loss for the three months ended March 31, 2018 was positively impacted from a gain on sale of assets of $2.9 million.above.

 

35

Adjusted EBITDA. Adjusted EBITDA from continuing operations decreased by $3.9$8.4 million for the three months ended March 31,September 30, 2019 to $0.6($2.9) million from $4.5$5.5 million for the three months ended March 31,September 30, 2018. Adjusted EBITDAThe decrease was primarily due to the decrease in net income for the three months ended March 31, 2019 was negatively impacted by the increasedSeptember 30, 2019. Including net loss as discussed above.from discontinued operations of approximately $43.3 million, which related to the assets sold at our Pennyrile operation in September 2019, our net loss was $51.7 million and Adjusted EBITDA was ($5.8) million for the three months ended March 31, 2018September 30, 2019. Including net loss from discontinued operations of approximately $3.3 million, which relates to Pennyrile, our net loss was positively impacted by$4.5 million and Adjusted EBITDA was $4.2 million for the $2.9 million gain on sale of assets.three months ended September 30, 2018. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA to net income/(loss) on a segment basis.

28

Segment Results

 

The following tables set forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data by reportable segment for the three months ended March 31,September 30, 2019 and 2018:

 

Central Appalachia Three months ended  Three months ended  Increase/(Decrease) 
  March 31, 2019  March 31, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $30.1  $30.9  $(0.8)  (2.7%)
Freight and handling revenues  -   -   -   n/a 
Other revenues  0.3   0.1   0.2   422.3%
Total revenues  30.4   31.0   (0.6)  (1.8%)
Coal revenues per ton $77.29  $67.43  $9.86   14.6%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  26.6   26.9   (0.3)  (1.0%)
Freight and handling costs  0.7   0.9   (0.2)  (25.0%)
Depreciation, depletion and amortization  1.9   2.2   (0.3)  (13.4%)
Selling, general and administrative costs  0.1   0.1   -   (23.2%)
Cost of operations per ton $68.37  $58.67  $9.70   16.5%
Net income  1.2   0.9   0.3   27.2%
Adjusted EBITDA  3.1   3.1   -   (1.4%)
Tons sold  389.3   458.4   (69.1)  (15.1%)

Central Appalachia

  Three months ended  Three months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $25.0  $43.9  $(18.9)  (43.0)%
Freight and handling revenues  -   -   -   n/a 
Other revenues  0.1   -   0.1   n/a 
Total revenues  25.1   43.9   (18.8)  (42.9)%
Coal revenues per ton $74.12  $83.59  $(9.47)  (11.3)%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  23.0   31.9   (8.9)  (27.7)%
Freight and handling costs  1.2   5.8   (4.5)  (79.5)%
Depreciation, depletion and amortization  2.0   2.2   (0.2)  (9.5)%
Selling, general and administrative costs  0.1   0.4   (0.3)  (87.0)%
Cost of operations per ton $68.25  $60.75  $7.50   12.4%
Net (loss)/income from continuing operations  (1.2)  3.6   (4.8)  (133.9)%
Adjusted EBITDA from continuing operations  0.8   6.1   (5.3)  (87.5)%
Tons sold (in thousands except %)  337.4   524.6   (187.2)  (35.7)%

 

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

 

Tons of coal sold in our Central Appalachia segment decreased by approximately 15.1% to approximately 0.4 million tons35.7% for the three months ended March 31,September 30, 2019 compared to the three months ended March 31,September 30, 2018 as we encountered adverse geological conditions duringprimarily due to the first quarter of 2019 thatsoftening in the met and steam coal markets, which has resulted in fewer tons being produced for sale. Tonssome of coal sold also decreased asour customers delayedpushing out shipments to a future periods duringdate. We also had some uncontracted tons in Central Appalachia and were unable to sell the three months ended March 31, 2019.coal on the spot market due to weak market demand.

 

Coal revenues decreased by approximately $0.8$18.9 million, or 2.7%43.0%, to approximately $30.1$25.0 million for the three months ended March 31,September 30, 2019 from approximately $30.9$43.9 million for the three months ended March 31,September 30, 2018. This decrease was primarily due to the decrease in tons sold discussed above, partially offset by higher contracted prices for tons sold during the three months ended March 31, 2019. Coal revenues per ton for our Central Appalachia segment increaseddecreased by $9.86,$9.47, or 14.6%11.3%, to $77.29$74.12 per ton for the three months ended March 31,September 30, 2019 as compared to $67.43$83.59 for the three months ended March 31,September 30, 2018. This increaseThe decrease in coal revenues was due to fewer met and steam coal tons sold during the third quarter of 2019 compared to 2018. The decrease in coal revenues per ton was primarily due to a decrease in the increase in contract sale pricesprice for met and steam coal from this region.tons sold during the three months ended September 30, 2019 compared to 2018.

 

Cost of operations decreased slightly by $0.3$8.9 million, or 1.0%27.7%, to $26.6$23.0 million for the three months ended March 31,September 30, 2019 from $26.9$31.9 million for the three months ended March 31,September 30, 2018. Our cost of operations per ton of $68.37$68.25 for the three months ended March 31,September 30, 2019 increased 16.5%12.4% compared to $58.67$60.75 per ton for the three months ended March 31,September 30, 2018. The decrease in cost of operations was primarily due to fewer tons produced and sold during the third quarter of 2019 compared to the same period in 2018. Cost of operations per ton increased as we sold fewer tons as discussed above and we experienced an increasewere sold from our Central Appalachia operations resulting in labor, diesel fuel, contract services and roof supportfixed costs being allocated to fewer tons sold during the three months ended March 31, 2019.current period.

 

Total freight and handling cost decreased to $0.7was $1.2 million for the three months ended March 31,September 30, 2019, from approximately $0.9which was a decrease of $4.5 million forfrom the three months ended March 31,September 30, 2018. The decrease in freight and handling costs was primarily the result of lower rail transportation costs at our Central Appalachia operations during the current period as we executed fewer export coal sales that require us to pay for railroad transportation to the port of export.export during the third quarter of 2019. We also incurred $0.9 million in demurrage charges during the three months ended September 30, 2018.

For our Central Appalachia segment, net incomeloss was approximately $1.2 million for the three months ended March 31,September 30, 2019 an increase of $0.3 million as compared to the three months ended March 31, 2018. Netnet income of $3.6 million for the three months ended March 31, 2019 increased versusSeptember 30, 2018. The decrease in net income was primarily the prior period due to lower freight and handling costsresult of the decrease in revenue resulting from fewer sales and lower DD&A expense.contracted sale prices during the third quarter of 2019 compared to the same period in 2018.

 

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 for the three months ended March 31,September 30, 2019 and 2018, is presented below. Note that our Northern Appalachia and Rhino Western and Illinois Basin segments currently produce and sell only steam coal.

(In thousands, except per ton data and %) 

Three months ended

March 31, 2019

  

Three months ended

March 31, 2018

  

Increase

(Decrease) %*

 
Met coal tons sold  149.1   212.5   (29.8%)
Steam coal tons sold  240.2   245.9   (2.3%)
Total tons sold  389.3   458.4   (15.1%)
             
Met coal revenue $16,698  $19,251   (13.3%)
Steam coal revenue $13,389  $11,662   14.8%
Total coal revenue $30,087  $30,913   (2.7%)
             
Met coal revenues per ton $111.98  $90.58   23.6%
Steam coal revenues per ton $55.75  $47.43   17.5%
Total coal revenues per ton $77.29  $67.43   14.6%
             
Met coal tons produced  122.5   126.5   (3.2%)
Steam coal tons produced  308.8   280.9   10.0%
Total tons produced  431.3   407.4   5.9%

 

Northern Appalachia Three months ended  Three months ended  Increase/(Decrease) 
  March 31, 2019  March 31, 2018  $  % * 
  (in millions, except per ton data and %) 
Coal revenues $6.1  $3.7  $2.4   64.5%
Freight and handling revenues  -   -   -   n/a 
Other revenues  0.5   0.4   0.1   21.1%
Total revenues  6.6   4.1   2.5   59.7%
Coal revenues per ton $50.19  $41.14  $9.05   22.0%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  6.8   5.1   1.7   33.4%
Freight and handling costs  0.5   -   0.5   n/a 
Depreciation, depletion and amortization  0.4   0.1   0.3   190.6%
Selling, general and administrative costs  -   -   -   n/a 
Cost of operations per ton $56.60  $57.21  $(0.61)  (1.1%)
Net loss  (1.1)  (1.1)  -   0.5%
Adjusted EBITDA  (0.7)  (1.0)  0.3   (27.8%)
Tons sold  120.8   89.6   31.2   34.9%
(In thousands, except per ton data and %) 

Three months ended

September 30, 2019

  

Three months ended

September 30, 2018

  Increase
(Decrease) %*		 
Met coal tons sold  147.4   264.0   (44.2)%
Steam coal tons sold  190.0   260.6   (27.1)%
Total tons sold  337.4   524.6   (35.7)%
             
Met coal revenue $14,261  $29,875   (52.3)%
Steam coal revenue $10,746  $13,979   (23.1)%
Total coal revenue $25,007  $43,854   (43.0)%
             
Met coal revenues per ton $96.75  $113.17   (14.5)%
Steam coal revenues per ton $56.56  $53.64   5.5%
Total coal revenues per ton $74.12  $83.59   (11.3)%
             
Met coal tons produced  177.0   141.7   24.9%
Steam coal tons produced  265.8   302.7   (12.2)%
Total tons produced  442.8   444.4   (0.4)%

 

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

30

For our Northern Appalachia segment, tons of coal sold increased by approximately 34.9% for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 as we experienced increased demand for coal from this region.

 

Coal revenues were approximately $6.1 million for the three months ended March 31, 2019, an increase of approximately $2.4 million, or 64.5%, from approximately $3.7 million for the three months ended March 31, 2018. Coal revenues per ton were $50.19 for the three months ended March 31, 2019 as compared to $41.14 for the three months ended March 31, 2018, which was primarily due to higher contracted prices for tons sold from our Hopedale complex compared to the same period in 2018.Northern Appalachia

 

Cost of operations increased by $1.7 million, or 33.4%, to $6.8 million for the three months ended March 31, 2019 from $5.1 million for the three months ended March 31, 2018. Our cost of operations per ton was $56.60 for the three months ended March 31, 2019, a decrease of $0.61, or 1.1%, compared to $57.21 for the three months ended March 31, 2018. The increase in total cost of operations was primarily the result of increased production and sales from this region. The cost of operations per ton decreased in Northern Appalachia as more tons were sold from this region resulting in fixed costs being allocated to higher tons during the three months ended March 31, 2019.

Net loss remained relatively flat in our Northern Appalachia segment at $1.1 million for the three months ended March 31, 2019 and 2018.

Rhino Western Three months ended  Three months ended  Increase/(Decrease) 
  March 31, 2019  March 31, 2018  $  % * 
  (in millions, except per ton data and %) 
Coal revenues $8.7  $8.1  $0.6   8.1%
Freight and handling revenues  -   -   -   n/a 
Other revenues  -   -   -   n/a 
Total revenues  8.7   8.1   0.6   7.9%
Coal revenues per ton $36.61  $35.95  $0.66   1.9%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  7.2   6.0   1.2   19.8%
Freight and handling costs  -   -   -   n/a 
Depreciation, depletion and amortization  1.1   1.1   -   3.2%
Selling, general and administrative costs  -   -   -   18.2%
Cost of operations per ton $30.35  $26.87  $3.48   12.9%
Net (loss)/income  (0.3)  0.9   (1.2)  (134.0%)
Adjusted EBITDA  1.5   2.0   (0.5)  (28.2%)
Tons sold  237.9   224.2   13.7   6.1%

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

31

Tons of coal sold from our Rhino Western segment increased by approximately 6.1% for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to an increase in demand for coal from this region.

Coal revenues increased by approximately $0.6 million, or 8.1%, to approximately $8.7 million for the three months ended March 31, 2019 from approximately $8.1 million for the three months ended March 31, 2018 primarily due to an increase in demand for tons sold from the Castle Valley mine. Coal revenues per ton for our Rhino Western segment increased by $0.66 or 1.9% to $36.61 per ton for the three months ended March 31, 2019 as compared to $35.95 per ton for the three months ended March 31, 2018 due to higher contracted sale prices.

Cost of operations increased by $1.2 million, or 19.8%, to $7.2 million for the three months ended March 31, 2019 from $6.0 million for the three months ended March 31, 2018. Our cost of operations per ton was $30.35 for the three months ended March 31, 2019, an increase of $3.48, or 12.9%, compared to $26.87 for the three months ended March 31, 2018. Total cost of operations and cost of operations per ton increased for the three months ended March 31, 2019 compared to the same period in 2018 due to increased production and sales and an increase in operating expenses at our coal mining operation at Castle Valley.

Net loss in our Rhino Western segment was $0.3 million for the three months ended March 31, 2019, compared to net income of $0.9 million for the three months ended March 31, 2018. This decrease in net income was primarily the result of higher operating costs at our Castle Valley operation.

Illinois Basin Three months ended Three months ended Increase/(Decrease) 
 Three months ended Three months ended Increase/(Decrease) 
 September 30, 2019 September 30, 2018 $ % * 
 March 31, 2019 March 31, 2018 $ % *  (in millions, except per ton data and %) 
 (in millions, except per ton data and %)          
Coal revenues $13.0  $11.6  $1.4   12.0% $6.2  $5.2  $1.0   18.6%
Freight and handling revenues  -   -   -   n/a   -   -   -   n/a 
Other revenues  -   -   -   n/a   0.3   0.7   (0.4)  (38.8)%
Total revenues  13.0   11.6   1.4   12.0%  6.5   5.9   0.6   12.6%
Coal revenues per ton $39.49  $38.67  $0.82   2.1% $47.35  $44.05  $3.30   7.5%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  14.5   12.0   2.5   21.0%  8.1   6.3   1.8   28.0%
Freight and handling costs  -   -   -   n/a   0.2   -   0.2   n/a 
Depreciation, depletion and amortization  2.1   1.9   0.2   6.1%  0.4   0.4   -   13.9%
Selling, general and administrative costs  0.1   -   0.1   0.3%  -   -   -   n/a 
Cost of operations per ton $44.17  $40.01  $4.16   10.4% $61.88  $53.33  $8.55   16.0%
Net (loss)  (3.6)  (2.3)  (1.3)  54.0%
Adjusted EBITDA  (1.5)  (0.4)  (1.1)  291.9%
Tons sold  329.2   300.4   28.8   9.6%
Net(loss) from continuing operations  (2.1)  (0.8)  (1.3)  144.9%
Adjusted EBITDA from continuing operations  (1.7)  (0.5)  (1.2)  246.4%
Tons sold (in thousands except %)  130.9   118.7   12.2   10.3%

 

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

 

For our Illinois BasinNorthern Appalachia segment, tons of coal sold increased by approximately 9.6%10.3% for the three months ended March 31,September 30, 2019 compared to the three months ended March 31,September 30, 2018 as adverse weather conditions limited barge shipmentswe experienced increased demand for coal from our Pennyrile mine in the first quarter of 2018.this region.

 

Coal revenues ofwere approximately $13.0$6.2 million for the three months ended March 31,September 30, 2019, increased byan increase of approximately $1.4$1.0 million, or 12.0%18.6%, compared to $11.6from approximately $5.2 million for the three months ended March 31,September 30, 2018. Coal revenues per ton for our Illinois Basin segment were $39.49$47.35 for the three months ended March 31,September 30, 2019 an increase of $0.82, or 2.1%, from $38.67as compared to $44.05 for the three months ended March 31,September 30, 2018. The increase in coal revenues was due to increased tons sold and coal revenues per ton increasedwas primarily due to higher contracted prices forthe increase in tons of coal sold from our Pennyrile mineHopedale operation resulting from increased demand in western Kentucky.this region and higher contracted sale prices for the tons sold compared to the same period in 2018.

Cost of operations was $14.5increased by $1.8 million, whileor 28.0%, to $8.1 million for the three months ended September 30, 2019 from $6.3 million for the three months ended September 30, 2018. Our cost of operations per ton was $44.17$61.88 for the three months ended March 31,September 30, 2019, bothan increase of which related$8.55, or 16.0%, compared to our Pennyrile mining complex in western Kentucky. For$53.33 for the three months ended March 31, 2018, cost of operationsSeptember 30, 2018. The increase in our Illinois Basin segment was $12.0 million and cost of operations per ton was $40.01. The increases intotal cost of operations and cost of operations per ton werewas primarily due to additional expense incurred as we encountered some adverse geological conditions at our Hopedale operation during the resultthird quarter of increased production and sales and as well as increases in labor costs, maintenance costs and an increase in roof support costs as steel prices continue to increase.2019.

 

ForNet loss in our Illinois BasinNorthern Appalachia segment we generated a net loss of $3.6was $2.1 million for the three months ended March 31,September 30, 2019 compared to net loss of $2.3$0.8 million for the three months ended March 31,September 30, 2018. The increase in net loss was primarily the result ofdue to the increase in cost of operations during the current period as discussed above.

 

Other Three months ended  Three months ended  Increase/(Decrease) 
  March 31, 2019  March 31, 2018  $  % * 
  (in millions, except per ton data and %) 
Coal revenues  n/a   n/a   n/a   n/a 
Freight and handling revenues  n/a   n/a   n/a   n/a 
Other revenues $-  $-  $-   n/a 
Total revenues  -   -   -   n/a 
Coal revenues per ton**  n/a   n/a   n/a   n/a 
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  (0.5)  (0.3)  (0.2)  39.4%
Freight and handling costs  -   -   -   n/a 
Depreciation, depletion and amortization  -   0.1   (0.1)  (3.4%)
Selling, general and administrative costs  2.6   2.6   -   1.1%
Cost of operations per ton**  n/a   n/a   n/a   n/a 
Net (loss)  (3.5)  (1.2)  (2.3)  170.0%
Adjusted EBITDA  (1.8)  0.8   (2.6)  (331.5%)
Tons sold  n/a   n/a   n/a   n/a 
38

Rhino Western

 

  Three months ended  Three months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $10.6  $10.2  $0.4   3.5%
Freight and handling revenues  -   -   -   n/a 
Other revenues  -   -   -   n/a 
Total revenues  10.6   10.2   0.4   3.5%
Coal revenues per ton $39.26  $35.06  $4.20   12.0%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  8.0   9.2   (1.2)  (12.5)%
Freight and handling costs  -   -   -   n/a 
Depreciation, depletion and amortization  1.1   1.0   0.1   8.6%
Selling, general and administrative costs  -   0.1   -   (67.9)%
Cost of operations per ton $29.67  $31.35  $(1.68)  (5.4)%
Net income from continuing operations  1.5   -   1.5   n/a 
Adjusted EBITDA from continuing operations  2.6   1.0   1.6   149.8%
Tons sold (in thousands except %)  270.4   292.5   (22.1)  (7.6)%

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

Tons of coal sold from our Rhino Western segment decreased by approximately 7.6% for the three months ended September 30, 2019 compared to the same period in 2018 primarily due to a decrease in demand for coal from this region.

Coal revenues increased by approximately $0.4 million, or 3.5%, to approximately $10.6 million for the three months ended September 30, 2019 from approximately $10.2 million for the three months ended September 30, 2018. Coal revenues per ton for our Rhino Western segment increased by $4.20 or 12.0% to $39.26 per ton for the three months ended September 30, 2019 as compared to $35.06 per ton for the three months ended September 30, 2018. The increase in coal revenues and coal revenues per ton was primarily due to higher contracted sale prices.

Cost of operations decreased by $1.2 million, or 12.5%, to $8.0 million for the three months ended September 30, 2019 from $9.2 million for the three months ended September 30, 2018. Our cost of operations per ton was $29.67 for the three months ended September 30, 2019, a decrease of $1.68, or 5.4%, compared to $31.35 for the three months ended September 30, 2018. Total cost of operations decreased for the three months ended September 30, 2019 compared to the same period in 2018 due to a decrease in tons sold from our Castle Valley mine operation.

Net income in our Rhino Western segment was $1.5 million for the three months ended September 30, 2019, compared to zero net income for the three months ended September 30, 2018. This increase in net income was primarily the result of an increase in our contracted sale prices for tons sold at our Castle Valley operation and lower operating costs during the third quarter of 2019.

39

Other

  Three months ended  Three months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $-  $-   n/a   n/a 
Freight and handling revenues  -   -   n/a   n/a 
Other revenues  -   -   n/a   n/a 
Total revenues  -   -   n/a   n/a 
Coal revenues per ton**   n/a    n/a   n/a   n/a 
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  (0.7)  (0.3)  (0.4)  147.9%
Freight and handling costs  -   -   -   n/a 
Depreciation, depletion and amortization  -   0.1   (0.1)  (64.3)%
Selling, general and administrative costs  5.3   2.3   3.0   132.3%
Cost of operations per ton**   n/a    n/a    n/a   n/a 
Net (loss) from continuing operations  (6.6)  (4.0)  (2.6)  58.8%
Adjusted EBITDA from continuing operations  (4.6)  (1.1)  (3.5)  297.2%
Tons sold (in thousands except %)   n/a    n/a    n/a   n/a 

*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 do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Other category. Cost of operations presented for our Other category includes costs incurred by our ancillary businesses. As a result, cost per ton measurements are not presented for this category.

 

For the Other category, we had net loss from continuing operations of $3.5$6.6 million for the three months ended March 31,September 30, 2019 as compared to net loss from continuing operations of $1.2$4.0 million for the three months ended March 31,September 30, 2018. The net loss for the three months ended March 31,September 30, 2019 was negatively impacted by a $2.0 million expense recorded as the result of an agreement reached with a third-party to assume the surety bonds associated with Sands Hill Mining LLC that had not been transferred from our bond portfolio by the purchaser of Sands Hill Mining LLC as required by the sale agreement executed with the purchaser in November 2017.

Summary. (Unless otherwise specified, the following discussion of the results of operations for the nine months ended September 30, 2019 and 2018 exclude operating results relating to Pennyrile. The Pennyrile operating results are recorded as discontinued operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.)

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the nine months ended September 30, 2019 and 2018:

  Nine months ended  Nine months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
Statement of Operations Data:         
             
Coal revenues $138.7  $142.6  $(3.9)  (2.8)%
Other revenues  1.8   1.9   (0.1)  (4.7)%
Total revenues  140.5   144.5   (4.0)  (2.8)%
Costs and expenses:                
Cost of operations (exclusive of DD&A shown separately below)  124.7   120.9   3.8   3.1%
Freight and handling costs  4.3   8.2   (3.9)  (47.7)%
Depreciation, depletion and amortization  10.5   10.8   (0.3)  (3.0)%
Selling, general and administrative (exclusive of DD&A shown separately above)  11.6   8.1   3.5   42.7%
(Gain) on sale/disposal of assets  (6.7)  (7.2)  0.5   (7.9)%
(Loss)/income from operations  (3.9)  3.7   (7.6)  (207.1)%
Interest and other (income) expense:                
Interest expense and other  5.3   6.6   (1.3)  (19.9)%
Interest income and other  -   -   -   n/a 
Total interest and other (income) expense  5.3   6.6   (1.3)  (20.0)%
Net (loss) from continuing operations  (9.2)  (3.0)  (6.2)  210.2%
Net (loss) from discontinued operations  (49.6)  (7.4)  (42.2)  569.3%
Net (loss) $(58.8) $(10.4)  (48.4)  466.6%
                 
Total tons sold (in thousands except %)  2,278.2   2,463.9   (185.7)  (7.5)%
Coal revenues per ton $60.88  $57.89  $2.99   5.2%
Cost of operations per ton $54.72  $49.08  $5.64   11.5%
                 
Other Financial Data                
Adjusted EBITDA from continuing operations $7.4  $14.7  $(7.3)  (50.1)%
Adjusted EBITDA from discontinued operations  (5.1)  (1.5) $(3.6)  230.9%
Adjusted EBITDA $2.3  $13.2  $(10.9)  (82.4)%

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

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

Revenues.Our coal revenues for the nine months ended September 30, 2019 decreased by approximately $3.9 million, or 2.8%, to approximately $138.7 million from approximately $142.6 million for the nine months ended September 30, 2018. Coal revenues per ton were $60.88 for the nine months ended September 30, 2019, an increase of $2.99, or 5.2%, from $57.89 per ton for the nine months ended September 30, 2018. The decrease in coal revenues was primarily the result of fewer tons of coal sold during the nine months ended September 30, 2019. The increase in coal revenues per ton was primarily due to an increase in the contracted sale prices across all segments for the nine months ended September 30, 2019 compared to the same period in 2018.

Cost of Operations. Total cost of operations increased by $3.8 million or 3.1% to $124.7 million for the nine months ended September 30, 2019 as compared to $120.9 million for the nine months ended September 30, 2018. Our cost of operations per ton was $54.72 for the nine months ended September 30, 2019, an increase of $5.64, or 11.5%, from the nine months ended September 30, 2018. The increase in cost of operations and cost of operations per ton was primarily due to increases in costs at several of our operations for labor, contract services and equipment maintenance for the nine months ended September 30, 2019 compared to the same period in 2018.

Freight and Handling.Total freight and handling cost decreased to $4.3 million for the nine months ended September 30, 2019 as compared to $8.2 million for the nine months ended September 30, 2018. The decrease in freight and handling costs was primarily the result of fewer export sales that require us to pay railroad transportation to the port of export during the nine months ended September 30, 2019. We also incurred $1.1 million in demurrage charges during the nine months ended September 30, 2018.

Depreciation, Depletion and Amortization. Total DD&A expense for the nine months ended September 30, 2019 was $10.5 million as compared to $10.8 million for the nine months ended September 30, 2018.

For the nine months ended September 30, 2019, our depreciation expense was approximately $7.5 million compared to approximately $7.7 million for the same period in 2018.

For the nine months ended September 30, 2019 and 2018, our depletion expense remained flat at approximately $1.3 million.

For the nine months ended September 30, 2019 our amortization expense was $1.7 million compared to $1.8 million for the same period in 2018.

41

Selling, General and Administrative. SG&A expense for the nine months ended September 30, 2019 increased to $11.6 million as compared to $8.1 million for the nine months ended September 30, 2018 primarily due to higher corporate overhead expenses. SG&A was also impacted by a $2.0 million expense recorded as the result of an agreement reached with a third-party to assume the surety bonds associated with Sands Hill Mining LLC that had not been transferred from our bond portfolio by the purchaser of Sands Hill Mining LLC as required by the sale agreement executed with the purchaser in November 2017.

Interest Expense.Interest expense for the nine months ended September 30, 2019 decreased to $5.3 million as compared to $6.6 million for the nine months ended September 30, 2018. This decrease was primarily due to the lower average outstanding debt balance for the nine months ended September 30, 2019 compared to the same period in 2018.

Net Loss. Net loss was $9.2 million for the nine months ended September 30, 2019 compared to net loss of $3.0 million for the nine months ended September 30, 2018. Our net loss increased during the nine months ended September 30, 2019 compared to 2018 primarily due the decrease in tons sold and an increase in operating costs including labor, contract services and equipment maintenance at several of our operations.

Adjusted EBITDA. Adjusted EBITDA from continuing operations for the nine months ended September 30, 2019 decreased by $7.3 million to $7.4 million from $14.7 million for the nine months ended September 30, 2018. Adjusted EBITDA from continuing operations decreased period over period primarily due to the increase in net loss as discussed above. Including net loss from discontinued operations of approximately $49.6 million, which related to the assets sold at our Pennyrile operation in September 2019, our net loss was $58.8 million and Adjusted EBITDA, which excludes an impairment loss associated with the sale, was $2.3 million for the nine months ended September 30, 2019. Including net loss from discontinued operations of approximately $7.4 million, which relates to Pennyrile, our net loss was $10.4 million and Adjusted EBITDA was $13.2 million for the nine months ended September 30, 2018. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA from continuing operations to net income/(loss) from continuing operations on a segment basis.

Segment Results

The following tables set forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data by reportable segment for the nine months ended September 30, 2019 and 2018:

Central Appalachia

  Nine months ended  Nine months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $90.3  $102.8  $(12.5)  (12.2)%
Freight and handling revenues  -   -   -   n/a 
Other revenues  0.4   0.1   0.3   164.1%
Total revenues  90.7   102.9   (12.2)  (12.0)%
Coal revenues per ton $80.49  $73.37  $7.12   9.7%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  82.1   82.1   -   0.0%
Freight and handling costs  3.2   8.2   (5.0)  (61.5)%
Depreciation, depletion and amortization  5.8   6.7   (0.9)  (13.6)%
Selling, general and administrative costs  0.1   0.4   (0.3)  (77.7)%
Cost of operations per ton $73.16  $58.56  $14.60   24.9%
Net income from continuing operations  6.5   5.5   1.0   17.5%
Adjusted EBITDA from continuing operations  12.3   12.5   (0.2)  (1.8)%
Tons sold (in thousands except %)  1,121.7   1,401.8   (280.1)  (20.0)%

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

Tons of coal sold in our Central Appalachia segment decreased by approximately 20.0% to approximately 1.1 million tons for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, primarily due to the softening in the met and steam coal markets during the third quarter of 2019, which has resulted in some of our customers pushing out shipments to a future date. We also had some uncontracted tons in Central Appalachia and were unable to sell the coal on the spot market during the third quarter of 2019.

Coal revenues decreased by approximately $12.5 million, or 12.2%, to approximately $90.3 million for the nine months ended September 30, 2019 from approximately $102.8 million for the nine months ended September 30, 2018. Coal revenues per ton for our Central Appalachia segment increased by $7.12, or 9.7%, to $80.49 per ton for the nine months ended September 30, 2019 as compared to $73.37 per ton for the nine months ended September 30, 2018. The increase in coal revenues per ton was primarily due to higher contracted sales prices for met and steam tons sold in Central Appalachia during the nine months ended September 30, 2019 compared to the same period in 2018.

For the nine months ended September 30, 2019 and 2018, our cost of operations remained flat at $82.1 million. In addition, costs increased for labor, contract services and equipment maintenance during the nine months ended September 30, 2019, which are included in our inventory balance. Our cost of operations per ton of $73.16 for the nine months ended September 30, 2019 increased 24.9% compared to $58.56 per ton for the nine months ended September 30, 2018. The cost of operations per ton increased as fewer tons sold from our Central Appalachia operations resulting in fixed costs being allocated to fewer tons sold during the nine months ended September 30, 2019 compared to the same period in 2018.

For our Central Appalachia segment, net income was approximately $6.5 million for the nine months ended September 30, 2019, an increase of $1.0 million compared to the nine months ended September 30, 2018. The increase in net income was primarily due to the $6.9 million gain resulting from the pipeline settlement discussed above, which was partially offset by the lower coal revenues discussed above for the nine months ended September 30, 2019.

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 for the nine months ended September 30, 2019, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.

(In thousands, except per ton data and %) 

Nine months ended

September 30, 2019

  

Nine months ended

September 30, 2018

  Increase (Decrease) %* 
Met coal tons sold  523.1   628.2   (16.7)%
Steam coal tons sold  598.6   773.6   (22.6)%
Total tons sold  1,121.7   1,401.8   (20.0)%
             
Met coal revenue $56,396  $64,004   (11.9)%
Steam coal revenue $33,884  $38,840   (12.8)%
Total coal revenue $90,280  $102,844   (12.2)%
             
Met coal revenues per ton $107.81  $101.89   5.8%
Steam coal revenues per ton $56.61  $50.20   12.8%
Total coal revenues per ton $80.49  $73.37   9.7%
             
Met coal tons produced  418.3   392.2   6.7%
Steam coal tons produced  850.0   941.8   (9.7)%
Total tons produced  1,268.3   1,334.0   (4.9)%

Northern Appalachia

 Nine months ended  Nine months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $20.7  $12.8  $7.9   61.2%
Freight and handling revenues  -   -   -   n/a 
Other revenues  1.4   1.6   (0.2)  (12.3)%
Total revenues  22.1   14.4   7.7   53.1%
Coal revenues per ton $48.68  $42.17  $6.51   15.4%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  23.6   17.0   6.6   38.2%
Freight and handling costs  1.1   -   1.1   n/a 
Depreciation, depletion and amortization  1.3   0.8   0.5   55.1%
Selling, general and administrative costs  -   -   -   n/a 
Cost of operations per ton $55.51  $56.07  $(0.56)  (1.0)%
Net (loss) from continuing operations  (4.0)  (3.5)  (0.5)  14.4%
Adjusted EBITDA from continuing operations  (2.7)  (2.7)  -   1.0%
Tons sold (in thousands except %)  424.4   304.0   120.4   39.6%

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

For our Northern Appalachia segment, tons of coal sold increased by approximately 39.6% for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 due to increase in demand for coal from this region during the nine months ended September 30, 2019.

Coal revenues were approximately $20.7 million for the nine months ended September 30, 2019, an increase of approximately $7.9 million, or 61.2%, from approximately $12.8 million for the nine months ended September 30, 2018. Coal revenues per ton increased by $6.51 or 15.4% to $48.68 per ton for the nine months ended September 30, 2108, as compared to $42.17 for the nine months ended September 30, 2018. Coal revenues and coal revenues per ton increased as the result of the increase in tons sold from our Hopedale operation and higher contracted prices for tons sold during the first nine months of 2019.

Cost of operations increased by $6.6 million, or 38.2%, to $23.6 million for the nine months ended September 30, 2019 from $17.0 million for the nine months ended September 30, 2018. The increase in total cost of operations was due to increased production and sales during the nine months ended September 30, 2019. We also encountered adverse geological conditions at times during the first nine months of 2019. Our cost of operations per ton was $55.51 for the nine months ended September 30, 2019, a decrease of $0.56, or 1.0%, compared to $56.07 for the nine months ended September 30, 2018.

Net loss in our Northern Appalachia segment was $4.0 million for the nine months ended September 30, 2019 compared to net loss of $3.5 million for the nine months ended September 30, 2018. The increase in net loss for the nine months ended September 30, 2019 was primarily due to the increase in cost of operations during the first nine months of 2019 compared to the same period in 2018.

Rhino Western

 Nine months ended  Nine months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $27.7  $27.0  $0.7   2.9%
Freight and handling revenues  -   -   -   n/a 
Other revenues  -   -   -   n/a 
Total revenues  27.7   27.0   0.7   2.8%
Coal revenues per ton $37.90  $35.58  $2.32   6.5%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  21.1   22.8   (1.7)  (7.2)%
Freight and handling costs  -   -   -   n/a 
Depreciation, depletion and amortization  3.3   3.1   0.2   6.0%
Selling, general and administrative costs  0.1   0.1   -   (46.2)%
Cost of operations per ton $28.87  $30.06  $(1.19)  (4.0)%
Net income from continuing operations  2.5   1.0   1.5   160.8%
Adjusted EBITDA from continuing operations  6.5   4.1   2.4   61.7%
Tons sold (in thousands except %)  732.1   758.1   (26.0)  (3.4)%

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

Tons of coal sold from our Rhino Western segment decreased by 3.4% for the nine months ended September 30, 2019 compared to the same period in 2018.

Coal revenues increased by approximately $0.7 million, or 2.9%, to approximately $27.7 million for the nine months ended September 30, 2019 from approximately $27.0 million for the nine months ended September 30, 2018. Coal revenues per ton for our Rhino Western segment increased by $2.32 or 6.5% to $37.90 per ton for the nine months ended September 30, 2019 as compared to $35.58 per ton for the nine months ended September 30, 2018. The increase in coal revenues and coal revenues per ton was primarily due to higher contracted sale prices for tons sold from the Castle Valley mine for the nine months ended September 30, 2019.

Cost of operations decreased by $1.7 million, or 7.2%, to $21.1 million for the nine months ended September 30, 2019 from $22.8 million for the nine months ended September 30, 2018. Our cost of operations per ton was $28.87 for the nine months ended September 30, 2019, a decrease of $1.19, or 4.0%, compared to $30.06 for the nine months ended September 30, 2018. The decrease in total cost of operations and cost of operations per ton was primarily due to lower operating costs during the nine months ended September 30, 2019 compared to the same period in 2018.

Net income from our Rhino Western segment was $2.5 million for the nine months ended September 30, 2019, compared to net income of $1.0 million for the nine months ended September 30, 2018. The increase in net income was primarily due to the increase in coal revenues per ton for coal sold from our Castle Valley operation and a decrease in operating expenses for the nine months ended September 30, 2019 compared to the same period in 2018.

Other

 Nine months ended  Nine months ended  Increase/(Decrease) 
  September 30, 2019  September 30, 2018  $  % * 
  (in millions, except per ton data and %) 
             
Coal revenues $-  $-   n/a   n/a 
Freight and handling revenues  -   -   n/a   n/a 
Other revenues  -   0.2  $(0.2)  (83.9)%
Total revenues  -   0.2   (0.2)  (83.9)%
Coal revenues per ton**   n/a    n/a    n/a   n/a 
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)  (2.1)  (1.0)  (1.1)  110.2%
Freight and handling costs  -   -   -   n/a 
Depreciation, depletion and amortization  0.1   0.2   (0.1)  (24.2)%
Selling, general and administrative costs  11.4   7.6   3.8   50.8%
Cost of operations per ton**   n/a    n/a    n/a   n/a 
Net (loss) from continuing operations  (14.2)  (6.0)  (8.2)  137.6%
Adjusted EBITDA from continuing operations  (8.7)  0.9   (9.6)  n/a 
Tons sold (in thousands except %)   n/a    n/a    n/a   n/a 

*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 do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Other category. Cost of operations presented for our Other category includes costs incurred by our ancillary businesses. As a result, cost per ton measurements are not presented for this category.

For the Other category, we had net loss of $14.2 million for the nine months ended September 30, 2019 as compared to net loss of $6.0 million for the nine months ended September 30, 2018. The net loss for the nine months ended September 30, 2019 was negatively impacted by a $2.0 million expense recorded as the result of an agreement reached with a third-party to assume the surety bonds associated with Sands Hill Mining LLC that had not been transferred from our bond portfolio by the purchaser of Sands Hill Mining LLC as required by the sale agreement executed with the purchaser in November 2017. The net loss for the nine months ended September 30, 2018 was positively impacted by a $2.9gain of $6.5 million gainrecognized on the sale of assets.Mammoth Inc. shares.

 

46

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      Central Northern Rhino Illinois     
Three months ended March 31, 2019 Appalachia Appalachia Western Basin Other Total 
Three months ended September 30, 2019 Appalachia Appalachia Western Basin Other Total 
 (in millions)  (in millions) 
Net income/(loss) $1.2  $(1.1) $(0.3) $(3.6) $(3.5) $(7.3) $(1.2) $(2.1) $1.5  $-  $(6.6) $(8.4)
Plus:                                                
DD&A  1.9   0.4   1.1   2.1   -   5.5   2.0   0.4   1.1   -   -   3.5 
Interest expense  -   -   -   -   1.7   1.7   -   -   -   -   1.9   1.9 
EBITDA†* $3.1  $(0.7) $0.8  $(1.5) $(1.8) $(0.1)
Plus: Loss from sale of non-core asset (1)          0.7           0.7 
Adjusted EBITDA †* $3.1  $(0.7) $1.5  $(1.5) $(1.8) $0.6 
EBITDA from continuing operations†* $0.8  $(1.7) $2.6  $-  $(4.6) $(3.0)
Plus: Loss from sale of non-core assets (1)  -   -   0.1   -   -   0.1 
Adjusted EBITDA from continuing operations  0.8   (1.7)  2.7   -   (4.6)  (2.9)
EBITDA from discontinued operations  -   -   -   (41.5)  -   (41.5)
Plus: Loss on impairment of assets (2)  -   -   -   38.6   -   38.6 
Adjusted EBITDA $0.8  $(1.7) $2.7  $(2.9) $(4.6) $(5.8)

 

 Central Northern Rhino Illinois      Central Northern Rhino Illinois     
Three months ended March 31, 2018 Appalachia Appalachia Western Basin Other Total 
Three months ended September 30, 2018 Appalachia Appalachia Western Basin Other Total 
 (in millions)  (in millions) 
Net (loss)/income $0.9  $(1.1) $0.9  $(2.3) $(1.2) $(2.8) $3.6  $(0.8) $-  $-  $(4.0) $(1.2)
Plus:                      -                       - 
DD&A  2.2   0.1   1.1   1.9   0.1   5.4   2.2   0.3   1.0   -   0.1   3.6 
Interest expense  -   -   -   -   1.9   1.9   -   -   -   -   2.8   2.8 
EBITDA † $3.1  $(1.0) $2.0  $(0.4) $0.8  $4.5 
Adjusted EBITDA † $3.1  $(1.0) $2.0  $(0.4) $0.8  $4.5 
EBITDA from continuing operations† $5.8  $(0.5) $1.0  $-  $(1.1) $5.2 
Plus: Bad debt expense  0.3   -   -   -   -   0.3 
Adjusted EBITDA from continuing operations† $6.1  $(0.5) $1.0  $-  $(1.1) $5.5 
EBITDA from discontinued operations  -   -   -   (1.3)  -   (1.3)
Adjusted EBITDA $6.1  $(0.5) $1.0  $(1.3) $(1.1) $4.2 

 

  Three months ended March 31, 
  2019  2018 
  (in millions) 
Reconciliation of net cash to Adjusted EBITDA provided by operating activities:        
Net cash provided by operating activities $0.5  $8.4 
Plus:        
Gain on sale of assets  -   2.9 
Gain on disposal of business  -   - 
Interest expense  1.7   1.9 
Less:        
Decrease in net operating assets  0.7   7.5 
Loss on sale of assets  0.2   - 
Amortization of advance royalties  0.4   0.3 
Amortization of debt discount  0.1   0.1 
Amortization of debt issuance costs  0.5   0.4 
Loss on retirement of advance royalties  0.1   0.1 
Accretion on asset retirement obligations  0.3   0.3 
EBITDA†  (0.1)  4.5 
Plus: Loss from sale of non-core asset (1)  0.7     
Adjusted EBITDA† $0.6  $4.5 
  Central  Northern  Rhino  Illinois       
Nine months ended September 30, 2019 Appalachia  Appalachia  Western  Basin  Other  Total 
  (in millions) 
Net income/(loss) $6.5  $(4.0) $2.5  $-  $(14.2) $(9.2)
Plus:                        
DD&A  5.8   1.3   3.3   -   0.1   10.5 
Interest expense  -   -   -   -   5.3   5.3 
EBITDA from continuing operations† $12.3  $(2.7) $5.8  $-  $(8.8) $6.6 
Plus: Loss from sale of non-core assets (1)  -   -   0.8   -   -   0.8 
Adjusted EBITDA from continuing operations†* $12.3  $(2.7) $6.5  $-  $(8.7) $7.4 
EBITDA from discontinued operations  -   -   -   (43.7)  -   (43.7)
Plus: Loss on impairment of assets (2)  -   -   -   38.6   -   38.6 
Adjusted EBITDA* $12.3  $(2.7) $6.5  $(5.1) $(8.7) $2.3 

 

  Central  Northern  Rhino  Illinois       
Nine months ended September 30, 2018 Appalachia  Appalachia  Western  Basin  Other  Total 
  (in millions) 
Net (loss)/income $5.5  $(3.5) $1.0  $-  $(6.0) $(3.0)
Plus:                      - 
DD&A  6.7   0.8   3.1   -   0.2   10.8 
Interest expense  -   -   -   -   6.6   6.6 
EBITDA from continuing operations†* $12.2  $(2.7) $4.1  $-  $0.9  $14.4 
Plus: Bad debt expense  0.3   -   -   -   -   0.3 
Adjusted EBITDA from continuing operations†* $12.5  $(2.7) $4.1  $-  $0.9  $14.7 
EBITDA from discontinued operations  -   -   -   (1.5)  -   (1.5)
Adjusted EBITDA †* $12.5  $(2.7) $4.1  $(1.5) $0.9  $13.2 
                         
* Total may not foot due to rounding                        

(1) During the three months ended March 31, 2019, we sold parcels of land owned in western Colorado for proceeds less than our carrying value of the land that resulted in a loss of approximately $0.7 million. This land is a non-core asset that we chose to monetize despite the loss incurred. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.

  Three months ended September 30,  Nine months ended September 30, 
  2019  2018  2019  2018 
  (in millions) 
Net cash (used in)/provided by operating activities $(2.1) $0.9  $(3.3) $7.5 
Plus:                
Gain on sale of assets  -   0.8   6.7   7.2 
Interest expense  1.9   2.8   5.3   6.6 
Decrease in deferred revenue  -   0.9   -   - 
Less:                
 Decrease in net operating assets  4.2   0.1   2.6   4.6 
Amortization of advance royalties  0.5   0.1   1.5   0.5 
Amortization of debt discount  0.1   0.1   0.3   0.3 
Amortization of debt issuance costs  0.5   0.6   1.6   1.4 
Increase in doubtful accounts  -   0.3   -   0.3 
Loss on sale of assets  -             
Loss on impairment of assets  38.6   -   38.6   - 
Loss on retirement of advance royalties  0.1   -   0.2   0.1 
Equity based compensation  -   -   -   0.2 
Accretion on asset retirement obligations  0.3   0.3   1.0   1.0 
EBITDA†  (44.5)  3.9   (37.1)  12.9 
Plus: Loss from sale of non-core assets (1)  0.1   -   0.8   - 
Plus: Non-cash bad debt expense  -   0.3   -   0.3 
Plus: Loss on asset impairments (2)  38.6   -   38.6   - 
Adjusted EBITDA  (5.8)  4.2   2.3   13.2 
Less: Adjusted EBITDA from discontinued operations  (2.9)  (1.3)  (5.1)  (1.5)
Adjusted EBITDA from continuing operations $(2.9) $5.5  $7.4  $14.7 

(1)During the three and nine months ended September 30, 2019, we sold parcels of land owned in western Colorado for proceeds less than our carrying value of the land that resulted in losses of approximately $0.1 million and $0.8 million, respectively. This land is a non-core asset that we chose to monetize despite the loss incurred. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.
(2)We recorded an impairment loss of $38.6 million associated with the sale of our Pennyrile assets for the three and nine months ended September 30, 2019. The impairment loss of $38.6 million is recorded in discontinued operations for the three and nine months ended September 30, 2019.

 

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

Liquidity and Capital Resources

 

Liquidity

 

As of March 31,September 30, 2019, our available liquidity was $4.2$8.0 million. We also have a delayed draw term loan commitment in the amount of $35$25 million contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement discussed below.

 

On December 27, 2017, we entered into a Financing Agreement, which provides us with a multi-draw loan in the original aggregate principal amount of $80 million. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement and ana $40 million additional $35 million commitment that iswas contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. As of September 30, 2019, we have utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. We used approximately $17.3 million of the initial Financing Agreement net proceeds thereof to repay all amounts outstanding and terminate the amended and restated credit agreement with PNC Bank.Bank, National Association, as Administrative Agent. The Financing Agreement terminates oninitially had a termination date of December 27, 2020. For more information about our2020, which was amended to December 27, 2022 per the fifth amendment to the Financing Agreement please read “—Financing Agreement”discussed further below.

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, cash available on our balance sheet 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 maintain 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.

Beginning in the later part of the third quarter of 2019, we have experienced weak market demand and have seen prices move lower for the qualities of met and steam coal we produce. If we continue to experience weak demand and prices continue to lower for our met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our Financing Agreement. If we violate any of the covenants or restrictions in our Financing Agreement, including the fixed-charge coverage ratio, some or all of our indebtedness may become immediately due and payable, and our lenders’ may not be willing to make any loans under the additional commitment available under our Financing Agreement. 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 under our Financing Agreement. Although we believe our lenders are well secured under the terms of our Financing 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 spending and 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.

 

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

Cash Flows

 

Net cash used in operating activities was $3.3 million for the nine months ended September 30, 2019 as compared to net cash provided by operating activities was $0.5of $7.5 million for the threenine months ended March 31, 2019 as compared to $8.4 million for the three months ended March 31,September 30, 2018. This decrease in cash provided by operating activities was the result of lowera higher net incomeloss and negative working capital changes primarily due to the increase in our inventory during the threenine months ended March 31,September 30, 2019.

 

Net cash provided by investing activities was $1.7 millionzero for the threenine months ended March 31,September 30, 2019 as compared to net cash used in investing activities of $4.4$3.8 million for the threenine months ended March 31,September 30, 2018. The decrease in cash used in investing activities was primarily due to an increase in proceeds from the sale of assets during the nine months ended September 30, 2019 and a decrease in capital expenditures during the first quarternine months of 2019 compared to the same period in 2018.

 

Net cash provided by financing activities was $4.5 million for the nine months ended September 30, 2019 and net cash used in financing activities was $4.2 million and $16.4$19.3 million for the threenine months ended March 31,September 30, 2018. Net cash provided by financing activities for the nine months ended September 30, 2019 and 2018, respectively.was primarily attributable to proceeds from our Financing Agreement. Net cash used in financing activities for the threenine months ended March 31,September 30, 2018 was primarily attributable to repayments on our Financing Agreement and deposits paid on our workers’ compensation and surety bond programs.programs and repayments on our Financing Agreement. The periods ending March 31,September 30, 2019 and 2018 were both impacted by payment of the distribution on the Series A preferred units.

3549
 

Capital Expenditures

 

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

 

Actual maintenance capital expenditures for the threenine months ended March 31,September 30, 2019 were approximately $1.6$6.3 million. These amounts wereThis amount was primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the threenine months ended March 31,September 30, 2019 were approximately $0.4$4.3 million, which were primarily related to the construction of a new airshaft at our Hopedale mining complex in Northern Appalachia.Appalachia and the purchase of the Virginia assets from Blackjewel that was discussed above.

 

Series A Preferred Unit Purchase Agreement

 

On December 30, 2016, we entered into a Series A Preferred Unit Purchase Agreement (“Preferred Unit Agreement”) with Weston Energy LLC (“Weston”) 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 us 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 our 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 us and Weston assigned to us a $2.0 million note receivable from Royal originally dated September 30, 2016. Through a series of transactions, Weston now owns all of the Series A preferred units.

 

Fourth Amended and Restated Partnership Agreement of Limited Partnership

 

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

 

The holders of the Series A preferred units are 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 our partnership agreement as (i) the total revenue of our Central Appalachia business segment, minus (ii) the cost of operations (exclusive of depreciation, depletion and amortization) for our 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 us from our Central Appalachia business segment. If we fail 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 we will not be permitted to pay any distributions on our partnership interests that rank junior to the Series A preferred units, including our common units.

 

We 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.

During the first quarter of 2019, we paid $3.2 million to the holders of Series A preferred units for distributions earned for the year ended December 31, 2018. During the first quarter of 2018, we paid the holders of Series A preferred units $6.0 million in distributions earned for the year ended December 31, 2017. We have accrued approximately $0.3$0.9 million for distributions to holders of the Series A preferred units for the threenine months ended March 31,September 30, 2019.

 

Financing Agreement

 

On December 27, 2017, we entered into a Financing Agreement with Cortland Capital Market Services LLC, as Collateral Agent and Administrative agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein (the “Lenders”), pursuant to which the Lenders have agreed to provide us with a multi-draw term loan in the original aggregate principal amount of $80 million, subject to the terms and conditions set forth in the Financing Agreement. The total principal amount is divided into a $40 million commitment, the conditions forof which were satisfied at the execution of the Financing Agreement (the “Effective Date Term Loan Commitment”) and ana $40 million additional $35 million commitment that iswas contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). As of September 30, 2019, we have utilized $15 million of the $40 million additional commitment, which results in $25 million of the additional commitment remaining. Loans made pursuant to the Financing Agreement are secured by substantially all of our assets. The Financing Agreement terminates onoriginally had a termination date of December 27, 2020.2020, which was amended to December 27, 2022 per the fifth amendment to the Financing Agreement discussed further below.

Loans made pursuant to the Financing Agreement are, at our option, either “Reference Rate Loans” or “LIBOR Rate Loans.” Reference Rate Loans bear interest at the greatest of (a) 4.25% per annum, (b) the Federal Funds Rate plus 0.50% per annum, (c) the LIBOR Rate (calculated on a one-month basis) plus 1.00% per annum or (d) the Prime Rate (as published in the Wall Street Journal) or if no such rate is published, the interest rate published by the Federal Reserve Board as the “bank prime loan” rate or similar rate quoted therein, in each case, plus an applicable margin of 9.00% per annum (or 12.00% per annum if we have elected to capitalize an interest payment pursuant to the PIK Option, as described below). LIBOR Rate Loans bear interest at the greater of (x) the LIBOR for such interest period divided by 100% minus the maximum percentage prescribed by the Federal Reserve for determining the reserve requirements in effect with respect to eurocurrency liabilities for any Lender, if any, and (y) 1.00%, in each case, plus 10.00% per annum (or 13.00% per annum if we have elected to capitalize an interest payment pursuant to the PIK Option). Interest payments are due on a monthly basis for Reference Rate Loans and one-, two- or three-month periods, at our option, for LIBOR Rate Loans. If there is no event of default occurring or continuing, we may elect to defer payment on interest accruing at 6.00% per annum by capitalizing and adding such interest payment to the principal amount of the applicable term loan (the “PIK Option”).

 

Commencing December 31, 2018, the principal for each loan made under the Financing Agreement will be payable on a quarterly basis in an amount equal to $375,000 per quarter, with all remaining unpaid principal and accrued and unpaid interest originally due on December 27, 2020.2020 (see discussion of fifth amendment below). In addition, we must make certain prepayments over the term of any loans outstanding, including: (i) the payment of 25% of Excess Cash Flow (as that term is defined in the Financing Agreement) for each fiscal year, commencing with respect to the year ending December 31, 2019, (ii) subject to certain exceptions, the payment of 100% of the net cash proceeds from the dispositions of certain assets, the incurrence of certain indebtedness or receipts of cash outside of the ordinary course of business, and (iii) the payment of the excess of the outstanding principal amount of term loans outstanding over the amount of the Collateral Coverage Amount (as that term is defined in the Financing Agreement). In addition, the Lenders are entitled to (i) certain fees, including 1.50% per annum of the unused Delayed Draw Term Loan Commitment for as long as such commitment exists, (ii) for the 12-month period following the execution of the Financing Agreement, a make-whole amount equal to the interest and unused Delayed Draw Term Loan Commitment fees that would have been payable but for the occurrence of certain events, including among others, bankruptcy proceedings or the termination of the Financing Agreement by us, and (iii) audit and collateral monitoring fees and origination and exit fees.

The Financing Agreement requires us to comply with several affirmative covenants at any time loans are outstanding, including, among others: (i) the requirement to deliver monthly, quarterly and annual financial statements, (ii) the requirement to periodically deliver certificates indicating, among other things, (a) compliance with terms of Financing Agreement and ancillary loan documents, (b) inventory, accounts payable, sales and production numbers, (c) the calculation of the Collateral Coverage Amount (as that term is defined in the Financing Agreement), (d) projections for the business and (e) coal reserve amounts; (iii) the requirement to notify the Administrative Agent of certain events, including events of default under the Financing Agreement, dispositions, entry into material contracts, (iv) the requirement to maintain insurance, obtain permits, and comply with environmental and reclamation laws (v) the requirement to sell up to $5.0 million of shares in Mammoth Inc. and use the net proceeds therefrom to prepay outstanding term loans and (vi) establish and maintain cash management services and establish a cash management account and deliver a control agreement with respect to such account to the Collateral Agent. The Financing Agreement also contains negative covenants that restrict our ability to, among other things: (i) incur liens or additional indebtedness or make investments or restricted payments, (ii) liquidate or merge with another entity, or dispose of assets, (iii) change the nature of our respective businesses; (iv) make capital expenditures in excess, or, with respect to maintenance capital expenditures, lower than, specified amounts, (v) incur restrictions on the payment of dividends, (vi) prepay or modify the terms of other indebtedness, (vii) permit the Collateral Coverage Amount to be less than the outstanding principal amount of the loans outstanding under the Financing Agreement or (viii) permit the trailing six month Fixed Charge Coverage Ratio to be less than 1.20 to 1.00 commencing with the six-month period ending June 30, 2018.

 

The Financing Agreement contains customary events of default, following which the Collateral Agent may, at the request of lenders, terminate or reduce all commitments and accelerate the maturity of all outstanding loans to become due and payable immediately together with accrued and unpaid interest thereon and exercise any such other rights as specified under the Financing Agreement and ancillary loan documents.

 

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

 

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

 

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

 

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

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

 

On May 8, 2019, we entered into a consent with our Lenders relatedthird amendment (“Third Amendment”) to the Financing Agreement. The consentThird Amendment includes the lenders agreement to waive any Event of Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio for the six months ended March 31, 2019. The Third Amendment increases the original exit fee of 3.0% to 6.0%. The original exit fee of 3% was included in the Financing Agreement at the execution date and the increase of the total exit fee to 6% was included as part of the amendment dated February 13, 2019 discussed above and this Third Amendment. The exit fee is applied to the principal amount of the loans made under the Financing Agreement that is payable on the earliest of (a) the final maturity date, (b) the termination date of the Financing agreement for any reason, (c) the acceleration of the obligations in the Financing Agreement for any reason and (d) the date of any refinancing of the term loan under the Financing Agreement.

On August 16, 2019, we entered into a fourth amendment (the “Fourth Amendment”) to the Financing Agreement originally executed on December 27, 2017 with the Lenders. The Fourth Amendment provides a $5.0 million term loan provided by the Lenders to us under the delayed draw feature of the Financing Agreement, and extends the period by which an applicable premium payable to the Lenders will be calculated to the final maturity date.

On September 6, 2019, we entered into a fifth amendment (the “Fifth Amendment”) to the Financing Agreement originally executed on December 27, 2017 with Cortland Capital Market Services LLC, as Collateral Agent and Administrative Agent, CB Agent Services LLC, as Origination Agent and the parties identified as Lenders therein (the “Lenders”). The Fifth Amendment (i) extends the maturity of the Financing Agreement to December 27, 2022, (ii) provides us with a $5.0 million term loan provided by the Lenders under the delayed draw feature of the Financing Agreement, (iii) extends the period by which an applicable premium payable to the Lenders will be calculated to December 31, 2021, (iv) modifies the certain definitions and concepts to account for our recent acquisition of properties from Blackjewel, (v) permits the disposition of the Pennyrile Mining Complex and (viii) provides for the payment of additional fees to the Lenders, including a consent fee of $1.0 million, an amendment fee of $825,000 and an increase in the lender exit fee of 1.00% to a total exit fee of 7.0% of the amount of term loans made under the Financing Agreement that is payable upon the maturity of the Financing Agreement.

 

At March 31,September 30, 2019, we had $28.7$27.9 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (12.50%(12.13%), $5.0 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (12.17%) and $5.0 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% (12.06%).

 

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 statement of financial position, 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. We then provide cash collateral to secure our surety bonding obligations in an amount up to a certain percentage of the aggregate bond liability that we negotiate with the surety companies. 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 March 31,September 30, 2019, we had $8.2$7.9 million in cash collateral held by third-parties of which $3.0 million serves as collateral for approximately $42.3$41.6 million in surety bonds outstanding that secure the performance of our reclamation obligations. The other $5.2$4.9 million serves as collateral for our self-insured workers’ compensation program. Of the $42.3$41.6 million in surety bonds, approximately $0.4 million relates to surety bonds for Deane Mining, LLC, and approximately $3.4 million relates to surety bonds for Sands Hill Mining, LLC, which in each case have not been transferred or replaced by the buyers of Deane Mining LLC or Sands Hill Mining, LLC as was agreed to by the parties as part of the transactions.transaction. We can provide no assurances that a surety company will underwrite the surety bonds of the purchaserspurchaser of these entities,Deane Mining LLC, nor are we aware of the actual amount of reclamation at any given time. Further, if there was a claim under these surety bonds prior to the transfer or replacement of such bonds by the buyersbuyer of Deane Mining, LLC or Sands Hill Mining, LLC, then we may be responsible to the surety company for any amounts it pays in respect of such claim. While the buyers arebuyer is required to indemnify us for damages, including reclamation liabilities, pursuant the agreements governing the sales of these entities,this entity, we may not be successful in obtaining any indemnity or any amounts received may be inadequate.

 

Certain surety bonds for Sands Hill Mining LLC had not been transferred or replaced by the buyer of Sands Hill Mining LLC as was agreed to when we sold Sands Hill Mining LLC to the buyer in November 2017. On July 9, 2019, we entered into an agreement with a third party for the replacement of our existing surety bond obligations with respect to Sands Hill Mining LLC. We agreed to pay the third party $2.0 million to assume our surety bond obligations related to Sands Hill Mining LLC. At the time of closing, the third party delivered to us confirmation from its surety underwriter evidencing the release and removal of us, our affiliates and guarantors, from the surety bond obligations and all related obligations under our bonding agreements related to Sands Hill Mining LLC, which includes a release of all applicable collateral for the surety bond obligations. Further, such confirmation from the surety underwriter was specifically provided for their acceptance of the third party as a replacement obligor.

We had no letters of credit outstanding as of March 31,September 30, 2019.

 

Critical Accounting Policies and Estimates

 

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

 

The accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are fully described in our Annual Report on Form 10-K for the year ended December 31, 2018. We adopted ASU 2014-09, Topic 606 on January 1, 2018, using the modified retrospective method. The adoption of Topic 606 has no impact on revenue amounts recorded in our financial statements. There have been no other significant changes in these policies and estimates as of March 31,September 30, 2019.

 

We adopted ASU 2016-02- Leases (Topic 842) and all related clarification standards on January 1, 2019 using the transition method to apply the standard prospectively. The standard had a material impact on our unaudited condensed consolidated statements of financial position, but did not have an impact on our auditedunaudited condensed consolidated statements of operations. Please refer to Note 57 of the notes to the unaudited condensed consolidated financial statements for further discussion of the standard and the related disclosures.

Recent Accounting Pronouncements

 

Refer to Part-I— Item 1. Financial Statements, Note 2 of the notes to the unaudited condensed consolidated financial statements for a discussion of recent accounting pronouncements. There are no known future impacts or material changes or trends of new accounting guidance beyond the disclosures provided in Note 2.

 

Item 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures.As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31,September 30, 2019 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting.There was no change in our internal control over financial reporting that occurred during the quarter ended March 31,September 30, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

PART II—Other Information

 

Item 1. Legal Proceedings.

 

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

 

On May 3, 2019, we together with Royal (the “Plaintiffs”) filed a complaint in the Court of Chancery in the State of Delaware against Rhino Resource Partners Holdings LLC (“Holdings”), Weston Energy LLC (“Weston”), Yorktown Partners LLC and certain Yorktown funds (collectively, the “Yorktown entities”), as well as Mr. Ronald Phillips, Mr. Bryan H. Lawrence and Mr. Bryan R. Lawrence.

 

The complaint alleges that Holdings violated certain representations and negative covenants under an option agreement, dated December 30, 2016 among Holdings, the Plaintiffs, and Weston (the “Option Agreement”) and, as a result of Holdings’ entry into a Restructuring Support Agreement with Armstrong Energy, Inc. (“Armstrong”), its creditors and certain other parties, which agreement was entered into in advance of Armstrong’s filing for bankruptcy relief under Chapter 11 of the United States Code in November 2017. The complaint further alleges that (i) Mr. Phillips violated fiduciary and contractual duties owed to the Plaintiffs and solicited, accepted and agreed to accept certain benefits from Holdings, Weston, the Yorktown entities and Messrs. Lawrence and Lawrence without the Plaintiff’s knowledge or consent and during a period in which Mr. Phillips was the President of Royal and a director on our board and (ii) Holdings, Weston, the Yorktown entities and Messrs. Lawrence and Lawrence aided and abetted Mr. Phillips’ breaches of his fiduciary duties, tortuously interfered with the observance of Mr. Phillips’ duties under the respective organizational agreements and conferred, offered to confer and agreed to confer benefits on Mr. Phillips without the Plaintiff’s knowledge or consent.

 

The Plaintiffs are seeking (i) the rescission of the Option Agreement, (ii) the return of all consideration thereunder, including 5,000,000 of our common units representing limited partner interests (iii) the cancellation of the Series A Preferred Purchase Agreement, dated December 30, 2016, among the Plaintiffs and Weston (the “Series A Preferred Purchase Agreement”), (iv) the invalidation of the Series A preferred units representing limited partner interests in us issued to Weston pursuant to the Series A Preferred Purchase Agreement and (v) unspecified monetary damages arising from Mr. Phillips’ breaches of fiduciary duties and the other defendants’ aiding and abetting of such breaches.

The Yorktown entities filed an answer to the lawsuit on May 31, 2019, followed by a Motion for Judgment on the Pleadings and Motion to Dismiss. A hearing on the Motion for Judgment on the Pleadings is scheduled for April 7, 2020.

On September 23, 2019 we and Royal entered into a settlement agreement with Ronald Phillips under which Mr. Phillips will be dismissed with prejudice from the lawsuit discussed above in consideration for, among other things, Mr. Phillip’s return for cancellation of up to 500,000 shares of common stock of Royal previously issued to Mr. Phillips and Mr. Phillips’ dismissal of an advancement action filed by him in reference to the lawsuit. In addition, the settlement provided for reimbursement of a portion of the legal fees claimed by Mr. Phillips and no admission of liability by any party.

 

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, 2018, which risks could materially affect our business, financial condition or future results. ThereExcept as stated below, 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, 2018. 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.

Tax Risks to Common Unitholders

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. For example, the “Clean Energy for America Act”, which is similar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal Section 7704(d)(1)(E) of the Internal Revenue Code upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a publicly traded partnership in the future.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

 

None.

Item 3. Defaults upon Senior Securities.

 

None.

 

Item 4. Mine Safety Disclosure.

 

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 March 31,September 30, 2019 is included as Exhibit 95.1 to this report.

 

Item 5. Other Information.

 

None.

 

Item 6. Exhibits.

 

Exhibit Number Description
   
2.1General Assignment and Assumption Agreement and Bill of Sale, dated as of August 14, 2019, by and among Blackjewel L.L.C., Blackjewel Holdings L.L.C., Revelation Energy Holdings, LLC, Revelation Management Corp., Revelation Energy, LLC, Dominion Coal Corporation, Harold Keene Coal Co. LLC, Vansant Coal Corporation, Lone Mountain Processing LLC, Powell Mountain Energy, LLC, and Cumberland River Coal LLC and Jewell Valley Mining LLC, incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on August 20, 2019.
2.2**Asset Purchase Agreement (Riveredge Mine Assets) dated September 6, 2019, by and among Rhino Energy LLC, Pennyrile Energy LLC, CAM Mining LLC, Castle Valley Mining LLC, and Rhino Services LLC as Sellers, Rhino Resource Partners LP, the Seller’s parent, Alliance Coal, LLC as Buyer, and Alliance Resource Partners, L.P., as Buyer’s parent dated September 6, 2019, incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-34892) filed on September 12, 2019.
2.3**Asset Purchase Agreement (Coal Supply Agreements) dated September 6, 2019, by and among Rhino Energy LLC and Pennyrile Energy LLC, as Seller, Rhino Resource Partners LP, Seller’s parent, Alliance Coal, LLC as Buyer, and Alliance Resource Partners, L.P., as Buyer’s parent, incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-34892) filed on September 12, 2019.
3.1 Certificate of Limited Partnership of Rhino Resource Partners LP, incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on May 5, 2010
   
3.2 Fourth Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated as of December 30, 2016, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-34892) filed on January 6, 2017
   
3.3 Amendment No. 1 to the Fourth Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated January 25, 2018, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-34892) filed on January 25, 2018
   
4.1 Registration Rights Agreement, dated as of March 21, 2016, by and between Rhino Resource Partners LP and Royal Energy Resources, Inc., incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on March 23, 2016
4.2*Form of Common Unit Warrant.
   

10.1*

10.1		 

ThirdFourth Amendment to Financing Agreement dated as of May 8,August 16, 2019, by and among Rhino Resource Partners LP, as Parent, Rhino Energy LLC and each subsidiary of Rhino Energy listed as a borrower on the signature pages thereto, as Borrowers, Parent and each subsidiary of Parent listed as a guarantor on the signature pages thereto, as Guarantors, the lenders from time to time party thereto, as Lenders, Cortland Capital Market Services LLC, as Collateral Agent and Administrative Agent and CB Agent Services LLC, as Origination Agent, incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-34892) filed on August 20, 2019.

10.2Fifth Amendment to Financing Agreement dated as of September 6, 2019, by and among Rhino Resource Partners LP, as Parent, Rhino Energy LLC and each subsidiary of Rhino Energy listed as a borrower on the signature pages thereto, as Borrowers, Parent and each subsidiary of Parent listed as a guarantor on the signature pages thereto, as Guarantors, the lenders from time to time party thereto, as Lenders, Cortland Capital Market Services LLC, as Collateral Agent and Administrative Agent and CB Agent Services LLC, as Origination Agent, incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on September 12, 2019.
   
31.1* Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
   
31.2* Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
   
32.1* Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
   
32.2* Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
   
95.1* Mine Health and Safety Disclosure pursuant to §1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act for the three months ended March 31, 2019
   
101.INS* XBRL Instance Document
   
101.SCH* XBRL Taxonomy Extension Schema Document
   
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
   
101.DEF* XBRL Taxonomy Definition Linkbase Document
   
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
   
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document

 

The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1 and 32.2) with this Form 10-Q.

** Schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Partnership will provide a copy of any omitted schedule or similar attachments to the Securities and Exchange Commission upon request.

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.

 

 RHINO RESOURCE PARTNERS LP
   
 By:Rhino GP LLC, its General Partner
   
Date: May 10,November 8, 2019By:/s/ Richard A. Boone
  Richard A. Boone
  President, Chief Executive Officer and Director
  (Principal Executive Officer)
   
Date: May 10,November 8, 2019By:/s/ W. Scott Morris
  W. Scott Morris
  Senior Vice President and Chief Financial Officer
  (Principal Financial Officer)

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