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 ~~September~~June 30, ~~2018~~2019

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

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

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

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 ~~November~~August 2, ~~2018,~~2019, 13,098,353 common units, ~~1,145,743~~1,143,171 subordinated units and 1,500,000 Series A preferred units were outstanding.

TABLE OF CONTENTS

Cautionary Note Regarding Forward-Looking Statements	3
Part I.—Financial Information (Unaudited)	4
ITEM 1. FINANCIAL STATEMENTS	4
Condensed Consolidated Statements of Financial Position as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018	4
Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018	5
Consolidated Statements of Partners’ Capital for the Six Months Ended June 30, 2019 and 2018	6
Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018	67
Notes to Condensed Consolidated Financial Statements	78
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2325
Item 4. Controls and Procedures	48
PART II—Other Information	4849
Item 1. Legal Proceedings	4849
Item 1A. Risk Factors	4849
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4850
Item 3. Defaults upon Senior Securities	4850
Item 4. Mine Safety Disclosure	4850
Item 5. Other Information	4850
Item 6. Exhibits	4951
SIGNATURES	5152

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, ~~2017,~~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,
2018 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 5,568 $ 8,796
Restricted cash - 7,116
Accounts receivable, net of allowance for doubtful accounts ($0.3 million as of September 30, 2018 and -0- as of December 31, 2017) 25,410 20,386
Inventories 9,542 12,860
Advance royalties, current portion 852 495
Investment in available for sale securities 3,029 11,165
Prepaid expenses and other 3,663 2,891
Total current assets 48,064 63,709
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs 450,307 440,843
Less accumulated depreciation, depletion and amortization (273,518 ) (263,520 )
Net property, plant and equipment 176,789 177,323
Advance royalties, net of current portion 7,837 7,901
Deposits - Workers’ Compensation and Surety Programs 8,209 -
Investment in unconsolidated affiliates - 130
Restricted cash - 5,209
Other non-current assets 29,354 28,508
TOTAL $ 270,253 $ 282,780
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable $ 18,661 $ 9,329
Accrued expenses and other 10,516 11,186
Accrued preferred distributions 1,788 6,038
Current portion of long-term debt 7,595 5,475
Current portion of asset retirement obligations 498 498
Total current liabilities 39,058 32,526
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion 23,195 28,573
Asset retirement obligations, net of current portion 18,859 18,164
Other non-current liabilities 48,386 48,071
Total non-current liabilities 90,440 94,808
Total liabilities 129,498 127,334
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners 118,339 130,233
General partner 8,804 8,855
Preferred partners 15,000 15,000
Investment in Royal common stock (NOTE 11) (4,126 ) (4,126 )
Common unit warrants 1,264 1,264
Accumulated other comprehensive income 1,474 4,220
Total partners’ capital 140,755 155,446
TOTAL $ 270,253 $ 282,780

~~See notes to unaudited condensed consolidated financial statements.~~

RHINO RESOURCE PARTNERS LP
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME
(in thousands, except per unit data)

Three Months Nine Months
Ended September 30, Ended September 30,
2018 2017 2018 2017
REVENUES:
Coal sales $ 71,866 $ 56,266 $ 180,383 $ 161,820
Other revenues 699 420 1,906 1,098
Total revenues 72,565 56,686 182,289 162,918
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 60,786 44,751 160,031 132,939
Freight and handling costs 5,848 1,237 8,225 1,832
Depreciation, depletion and amortization 5,629 5,060 16,733 16,037
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above) 2,785 2,663 8,281 8,419
(Gain) on sale/disposal of assets—net (784 ) (83 ) (7,217 ) (38 )
Total costs and expenses 74,264 53,628 186,053 159,189
(LOSS)/INCOME FROM OPERATIONS (1,699 ) 3,058 (3,764 ) 3,729
INTEREST AND OTHER EXPENSE/(INCOME):
Interest expense 2,831 1,011 6,629 3,131
Interest income and other - (86 ) (7 ) (86 )
Equity in net (income) of unconsolidated affiliates - - - (36 )
Total interest and other expense 2,831 925 6,622 �� 3,009
NET (LOSS)/INCOME BEFORE INCOME TAXES FROM CONTINUING OPERATIONS (4,530 ) 2,133 (10,386 ) 720
INCOME TAXES - - - -
NET (LOSS)/INCOME FROM CONTINUING OPERATIONS (4,530 ) 2,133 (10,386 ) 720
DISCONTINUED OPERATIONS (NOTE 3)
Loss from discontinued operations - (461 ) - (787 )
NET (LOSS)/INCOME (4,530 ) 1,672 (10,386 ) (67 )
Other comprehensive (loss)/income:
Fair market value adjustment for available-for-sale investment (506 ) (990 ) 3,874 1,030
Reclass for disposition - - (6,621 ) -
Total other comprehensive (loss)/income (506 ) (990 ) (2,747 ) 1,030
COMPREHENSIVE (LOSS)/INCOME $ (5,036 ) $ 682 $ (13,133 ) $ 963

General partner’s interest in net (loss)/income:
Net (loss)/income from continuing operations $ (24 ) $ 2 $ (51 ) $ (15 )
Net (loss) from discontinued operations - (1 ) - (3 )
General partner’s interest in net (loss)/income $ (24 ) $ 1 $ (51 ) $ (18 )
Common unitholders’ interest in net (loss)/income:
Net (loss)/income from continuing operations $ (5,228 ) $ 445 $ (11,144 ) $ (3,088 )
Net (loss) from discontinued operations - (420 ) - (715 )
Common unitholders’ interest in net (loss)/income: $ (5,228 ) $ 25 $ (11,144 ) $ (3,803 )
Subordinated unitholders’ interest in net (loss)/income:
Net (loss)/income from continuing operations $ (457 ) $ 42 $ (979 ) $ (295 )
Net (loss) from discontinued operations - (40 ) - (69 )
Subordinated unitholders’ interest in net (loss)/income: $ (457 ) $ 2 $ (979 ) $ (364 )
Preferred unitholders’ interest in net income:
Net income from continuing operations $ 1,179 $ 1,644 $ 1,788 $ 4,118
Net income from discontinued operations - - - -
Preferred unitholders’ interest in net income $ 1,179 $ 1,644 $ 1,788 $ 4,118
Net (loss)/income per limited partner unit, basic:
Common units:
Net (loss)/income per unit from continuing operations $ (0.40 ) $ 0.03 $ (0.86 ) $ (0.24 )
Net (loss) per unit from discontinued operations - (0.03 ) - (0.05 )
Net (loss) per common unit, basic $ (0.40 ) $ - $ (0.86 ) $ (0.29 )
Subordinated units
Net (loss)/income per unit from continuing operations (0.40 ) $ 0.03 $ (0.86 ) $ (0.24 )
Net (loss) per unit from discontinued operations - (0.03 ) - (0.05 )
Net (loss) per subordinated unit, basic $ (0.40 ) $ - $ (0.86 ) $ (0.29 )
Preferred units
Net income per unit from continuing operations $ 0.79 $ 1.10 $ 1.19 $ 2.75
Net income per unit from discontinued operations - - - -
Net income per preferred unit, basic $ 0.79 $ 1.10 $ 1.19 $ 2.75
Net (loss)/income per limited partner unit, diluted:
Common units
Net (loss)/income per unit from continuing operations $ (0.40 ) $ 0.03 $ (0.86 ) $ (0.24 )
Net (loss) per unit from discontinued operations - (0.03 ) - (0.05 )
Net (loss) per common unit, diluted $ (0.40 ) $ - $ (0.86 ) $ (0.29 )
Subordinated units
Net (loss)/income per unit from continuing operations $ (0.40 ) $ 0.03 $ (0.86 ) $ (0.24 )
Net (loss) per unit from discontinued operations - (0.03 ) - (0.05 )
Net (loss) per subordinated unit, diluted $ (0.40 ) $ - $ (0.86 ) $ (0.29 )
Preferred units
Net income per unit from continuing operations $ 0.79 $ 1.10 $ 1.19 $ 2.75
Net income per unit from discontinued operations - - - -
Net income per preferred unit, diluted $ 0.79 $ 1.10 $ 1.19 $ 2.75

Weighted average number of limited partner units outstanding, basic:
Common units 13,098 12,994 13,035 12,942
Subordinated units 1,146 1,236 1,146 1,236
Preferred units 1,500 1,500 1,500 1,500
Weighted average number of limited partner units outstanding, diluted:
Common units 13,098 12,994 13,035 12,942
Subordinated units 1,146 1,236 1,146 1,236
Preferred units 1,500 1,500 1,500 1,500

	June 30,			December 31,
	2019			2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,592		$	6,172
Accounts receivable, net of allowance for doubtful accounts ($-0- and $0.7 million as of June 30, 2019 and December 31, 2018, respectively.)		22,595			15,126
Receivable-other		7,000			-
Inventories		11,747			6,573
Advance royalties, current portion		1,118			548
Investment in equity securities		-			1,872
Prepaid expenses and other		3,698			2,766
Total current assets		47,750			33,057
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs		452,998			450,888
Less accumulated depreciation, depletion and amortization		(287,855	)		(277,029	)
Net property, plant and equipment		165,143			173,859
Operating lease right-of-use assets (net)		12,759			-
Advance royalties, net of current portion		7,973			8,026
Deposits - Workers’ Compensation and Surety Programs		7,943			8,266
Other non-current assets		25,123			25,410
TOTAL	$	266,691		$	248,618
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	26,439		$	14,185
Accrued expenses and other		11,994			10,107
Accrued preferred distributions		600			3,210
Current portion of operating lease liabilities		3,211			-
Current portion of long-term debt		5,036			2,174
Current portion of asset retirement obligations		465			465
Total current liabilities		47,745			30,141
NON-CURRENT LIABILITIES:
Long-term debt, net		20,705			22,458
Asset retirement obligations, net of current portion		18,646			18,084
Operating lease liabilities, net of current portion		9,181			-
Other non-current liabilities		41,746			41,500
Total non-current liabilities		90,278			82,042
Total liabilities		138,023			112,183
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners		107,770			115,505
General partner		8,760			8,792
Preferred partners		15,000			15,000
Investment in Royal common stock (NOTE 11)		(4,126	)		(4,126	)
Common unit warrants		1,264			1,264
Total partners’ capital		128,668			136,435
TOTAL	$	266,691		$	248,618

See notes to unaudited condensed consolidated financial statements.

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(In thousands, except per unit data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
REVENUES:
Coal sales	$	65,092		$	54,245		$	122,955		$	108,517
Other revenues		496			678			1,371			1,206
Total revenues		65,588			54,923			124,326			109,723
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		59,756			49,592			114,403			99,245
Freight and handling costs		1,778			1,472			2,933			2,376
Depreciation, depletion and amortization		5,616			5,677			11,166			11,104
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)		3,475			2,800			6,217			5,496
(Gain) on sale/disposal of assets, net		(6,884	)		(3,496	)		(6,662	)		(6,434	)
Total costs and expenses		63,741			56,045			128,057			111,787
INCOME/(LOSS) FROM OPERATIONS		1,847			(1,122	)		(3,731	)		(2,064	)
INTEREST AND OTHER (EXPENSE)/INCOME:
Interest expense and other		(1,735	)		(1,913	)		(3,436	)		(3,798	)
Interest income and other		-			-			-			6
Total interest and other (expense)		(1,735	)		(1,913	)		(3,436	)		(3,792	)
INCOME/(LOSS) BEFORE INCOME TAXES		112			(3,035	)		(7,167	)		(5,856	)
INCOME TAXES		-			-			-			-
NET INCOME/(LOSS)		112			(3,035	)		(7,167	)		(5,856	)
Other comprehensive income:
Fair value adjustment for investment		-			198			-			4,380
Reclass for disposition		-			(3,977	)		-			(6,621	)
Total other comprehensive income		-			(3,779	)		-			(2,241	)
COMPREHENSIVE INCOME/(LOSS)	$	112		$	(6,814	)	$	(7,167	)	$	(8,097	)

General partner’s interest in net (loss)	$	(1	)	$	(14	)	$	(32	)	$	(27	)
Common unitholders’ interest in net (loss)	$	(172	)	$	(3,061	)	$	(7,114	)	$	(5,917	)
Subordinated unitholders’ interest in net (loss)	$	(15	)	$	(269	)	$	(621	)	$	(521	)
Preferred unitholders’ interest in net income	$	300		$	309		$	600		$	609
Net (loss)/income per limited partner unit, basic:
Common units	$	(0.01	)	$	(0.23	)	$	(0.54	)	$	(0.45	)
Subordinated units	$	(0.01	)	$	(0.23	)	$	(0.54	)	$	(0.45	)
Preferred units	$	0.20		$	0.21		$	0.40		$	0.41
Net (loss)/income per limited partner unit, diluted:
Common units	$	(0.01	)	$	(0.23	)	$	(0.54	)	$	(0.45	)
Subordinated units	$	(0.01	)	$	(0.23	)	$	(0.54	)	$	(0.45	)
Preferred units	$	0.20		$	0.21		$	0.40		$	0.41

Weighted average number of limited partner units outstanding, basic:
Common units		13,098			13,055			13,098			13,009
Subordinated units		1,143			1,146			1,144			1,146
Preferred units		1,500			1,500			1,500			1,500
Weighted average number of limited partner units outstanding, diluted:
Common units		13,098			13,055			13,098			13,009
Subordinated units		1,143			1,146			1,144			1,146
Preferred units		1,500			1,500			1,500			1,500

See notes to unaudited condensed consolidated financial statements.

RHINO RESOURCE PARTNERS LP
UNAUDITED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)

																	Accumulated
	Limited Partners										General			Preferred			Other					Total
	Common					Subordinated					Partner			Partner			Comprehensive					Partners’
	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
Net (loss)/income		-		(6,941	)		-		(606	)		(32	)		300			-		-			(7,279	)
Preferred partner distribution earned		-		-			-		-			-			(300	)		-		-			(300	)
BALANCE - March 31, 2019		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

																	Accumulated
	Limited Partners										General			Preferred			Other						Total
	Common					Subordinated					Partner			Partner			Comprehensive						Partners’
	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
Net (loss)/income		-		(2,856	)		-		(252	)		(13	)		300			-			-			(2,821	)
Preferred partner distribution earned		-		-			-		-			-			(300	)		-			-			(300	)
Reclass of disposition of Mammoth shares		-		-			-		-			-			-			(2,644	)		-			(2,644	)
Mark-to-market investment in Mammoth		-		-			-		-			-			-			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
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

See notes to consolidated financial statements.

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(inIn thousands)

	Nine Months Ended September 30,						Six Months Ended June 30,
	2018			2017			2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)	$	(10,386	)	$	(67	)	$	(7,167	)	$	(5,856	)
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		16,733			16,495			11,166			11,104
Accretion on asset retirement obligations		954			1,422			638			639
Amortization of advance royalties		502			876			1,032			378
Amortization of debt issuance costs		1,432			1,068			1,073			815
Provision for doubtful accounts		294			-
Amortization of debt discount		316			-			211			211
Equity in net loss/(income) of unconsolidated affiliates		-			(36	)
Reduction of deferred revenue								-			(189	)
Loss on retirement of advance royalties		108			136			225			108
(Gain) on sale/disposal of assets—net		(719	)		(40	)
(Gain)/loss on sale/disposal of assets—net								(6,229	)		64
(Gain) on sale of Mammoth shares		(6,498	)		-			(433	)		(6,498	)
Equity based compensation		230			260			-			230
Changes in assets and liabilities:
Accounts receivable		(5,223	)		(4,820	)		(7,469	)		5,148
Inventories		3,319			(3,285	)		(5,174	)		(3,001	)
Advance royalties		(904	)		(962	)		(1,774	)		(845	)
Prepaid expenses and other assets		(1,618	)		(1,923	)		(993	)		(1,480	)
Accounts payable		8,865			1,239			11,158			4,163
Accrued expenses and other liabilities		391			2,888			2,624			1,816
Asset retirement obligations		(259	)		(34	)		(76	)		(158	)
Net cash provided by operating activities		7,537			13,217
Net cash (used in)/provided by operating activities								(1,188	)		6,649
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment		(20,525	)		(14,306	)		(4,260	)		(16,000	)
Proceeds from sales of property, plant, and equipment		4,802			506			1,635			4,014
Proceeds from business disposal		-			890
Proceeds from sale of Mammoth shares		11,887			-			2,304			11,887
Net cash used in investing activities		(3,836	)		(12,910	)		(321	)		(99	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit		-			98,350
Repayments on line of credit		-			(98,450	)
Proceeds from short-term borrowing		5,000			-
Repayments on long-term debt		(10,208	)		-			(750	)		(10,222	)
Repayments on other debt								(522	)		(134	)
Repayments on finance leases								(2	)		-
Proceeds from issuance of other debt		1,622			-			1,772			1,329
Repayments on other debt		(540	)		-
Deposit for workers’ compensation and surety programs		(8,209	)		-			323			(5,209	)
Payments on debt issuance costs		(879	)		(227	)
Payments of debt issuance costs								(682	)		(629	)
Preferred distributions paid		(6,039	)		-			(3,210	)		(6,039	)
Net cash used in financing activities		(19,253	)		(327	)
Net cash (used in) financing activities								(3,071	)		(20,904	)
NET (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(15,552	)		(20	)		(4,580	)		(14,354	)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH—Beginning of period		21,120			47			6,172			21,120
CASH, CASH EQUIVALENTS AND RESTRICTED CASH—End of period	$	5,568		$	27		$	1,592		$	6,766

Summary Statement of Financial Position:
Cash and cash equivalents	$	5,568		$	27		$	1,592		$	3,114
Restricted cash		-			-			-			3,652
	$	5,568		$	27		$	1,592		$	6,766

See notes to unaudited condensed consolidated financial statements.

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF ~~SEPTEMBER~~JUNE 30, ~~2018~~2019 AND DECEMBER 31, ~~2017~~2018 AND FOR THE THREE AND ~~NINE~~SIX MONTHS ENDED ~~SEPTEMBER~~

JUNE 30, ~~2018~~2019 AND ~~2017~~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 ~~September~~June 30, ~~2018,~~2019, condensed consolidated statements of operations and comprehensive income for the three and ~~nine~~six months ended ~~September~~June 30, 2019 and 2018, consolidated statements of partners’ capital for the six months ended June 30, 2019 and ~~2017~~2018 and the condensed consolidated statements of cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~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, ~~2017~~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, ~~2017~~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, ~~2017~~2018 filed with the SEC.

~~Reclassifications.~~Certain prior year amounts have been reclassified to discontinued operations on the unaudited condensed consolidated statements of operations and comprehensive income related to the disposal of Sands Hill Mining LLC in 2017. See Note 3, “Discontinued Operations” for further information on the disposal.

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 ~~has increased~~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.”

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Revenue Recognition. The Partnership adopted ASU ~~2014-09, Topic 606~~2014-09-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 15 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, ~~and~~ the title or risk of loss has passed in accordance with the terms of the sales ~~agreement.~~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.

~~Investments~~Debt Issuance Costs. Debt issuance costs reflect fees incurred to obtain financing and are amortized (included in ~~Unconsolidated Affiliates.~~ ~~Investments in other entities are accounted for~~interest expense) using the ~~consolidation, equity~~straight-line method ~~or cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence~~ over the ~~operating and financial policies~~life of the ~~investee~~related debt, which approximates the effective interest method. Debt issuance costs are presented as a direct deduction from long-term debt as of June 30, 2019 and ~~whether~~December 31, 2018. The effective interest rate for the ~~Partnership is determined to be~~six months ended June 30, 2019 was 22.21% and 20.79% for the primary beneficiary of a variable interest entity. Equity investments are recorded at original cost and adjusted periodically to recognize the Partnership’s proportionate share of the investees’ net income or losses after the date of investment. Any losses from the Partnership’s equity method investments are absorbed by the Partnership based upon its proportionate ownership percentage. If losses are incurred that exceed the Partnership’s investment in the equity method entity, then the Partnership continues to record its proportionate share of losses in excess of its investment. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.six months ended June 30, 2018.

Recently Issued Accounting 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. ~~The Partnership has established an implementation team and is implementing a new lease accounting information system.~~ 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 ~~will adopt the standard~~adopted ASU 2016-02 in the first quarter of 2019 and ~~elect this~~elected the transition method to apply the standard ~~prospectively. While~~prospectively and also elected the “package of practical expedients” within the standard which permits the Partnership ~~is currently evaluating~~not to reassess its prior conclusions about lease identification, lease classification and initial direct costs. Additionally, the ~~impact of adoption of this ASU,~~Partnership made an election to not separate lease and non-lease components for all leases, and will not use hindsight. Finally, the ~~adoption is expected to result in~~Partnership will continue its current policy for accounting for land easements as executory contracts. The standard had a material ~~increase in~~impact on our unaudited condensed Consolidated Statements of Financial Position, but did not have an impact on our unaudited condensed Consolidated Statements of Operations and Comprehensive Income. Please refer to Note 5 for disclosures related to the ~~assets and liabilities recorded on the Condensed Consolidated Balance Sheets.~~new standard.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805).” ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership has adopted this standard on its unaudited condensed consolidated financial statements, which has no current period impact but may impact future periods in which acquisitions are completed.

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.

3. ~~DISCONTINUED OPERATIONS~~

~~Sands Hill Mining LLC~~

~~Major components of net (loss) from discontinued operations for the three and nine months ended September 30, 2018 and 2017 are summarized as follows:~~

Three Months Ended
September 30,

Nine Months Ended
September 30,

2018 2017 2018 2017
Major line items constituting (loss) from discontinued operations for the Sands Hill Mining disposal:
Coal sales $ - $ 194 $ - $ 1,131
Limestone sales - 1,003 - 3,089
Other revenues - 462 - 1,294
Total revenues - 1,659 - 5,514

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) - 1,704 - 5,128
Depreciation, depletion and amortization - 127 - 458
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above) - 8 - 34
Freight and handling costs 281 - 683
(Gain) on sale/disposal of assets, net - - - (2 )
Total costs and expenses - 2,120 - 6,301
(Loss) from discontinued operations before income taxes for the Sands Hill Mining disposal - (461 ) - (787 )
Income taxes - - - -
Net (loss) from discontinued operations $ - $ (461 ) $ - $ (787 )

~~Cash Flows~~

The depreciation, depletion and amortization amounts for Sands Hill Mining LLC for each period presented are listed in the previous table. The Partnership did not fund any material capital expenditures for Sands Hill Mining LLC for any period presented. Sands Hill Mining LLC did not have any material non-cash operating items or non-cash investing items for any period presented.

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:

					June 30,		December 31,
	September 30, 2018		December 31, 2017		2019		2018
	(in thousands)				(in thousands)
Other prepaid expenses	$	1,340	$	920	$	1,142	$	971
Prepaid insurance		1,890		1,445		2,151		1,397
Prepaid leases		127		92		99		92
Supply inventory		306		434		306		306
Total Prepaid expenses and other	$	3,663	$	2,891
Total					$	3,698	$	2,766

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 June 30, 2019, the $7.0 million receivable was recorded in Receivable –Other on the Partnership’s unaudited condensed consolidated statements of financial position and a gain of $6.9 million was recorded on the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

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 consolidated statements of financial position. During the three months ended March 31, 2019, the Partnership sold its 104,100 shares for net consideration of approximately $2.3 million.

5.4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018 are summarized by major classification as follows:

	Useful Lives	September 30, 2018			December 31, 2017				June 30,			December 31,
		(in thousands)						Useful Lives	2019			2018
Land		$	13,783		$	14,687
									(in thousands)
Land and land improvements									$	10,416		$	13,181
Mining and other equipment and related facilities	2 - 20 Years		305,595			298,293		2 - 20 Years		311,197			307,300
Mine development costs	1 - 15 Years		60,422			58,566		1 - 15 Years		64,757			63,681
Coal properties	1 - 15 Years		64,070			64,070		1 - 15 Years		63,461			63,527
Construction work in process			6,437			5,227				3,167			3,199
Total			450,307			440,843				452,998			450,888
Less accumulated depreciation, depletion and amortization			(273,518	)		(263,520	)			(287,855	)		(277,029	)
Net		$	176,789		$	177,323			$	165,143		$	173,859

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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017		2019		2018		2019		2018
	(in thousands)								(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	4,276	$	3,843	$	12,607	$	12,324	$	4,216	$	4,244	$	8,380	$	8,331
Depletion expense for coal properties and oil and natural gas properties		467		450		1,419		1,221
Depletion expense for coal properties										482		481		948		953
Amortization expense for mine development costs		777		721		2,348		2,265		843		821		1,687		1,570
Amortization expense for asset retirement costs		109		46		359		227		75		131		151		250
Total depreciation, depletion and amortization	$	5,629	$	5,060	$	16,733	$	16,037
Total									$	5,616	$	5,677	$	11,166	$	11,104

5. LEASES

~~On May 17, 2018,~~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 ~~entered into a sale leaseback agreement with Wintrust Commercial~~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. Finance leases are included in plant, property and equipment, current liabilities and long-term liabilities.

ROU assets represent the Partnership’s right to use an underlying asset for ~~certain equipment previously owned by~~ the ~~Partnership. The Partnership received approximately $3.7 million~~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 ~~proceeds, of which $1.7 million was used to reduce debt. The~~ lease ~~agreement has a thirty-six month~~payments over the lease term. The Partnership ~~recorded a loss of $0.2 million on~~utilizes the ~~sale~~implicit rate in the lease, if determinable, at the commencement date of the ~~equipment which~~lease to determine the present value of the lease payments. If the implicit rate is ~~included~~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 ~~(Gain)/Loss on sale/disposal~~lease term.

Supplemental information related to leases was as follows:

	Six months ended June 30, 2019
	(in thousands)
Operating leases
Operating lease right-of use assets	$	12,759

Operating lease liabilities-current	$	3,211
Operating lease liabilities-long-term		9,181
Total operating lease liabilities	$	12,392

Finance leases
Property. Plant and Equipment, gross	$	10
Accumulated depreciation		(2	)
Total Property, Plant and Equipment, net	$	8

Finance leases - current portion	$	4
Finance leases - noncurrent portion		3
Total finance lease obligation	$	7

Weighted Average Discount Rates and Lease Terms

	Six months ended June 30, 2019
Weighted Average Discount Rate

Operating leases		7.0	%
Finance leases		7.0	%

Weighted Average Lease Term
Operating leases		5.45 years
Finance leases		2.25 years

Supplemental cash flow information related to leases was as follows:

	Six months ended June 30, 2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	1,950
Operating cash flows for finance leases	$	-
Financing cash flows for finance leases	$	2

Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	13,896
Finance leases	$	10

Maturities of ~~assets-net line in the Partnership’s unaudited condensed consolidated statements~~lease liabilities are as follows:

	Operating leases		Finance leases
	(in thousands)
Year ending December 31,
2019(excluding the six months ended June 30, 2019)	$	2,011	$	3
2020		3,444		4
2021		2,561		-
2022		1,031		-
2023		912		-
Thereafter		2,878		-
Total lease payments		12,837		7
Less imputed interest		445		-
Total	$	12,392	$	7

The components of ~~operations and comprehensive income.~~lease expense were as follows:

	Three months ended June 30, 2019		Six months ended June 30, 2019
	(in thousands)

Operating lease cost	$	983	$	1,966

Finance lease cost:
Amortization of right-of-use assets	$	1	$	2
Interest on lease liabilities		-		-
Total finance lease cost	$	1	$	2

6. OTHER NON-CURRENT ASSETS

Other non-current assets as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:

							June 30,			December 31,
	September 30, 2018			December 31, 2017			2019			2018
	(in thousands)						(in thousands)
Deposits and other	$	1,260		$	423		$	864		$	1,144
Due (to)/from Rhino GP		(30	)		(61	)
Due (to) Rhino GP								(77	)		(84	)
Non-current receivable		27,806			27,806			24,192			24,192
Deferred expenses		318			340			144			158
Total	$	29,354		$	28,508		$	25,123		$	25,410

Non-current receivable. The non-current receivable balance of ~~$27.8~~$24.2 million as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~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 ~~$27.8~~$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. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:

					June 30,		December 31,
	September 30, 2018		December 31, 2017		2019		2018
	(in thousands)				(in thousands)
Payroll, bonus and vacation expense	$	1,988	$	2,633	$	2,595	$	2,151
Non income taxes		2,878		2,738
Non-income taxes						3,066		2,168
Royalty expenses		1,713		2,410		2,230		1,669
Accrued interest		161		132		53		35
Health claims		746		871		857		868
Workers’ compensation & pneumoconiosis		1,750		1,750		1,900		1,900
Other		1,280		652		1,293		1,316
Total	$	10,516	$	11,186	$	11,994	$	10,107

8. DEBT

Debt as of ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:

	September 30, 2018			December 31, 2017			June 30,			December 31,
	(in thousands)						2019			2018
Note payable-Financing Agreement	$	34,778		$	40,000
							(in thousands)
Note payable -Financing Agreement							$	28,298		$	29,048
Note payable-other debt		1,095			-			1,772			522
Finance lease obligation								7			-
Net unamortized debt issuance costs		(4,135	)		(4,688	)		(3,704	)		(4,095	)
Net unamortized original issue discount		(948	)		(1,264	)		(632	)		(843	)
Total		30,790			34,048			25,741			24,632
Less current portion		(7,595	)		(5,475	)		(5,036	)		(2,174	)
Long-term debt	$	23,195		$	28,573		$	20,705		$	22,458

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 an additional ~~$40~~$35 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). Loans made pursuant to the Financing Agreement are secured by substantially all of the Borrowers’ and Guarantors’ assets. The Financing Agreement terminates on December 27, 2020.

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 due on December 27, 2020. 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 September 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. The Partnership entered into a warrant agreement with certain parties that are also parties to the Financing Agreement discussed above. (See Note 11 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.

~~At September 30,~~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 ~~$29.8~~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 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.

On 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.

At June 30, 2019, the Partnership had $28.3 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% ~~(12.25%) and $5.0 million of borrowings outstanding at a fixed interest rate of 12.34%.~~

~~Letter of Credit Facility-PNC Bank~~

On December 27, 2017, the Partnership entered into a master letter of credit facility, security agreement and reimbursement agreement (the “LoC Facility Agreement”) with PNC Bank, National Association (“PNC”), pursuant to which PNC agreed to provide the Partnership with a facility for the issuance of standby letters of credit used in the ordinary course of its business (the “LoC Facility”(12.41%). The LoC Facility Agreement provided that the Partnership pay a quarterly fee at a rate equal to 5% per annum calculated based on the daily average of letters of credit outstanding under the LoC Facility, as well as administrative costs incurred by PNC and a $100,000 closing fee. The LoC Facility Agreement provided that the Partnership reimburse PNC for any drawing under a letter of credit by a specified beneficiary as soon as possible after payment was made. The Partnership’s obligations under the LoC Facility Agreement were secured by a first lien security interest on a cash collateral account that was required to contain no less than 105% of the face value of the outstanding letters of credit. In the event the amount in such cash collateral account was insufficient to satisfy the Partnership’s reimbursement obligations, the amount outstanding would bear interest at a rate per annum equal to the Base Rate (as that term was defined in the LoC Facility Agreement) plus 2.0%. The Partnership was to indemnify PNC for any losses which PNC may have incurred as a result of the issuance of a letter of credit or PNC’s failure to honor any drawing under a letter of credit, subject in each case to certain exceptions. The Partnership provided cash collateral to its counterparties during the third quarter of 2018 and as of September 30, 2018, the LoC Facility was terminated. The Partnership had no outstanding letters of credit at September 30, 2018.

9. ASSET RETIREMENT OBLIGATIONS

The changes in asset retirement obligations for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and the year ended December 31, ~~2017~~2018 are as follows:

	Nine months ended			Year ended
	September 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Balance at beginning of period (including current portion)	$	18,662		$	19,108		$	18,549		$	18,662
Accretion expense		954			1,493			638			1,269
Adjustment resulting from disposal of property		-			(223	)
Adjustments to the liability from annual recosting and other		-			(1,656	)		-			(1,083	)
Liabilities settled		(259	)		(60	)		(76	)		(299	)
Balance at end of period		19,357			18,662			19,111			18,549
Less current portion of asset retirement obligation		(498	)		(498	)		(465	)		(465	)
Long-term portion of asset retirement obligation	$	18,859		$	18,164		$	18,646		$	18,084

10. 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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~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
September 30,

Nine months ended
September 30,

2018 2017 2018 2017
(in thousands)
401(k) plan expense $ 459 $ 376 $ 1,288 $ 1,070

	Three Months Ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(in thousands)
401(k) plan expense	$	470	$	393	$	959	$	829

11. 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 ~~where~~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 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 in~~discount on Long-term debt, net on the Partnership’s consolidated statements of financial position.

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, the 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, the Partnership paid the holders of Series A preferred units $6.0 million in distributions earned for the year ended December 31, ~~2017 to holders of the Series A preferred units.~~2017. The Partnership has accrued ~~$1.8~~approximately $0.6 million for distributions to holders of the Series A preferred units for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~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

~~On April 12, 2018 the Partnership sold 232,347 shares of Mammoth Energy Services, Inc. (NASDAQ: TUSK)~~In accordance with Accounting Standards Codification (“~~Mammoth Inc.”~~ASU”) 2016-01, which was effective for net cash consideration of $7.1 million. The Partnership used $3.4 million of the proceeds to reduce its debt balance. The Partnership recorded a gain on the sale of approximately $3.6 million and reduced Other Comprehensive income by $4.0 million as a result of the disposition. On January 19, 2018 the Partnership sold 232,347 shares of Mammoth Inc. for net cash consideration of $4.8 million. The proceeds were used to reduce the Partnership’s debt balance. The Partnership recorded a gain on the sale of $2.9 million and reduced Other Comprehensive income by $2.6 million as a result of the disposition. As of September 30, 2018 andfiscal years that began after December ~~31,~~15, 2017, the Partnership ~~recorded~~ceased recording fair market ~~value~~ adjustments ~~of $3.9 million and $2.6 million, respectively,~~ for ~~its available-for-sale investment in Mammoth Inc. based on the market value of~~ the shares at September 30, 2018 and December 31, 2017, respectively, which was recorded in Other Comprehensive Income. As of September 30, 2018 and December 31, 2017, the Partnership recorded its investment in Mammoth Inc. as a current asset, which was classified as available-for-sale. The Partnership has included its investmentit owns in Mammoth Inc. in ~~its~~ Other ~~category for segment reporting purposes. As~~Comprehensive Income during the fourth quarter of ~~September 30,~~2018. Upon adoption during the fourth quarter of 2018, the Partnership ~~owned 104,100~~recorded a $4.2 million reclassification from Other Comprehensive Income to Partners’ Capital relating to its Mammoth Inc. shares ~~of Mammoth Inc.~~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 ~~September 30, 2018,~~March 31, 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 ~~September~~June 30, ~~2018,~~2019, the Partnership had accumulated arrearages of ~~$614.5~~$790.2 million.

12. 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 ~~September~~June 30, ~~2018~~2019 and ~~2017:~~2018:

Three Months Ended June 30, 2019	General Partner			Common Unitholders			Subordinated Unitholders			Preferred Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/ income	$	(1	)	$	(172	)	$	(15	)	$	300

Denominator:
Weighted average units used to compute basic EPU		n/a			13,098			1,143			1,500
Weighted average units used to compute diluted EPU		n/a			13,098			1,143			1,500

Net (loss)/income per limited partner unit, basic:		n/a		$	(0.01	)	$	(0.01	)	$	0.20
Net (loss)/income per limited partner unit, diluted		n/a		$	(0.01	)	$	(0.01	)	$	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 $ (24 ) $ (5,228 ) $ (457 ) $ 1,179
Net(loss)/income from discontinued operations - - - -
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 $ (0.40 ) $ (0.40 ) $ 0.79
Net(loss/income) per unit from discontinued operations n/a - - -
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 $ (0.40 ) $ (0.40 ) 0.79
Net (loss)/income per unit from discontinued operations n/a - - -
Net (loss)/income per common unit, diluted n/a $ (0.40 ) $ (0.40 ) 0.79

Three Months Ended June 30, 2018	General Partner			Common Unitholders			Subordinated Unitholders			Preferred Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income	$	(14	)	$	(3,061	)	$	(269	)	$	309

Denominator:
Weighted average units used to compute basic EPU		n/a			13,055			1,146		$	1,500
Weighted average units used to compute diluted EPU		n/a			13,055			1,146		$	1,500

Net (loss)/income per limited partner unit, basic		n/a		$	(0.23	)	$	(0.23	)	$	0.21
Net (loss)/income per limited partner unit, diluted		n/a		$	(0.23	)	$	(0.23	)	$	0.21

Three months ended September 30, 2017 General
Partner Common Unitholders Subordinated Unitholders Preferred Unitholders
(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net income from continuing operations $ 2 $ 445 $ 42 $ 1,644
Net (loss) from discontinued operations (1 ) (420 ) (40 ) -
Total interest in net income $ 1 $ 25 $ 2 1,644
Denominator:
Weighted average units used to compute basic EPU n/a 12,994 1,236 1,500
Weighted average units used to compute diluted EPU n/a 12,994 1,236 1,500

Net (loss)/income per limited partner unit, basic
Net (loss)/income per unit from continuing operations n/a $ 0.03 $ 0.03 $ 1.10
Net (loss) per unit from discontinued operations n/a (0.03 ) (0.03 ) -
Net (loss)/income per common unit, basic n/a $ - $ - $ 1.10
Net (loss)/income per limited partner unit, diluted
Net (loss)/income per unit from continuing operations n/a $ 0.03 $ 0.03 $ 1.10
Net (loss) per unit from discontinued operations n/a (0.03 ) (0.03 ) -
Net (loss)/income per common unit, diluted n/a $ - $ - $ 1.10

Six Months Ended June 30, 2019	General Partner			Common Unitholders			Subordinated Unitholders			Preferred Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/ income	$	(32	)	$	(7,114	)	$	(621	)	$	600

Denominator:
Weighted average units used to compute basic EPU		n/a			13,098			1,144			1,500
Weighted average units used to compute diluted EPU		n/a			13,098			1,144			1,500

Net (loss)/income per limited partner unit, basic:		n/a		$	(0.54	)	$	(0.54	)	$	0.40
Net (loss)/income per limited partner unit, diluted		n/a		$	(0.54	)	$	(0.54	)	$	0.40

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 $ (51 ) $ (11,144 ) $ (979 ) $ 1,788
Net (loss)/income from discontinued operations - - - -
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 $ (0.86 ) $ (0.86 ) $ 1.19
Net (loss)/income per unit from discontinued operations n/a - - -
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 $ (0.86 ) $ (0.86 ) 1.19
Net (loss)/income per unit from discontinued operations n/a - - -
Net (loss)/income per common unit, diluted n/a $ (0.86 ) $ (0.86 ) 1.19
Nine months ended September 30, 2017 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 $ (15 ) $ (3,088 ) $ (295 ) 4,118
Net (loss) from discontinued operations (3 ) (715 ) (69 ) -
Total interest in net (loss)/income $ (18 ) $ (3,803 ) $ (364 ) 4,118
Denominator:
Weighted average units used to compute basic EPU n/a 12,942 1,236 1,500
Weighted average units used to compute diluted EPU n/a 12,942 1,236 1,500

Net (loss)/income per limited partner unit, basic
Net (loss)/income per unit from continuing operations n/a $ (0.24 ) $ (0.24 ) $ 2.75
Net (loss) per unit from discontinued operations n/a (0.05 ) (0.05 ) -
Net (loss)/income per common unit, basic n/a $ (0.29 ) $ (0.29 ) $ 2.75
Net (loss)/income per limited partner unit, diluted
Net (loss)/income per unit from continuing operations n/a $ (0.24 ) $ (0.24 ) $ 2.75
Net (loss) per unit from discontinued operations n/a (0.05 ) (0.05 ) -
Net (loss)/income per common unit, diluted n/a $ (0.29 ) $ (0.29 ) $ 2.75

Six Months Ended June 30, 2018	General Partner			Common Unitholders			Subordinated Unitholders			Preferred Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income	$	(27	)	$	(5,917	)	$	(521	)	$	609

Denominator:
Weighted average units used to compute basic EPU		n/a			13,009			1,146		$	1,500
Weighted average units used to compute diluted EPU		n/a			13,009			1,146		$	1,500

Net (loss)/income per limited partner unit, basic		n/a		$	(0.45	)	$	(0.45	)	$	0.41
Net (loss)/income per limited partner unit, diluted		n/a		$	(0.45	)	$	(0.45	)	$	0.41

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 ~~loss~~losses for three ~~and nine~~ months ended ~~September~~June 30, 2018 and for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~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. The Partnership earned ~~total~~ net income for the three months ended ~~September~~June 30, ~~2017~~2019, but did not have any potential dilutive units outstanding during the period. There were 683,888 potential dilutive common units related to the Common Unit Warrants as discussed in Note 11 for the ~~nine~~six months ended ~~September~~June 30, 2019 and 2018.

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of ~~September~~June 30, ~~2018,~~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
2018 Q4		1,283		14
2019		2,107		10
2019 Q3-Q4					2,192	18
2020		1,446		6	2,180	7
2021					920	3

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

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 ~~of $31,000~~ from coal purchase contracts or expense from OTC purchases for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~no purchase coal expense for the three and nine months ended September 30, 2017.~~2018.

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. Please read Note 5 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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~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 September 30,				Nine months ended September 30,				Three Months Ended June 30,				Six months ended June 30,
	2018		2017		2018		2017		2019		2018		2019		2018
	(in thousands)								(in thousands)
Lease expense	$	1,242	$	725	$	2,648	$	3,198	$	1,302	$	976	$	2,556	$	1,406
Royalty expense	$	3,320	$	3,602	$	10,431	$	10,888	$	4,289	$	3,467	$	8,182	$	7,111

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 June 30, 2019. The Partnership had outstanding surety bonds with third parties of $39.2 million as of June 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 $39.2 million, approximately $0.4 million relates to surety bonds for Deane Mining, LLC, which have not been transferred or replaced by the buyer of Deane Mining LLC as was agreed to by the parties as part of the transaction. The Partnership can provide no assurances that a surety company will underwrite the surety bonds of the purchaser of 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 buyer of Deane Mining, LLC, the Partnership may be responsible to the surety company for any amounts it pays in respect of such claim. While the buyer is required to indemnify the Partnership for damages, including reclamation liabilities, pursuant the agreements governing the sales of this entity, the Partnership may not be successful in obtaining any indemnity or any amounts received may be inadequate. Of the $39.2 million in outstanding surety bonds, approximately $3.4 million related to surety bonds for Sands Hill Mining LLC, which are to be replaced by a third party pursuant to an agreement dated July 9, 2019 (see Note 19 for additional discussion).

14. MAJOR CUSTOMERS

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

	September 30,		December 31,		Nine months		Nine months
	2018		2017		ended		ended
	Receivable		Receivable		September 30,		September 30,
	Balance		Balance		2018 Sales		2017 Sales		June 30, 2019 Receivable Balance		December 31, 2018 Receivable Balance		Six months ended June 30, 2019 Sales		Six months ended June 30, 2018 Sales
	(in thousands)								(in thousands)
Javelin Global	$	4,628	$	2,470	$	29,267	$	-	$	3,816	$	4,347	$	24,527	$	16,554
Integrity Coal									$	-	$	937	$	3,939	$	11,364
Dominion Energy		593		1,232		17,166		17,148	$	683	$	-	$	3,826	$	14,013
Integrity Coal		-		2,238		15,534		18,152
Big Rivers Electric Corporation		642		-		15,586		18,387
LG&E		700		1,483		10,309		30,971

15. 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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017.~~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~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017.~~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, ~~prices are fixed or determinable and~~ the title or risk of loss has passed in accordance with the terms of the coal sales ~~agreement.~~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 ~~September~~June 30, ~~2018:~~2019:

	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated		Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated
	(in thousands)												(in thousands)
Coal sales
Steam coal	$	13,979	$	5,229	$	10,254	$	12,529	$	-	$	41,991	$	9,749	$	8,396	$	8,422	$	13,088	$	-	$	39,655
Met coal		29,875		-		-		-		-		29,875		25,437		-		-		-		-		25,437
Other revenue		36		602		-		-		61		699		36		460		-		-		-		496
Total	$	43,890	$	5,831	$	10,254	$	12,529	$	61	$	72,565	$	35,222	$	8,856	$	8,422	$	13,088	$	-	$	65,588

The following table disaggregates revenue by type for each reportable segment for the three months ended ~~September~~June 30, ~~2017:~~2018:

	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated		Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated
	(in thousands)												(in thousands)
Coal sales
Steam coal	$	9,580	$	4,361	$	9,080	$	14,960	$	-	$	37,981	$	13,200	$	3,904	$	8,656	$	13,608	$	-	$	39,368
Met coal		18,285		-		-		-		-		18,285		14,877		-		-		-		-		14,877
Other revenue		27		377		-		5		11		420		56		517		-		-		105		678
Total	$	27,892	$	4,738	$	9,080	$	14,965	$	11	$	56,686	$	28,133	$	4,421	$	8,656	$	13,608	$	105	$	54,923

The following table disaggregates revenue by type for each reportable segment for the ~~nine~~six months ended ~~September~~June 30, ~~2018:~~2019:

	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated		Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated
	(in thousands)												(in thousands)
Coal sales
Steam coal	$	38,840	$	12,821	$	26,970	$	37,748	$	-	$	116,379	$	23,138	$	14,461	$	17,132	$	26,089	$	-	$	80,820
Met coal		64,004		-		-		-		-		64,004		42,135		-		-		-		-		42,135
Other revenue		154		1,576		10		-		166		1,906		357		1,014		-		-		-		1,371
Total	$	102,998	$	14,397	$	26,980	$	37,748	$	166	$	182,289	$	65,630	$	15,475	$	17,132	$	26,089	$	-	$	124,326

The following table disaggregates revenue by type for each reportable segment for the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2018:

Central Appalachia Northern Appalachia Rhino Western Illinois
Basin Other Total Consolidated
(in thousands)
Coal sales
Steam coal $ 26,634 $ 10,544 $ 25,138 $ 49,373 $ - $ 111,689
Met coal 50,131 - - - - 50,131
Other revenue 114 955 3 5 21 1,098
Total $ 76,879 $ 11,499 $ 25,141 $ 49,378 $ 21 $ 162,918

	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated
	(in thousands)
Coal sales
Steam coal	$	24,861	$	7,592	$	16,716	$	25,219	$	-	$	74,388
Met coal		34,129		-		-		-		-		34,129
Other revenue		118		974		9		-		105		1,206
Total	$	59,108	$	8,566	$	16,725	$	25,219	$	105	$	109,723

16. 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 ~~September~~June 30, ~~2018.~~2019. The fair value of the Partnership’s Financing Agreement is a Level 2 measurement.

As of ~~September 30, 2018 and~~ December 31, ~~2017,~~2018, the Partnership had a recurring fair value measurement relating to its investment in Mammoth Inc. As discussed in Note ~~11,~~5, the Partnership ~~owned 104,100 shares~~sold the balance of its Mammoth Inc. asshares (104,100 shares) during the first quarter of ~~September 30, 2018.~~2019. The Partnership’s shares of Mammoth Inc. ~~are~~were classified as an ~~available-for-sale~~ investment on the Partnership’s unaudited condensed consolidated statements of financial ~~position.~~position as of December 31, 2018. Based on the availability of a quoted price, the recurring fair value measurement of the Mammoth Inc. shares iswas a Level 1 measurement.

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash payments for interest were ~~$4.9~~$2.2 million and ~~$2.1~~$2.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

The unaudited condensed consolidated statement of cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017~~2018 excludes approximately ~~$1.1~~$2.3 million and ~~$1.3~~$1.6 million, respectively, of property, plant and equipment additions which are recorded in Accounts payable.

18. 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 ~~September~~June 30, ~~2018,~~2019, the Partnership has four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois Basin. Additionally, the Partnership has an Other category that includes its ancillary businesses.

~~Held for sale assets are included in the applicable segment for reporting purposes.~~ 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 ~~September~~June 30, ~~2018~~2019 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

	Central		Northern			Rhino		Illinois						Total
	Appalachia		Appalachia			Western		Basin			Other			Consolidated			Central Appalachia		Northern Appalachia			Rhino Western		Illinois Basin			Other			Total Consolidated
	(in thousands)																(in thousands)
Total revenues	$	43,890	$	5,831		$	10,255	$	12,529		$	60		$	72,565		$	35,222	$	8,856		$	8,422	$	13,088		$	-		$	65,588
DD&A		2,200		385			978		1,974			92			5,629			1,863		434			1,109		2,122			88			5,616
Interest expense		-		-			-		-			2,831			2,831			-		-			-		-			1,735			1,735
Net income (loss) from continuing operations	$	3,619	$	(881	)	$	56	$	(3,232	)	$	(4,092	)	$	(4,530	)
Net Income/(loss)																	$	6,560	$	(692	)	$	1,321	$	(2,760	)	$	(4,317	)	$	112

Reportable segment results of operations for the three months ended ~~September~~June 30, ~~2017~~2018 are as follows:

	Central		Northern			Rhino		Illinois					Total
	Appalachia		Appalachia			Western		Basin		Other			Consolidated		Central Appalachia		Northern Appalachia			Rhino Western			Illinois Basin			Other			Total Consolidated
	(in thousands)														(in thousands)
Total revenues	$	27,891	$	4,738		$	9,080	$	14,965	$	12		$	56,686	$	28,133	$	4,422		$	8,656		$	13,608		$	104		$	54,923
DD&A		1,890		251			1,080		1,755		84			5,060		2,263		300			1,041			1,979			94			5,677
Interest expense		-		-			-		-		1,011			1,011		-		-			-			-			1,913			1,913
Net income (loss) from continuing operations	$	3,785	$	(449	)	$	1,416	$	107	$	(2,726	)	$	2,133
Net Income/(loss)															$	997	$	(1,477	)	$	(63	)	$	(1,880	)	$	(612	)	$	(3,035	)

Reportable segment results of operations for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 are as follows:

	Central		Northern			Rhino		Illinois						Total
	Appalachia		Appalachia			Western		Basin			Other			Consolidated			Central Appalachia		Northern Appalachia			Rhino Western		Illinois Basin			Other			Total Consolidated
	(in thousands)																(in thousands)
Total revenues	$	102,998	$	14,397		$	26,980	$	37,748		$	166		$	182,289		$	65,630	$	15,475		$	17,132	$	26,089		$	-		$	124,326
DD&A		6,659		825			3,080		5,892			277			16,733			3,763		842			2,203		4,180			178			11,166
Interest expense		1		-			-		-			6,628			6,629			-		-			-		-			3,436			3,436
Net income (loss) from continuing operations	$	5,546	$	(3,473	)	$	956	$	(7,441	)	$	(5,974	)	$	(10,386	)
Net Income/(loss)																	$	7,743	$	(1,814	)	$	993	$	(6,347	)	$	(7,742	)	$	(7,167	)

Reportable segment results of operations for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 are as follows:

	Central		Northern			Rhino		Illinois					Total
	Appalachia		Appalachia			Western		Basin		Other			Consolidated		Central Appalachia		Northern Appalachia			Rhino Western		Illinois Basin			Other			Total Consolidated
	(in thousands)														(in thousands)
Total revenues	$	76,880	$	11,500		$	25,141	$	49,377	$	20		$	162,918	$	59,108	$	8,566		$	16,725	$	25,219		$	105		$	109,723
DD&A		5,812		836			3,396		5,708		285			16,037		4,459		441			2,102		3,918			184			11,104
Interest expense		-		-			-		-		3,131			3,131		1		-			-		-			3,797			3,798
Net income (loss) from continuing operations	$	9,416	$	(2,480	)	$	1,570	$	1,736	$	(9,522	)	$	720
Net Income/(loss)															$	1,927	$	(2,592	)	$	900	$	(4,209	)	$	(1,882	)	$	(5,856	)

19. SUBSEQUENT EVENTS

On ~~November 8, 2018,~~July 9, 2019, the Partnership entered into an agreement with a ~~consent~~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 for the Partnership’s release of the surety bond obligations. At the time of closing, the third party delivered to the Partnership confirmation from its ~~Lenders~~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 ~~the Financing Agreement. The consent~~Sands Hill Mining LLC, which includes ~~the lenders agreement to waive any Event~~a release of ~~Default that arose or would otherwise arise under the Financing Agreement for failing to comply with the Fixed Charge Coverage Ratio~~all applicable collateral for the ~~six months ended September 30, 2018.~~surety bond obligations. Further, such confirmation from the surety underwriter was specifically provided for their acceptance of the third party as a replacement obligor.

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, ~~2017~~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, ~~2017.~~

On November 7, 2017, we closed an agreement with a third party to transfer 100% of the membership interests and related assets and liabilities in our Sands Hill Mining entity to the third party in exchange for a future override royalty for any mineral sold, excluding coal, from Sands Hill Mining after the closing date. Our unaudited condensed consolidated statement of operations and comprehensive income have been retrospectively adjusted to reclassify our Sands Hill Mining operation to discontinued operations for the three and nine months ended September 30, 2017.2018.

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. Our investments have included joint ventures that provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in joint ventures that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.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, ~~2017,~~2018, we controlled an estimated ~~252.7~~268.5 million tons of proven and probable coal reserves, consisting of an estimated ~~200.1~~214.0 million tons of steam coal and an estimated ~~52.6~~54.5 million tons of metallurgical coal. In addition, as of December 31, ~~2017,~~2018, we controlled an estimated ~~185.2~~164.1 million tons of non-reserve coal deposits.

We operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate may vary from time to time depending on a number of factors, including 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~~six months ended ~~September~~June 30, ~~2018,~~2019, we generated revenues of approximately ~~$72.6~~$65.6 million and ~~$182.3~~$124.3 million, respectively, and we generated net ~~losses~~income of ~~$4.5 million and $10.4~~approximately $0.1 million for the three ~~and nine~~ months ended ~~September~~June 30, ~~2018.~~2019 and a net loss of approximately $7.2 million for the six months ended June 30, 2019. For the three months ended ~~September~~June 30, ~~2018,~~2019, we produced approximately ~~1.1~~1.2 million tons of coal and sold approximately ~~1.3~~1.1 million tons of coal, of which approximately ~~60%~~85% were sold pursuant to supply contracts. For the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, we produced ~~approximately 3.3~~2.3 million tons of coal and sold approximately ~~3.4~~2.2 million tons of coal, of which approximately ~~65%~~87% were sold pursuant to supply contracts.

Current Liquidity and Outlook

As of ~~September~~June 30, ~~2018,~~2019, our available liquidity was ~~$5.6~~$1.6 million. We also have a delayed draw term loan commitment in the amount of ~~$40~~$35 million ~~(under which we have drawn approximately $5 million)~~ contingent upon the satisfaction of certain conditions precedent specified in ~~the Financing Agreement~~our 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 an additional ~~$40~~$35 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. We used approximately $17.3 million of the net proceeds thereof to repay all amounts outstanding and terminate the ~~Amended~~amended and ~~Restated Credit Agreement~~restated credit agreement with PNC Bank, National Association, as Administrative Agent. The Financing Agreement terminates on December 27, 2020. For more information about our ~~new~~ Financing Agreement, please read “— Liquidity and Capital Resources—Financing Agreement.”

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

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. At June 30, 2019, the $7.0 million receivable was recorded in Receivable –Other on our unaudited condensed consolidated statements of financial position and a gain of $6.9 million was recorded on our unaudited condensed consolidated statements of operations and comprehensive income.

Financing Agreement

On ~~December 27, 2017,~~May 8, 2019, 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”third amendment (“Third Amendment”), pursuant to which Lenders agreed to provide us with a multi-draw term loan in the aggregate principal amount of $80 million, subject to the terms and conditions set forth in the Financing Agreement. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement (the “Effective Date Term Loan Commitment”) and an additional $40 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). Loans made pursuant to the Financing Agreement are secured by substantially all of our assets. The Financing Agreement terminates on December 27, 2020. For more information about our new Financing Agreement, please read “— Liquidity and Capital Resources—Financing Agreement.”

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

~~On July 27, 2018, 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~~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 ~~September 30, 2018.~~

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 below and this Third~~Common Unit Warrants~~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.

~~In December 2017,~~On February 13, 2019, we entered into a ~~warrant agreement with certain parties that are also parties~~second amendment (“Amendment”) to the Financing ~~Agreement discussed above.~~Agreement. The ~~warrant agreement included~~Amendment provided the ~~issuance of~~Lender’s consent for us to pay a ~~total of 683,888 warrants of our common units (“Common Unit Warrants”) at an exercise price of $1.95 per unit, which was the closing price of our common units~~one-time cash distribution on the OTC market as of December 27, 2017. The Common Unit Warrants have a five year expiration date. The Common Unit Warrants and our 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 dilutiveFebruary 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 ~~Rhino’s common units outstanding. The warrant agreement includes a provision for a cashless exercise where the warrant holders can receive a net number~~Default that has or would otherwise arise under Section 9.01(c) of ~~common units. Per the warrant agreement, the warrants are detached from~~ the Financing Agreement ~~and fully transferable.~~

~~Letter~~solely by reason of ~~Credit Facility – PNC Bank~~

~~On December 27, 2017, we entered into a master letter~~us failing to comply with the Fixed Charge Coverage Ratio covenant in Section 7.03(b) of credit facility, security agreement and reimbursement agreement (the “LoC Facility Agreement”) with PNC Bank, National Association (“PNC”), pursuant to which PNC agreed to provide us with a facilitythe Financing Agreement for the ~~issuance~~fiscal quarter ending December 31, 2018. The Amendment includes an amendment fee of ~~standby letters of credit used in the ordinary course of our business (the “LoC Facility”). The LoC Facility Agreement provided that we pay a quarterly~~approximately $0.6 million payable by us on May 13, 2019 and an exit fee ~~at a rate~~ equal to ~~5% per annum calculated based~~1% of the principal amount of the term loans made under the Financing Agreement that is payable on the ~~daily average~~earliest of ~~letters~~(w) the final maturity date of ~~credit outstanding under~~ the ~~LoC Facility, as well as administrative costs incurred by PNC and a $100,000 closing fee. The LoC Facility~~Financing Agreement, ~~provided that we reimburse PNC for any drawing under a letter~~(x) the termination date of ~~credit by a specified beneficiary as soon as possible after payment was made. Our~~the Financing Agreement, (y) the acceleration of the obligations under the ~~LoC Facility~~Financing Agreement ~~were secured by a first lien security interest on a cash collateral account that was required to contain no less than 105%~~for any reason, including, without limitation, acceleration in accordance with Section 9.01 of the face value of the outstanding letters of credit. In the event the amount in such cash collateral account was insufficient to satisfy our reimbursement obligations, the amount outstanding would bear interest at a rate per annum equal to the Base Rate (as that term was defined in the LoC Facility Agreement) plus 2.0%. We would indemnify PNC for any losses which PNC may have incurredFinancing Agreement, including as a result of the ~~issuance~~commencement of ~~a letter~~an insolvency proceeding and (z) the date of ~~credit or PNC’s failure~~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 ~~honor any drawing under a letter~~extend the date of ~~credit, subject in each case~~the Make-Whole Amount period to certain exceptions. We provided cash collateral to our counterparties during the third quarter of 2018 and as of September 30, 2018, the LoC Facility was terminated. We had no outstanding letters of credit as of September 30, 2018.

December 31, 2019.

Distribution Suspension

Pursuant to the 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 ~~September 30, 2018,~~March 31, 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 ~~September~~June 30, ~~2018,~~2019, we had accumulated arrearages of ~~$614.5~~$790.2 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 ~~September~~June 30, ~~2018,~~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
2018 Q4		1,283		14
2019		2,107		10
2019 Q3-Q4					2,192	18
2020		1,446		6	2,180	7
2021					920	3

~~Some~~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 ~~September~~June 30, ~~2018,~~2019, we have four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois Basin. Additionally, we have an Other category that includes our ancillary businesses. Our Central Appalachia segment consists of two mining complexes: Tug River and Rob Fork, which, as of ~~September~~June 30, ~~2018,~~2019, together included one underground mine, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Our Northern Appalachia segment consists of the Hopedale mining complex and the Leesville field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of ~~September~~June 30, ~~2018.~~2019. Our Rhino Western segment includes one underground mine in the Western Bituminous region at our Castle Valley mining complex in Utah. Our Illinois Basin segment includes one underground mine, preparation plant and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our Taylorville field reserves located in central Illinois. Our Other category is comprised of our ancillary businesses.

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. ~~(The following discussions of financial and operational data for the three months ended September 30, 2018 and 2017 pertain to continuing operations unless otherwise specified.)~~

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the three months ended ~~September~~June 30, ~~2018~~2019 and ~~2017:~~2018:

	Three months ended			Three months ended			Increase/(Decrease)						Three months ended			Three months ended			Increase/(Decrease)
	September 30, 2018			September 30, 2017			$			% *			June 30, 2019			June 30, 2018			$			% *
	(in millions, except per ton data and %)												(in millions, except per ton data and %)
Statement of Operations Data:

Coal revenues	$	71.9		$	56.3		$	15.6			27.7	%	$	65.1		$	54.2		$	10.9			20.0	%
Other revenues		0.7			0.4			0.3			66.4	%		0.5			0.7			(0.2	)		(26.8	)%
Total revenues		72.6			56.7			15.9			28.0	%		65.6			54.9			10.7			19.4	%
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below)		60.8			44.8			16.0			35.8	%		59.8			49.6			10.2			20.5	%
Freight and handling costs		5.8			1.2			4.6			372.7	%		1.8			1.4			0.4			20.7	%
Depreciation, depletion and amortization		5.6			5.1			0.5			11.2	%		5.6			5.7			(0.1	)		(1.1	)%
Selling, general and administrative (exclusive of DD&A shown separately above)		2.8			2.7			0.1			4.6	%		3.5			2.8			0.7			24.1	%
(Gain)/loss on sale/disposal of assets		(0.7	)		(0.1	)		(0.6	)		840.0	%
(Loss)/income from operations		(1.7	)		3.0			(4.7	)		(155.6	%)
Interest and other (income) expense:
(Gain) on sale/disposal of assets														(6.9	)		(3.5	)		(3.4	)		96.9	%
Income/(Loss) from operations														1.8			(1.1	)		2.9			(264.6	)%
Interest expense and other		2.8			1.0			1.8			180.0	%		1.7			1.9			(0.2	)		(9.4	)%
Interest income and other		-			(0.1	)		0.1			(100.0	%)		-			-			-			n/a
Total interest and other (income) expense		2.8			0.9			1.9			206.1	%		1.7			1.9			(0.2	)		(9.4	)%
Net (loss)/income from continuing operations		(4.5	)		2.1			(6.6	)		(312.3	%)
Net (loss) from discontinued operations		-			(0.4	)		0.4			(100.0	%)
Net (loss)/income	$	(4.5	)	$	1.7		$	(6.2	)		(370.9	%)
Net income/(loss)													$	0.1		$	(3.0	)		3.1			(103.7	)%

Total tons sold		1,255.2			1,044.8			210.4			20.1	%
Total tons sold (in thousands except %)														1,123.2			1,102.8			20.4			1.9	%
Coal revenues per ton	$	57.25		$	53.86		$	3.39			6.3	%	$	57.95		$	49.19		$	8.76			17.8	%
Cost of operations per ton	$	48.43		$	42.83		$	5.60			13.1	%	$	53.20		$	44.97		$	8.23			18.3	%

Other Financial Data
Adjusted EBITDA from continuing operations	$	4.2		$	8.2		$	(4.0	)		(48.5	%)
Adjusted EBITDA from discontinued operations		-			(0.3	)		0.3			(100.0	%)
Adjusted EBITDA	$	4.2		$	7.9		$	(3.7	)		(46.3	%)	$	7.5		$	4.6		$	2.9			65.2	%

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

Three Months Ended ~~September~~June 30, ~~2018~~2019 Compared to Three Months Ended ~~September~~June 30, ~~2017~~2018

Revenues.Our coal revenues for the three months ended ~~September~~June 30, ~~2018~~2019 increased by approximately ~~$15.6~~$10.9 million, or ~~27.7%~~20.0%, to approximately ~~$71.9~~$65.1 million from approximately ~~$56.3~~$54.2 million for the three months ended ~~September~~June 30, ~~2017. The increase in coal revenues was primarily due to an increase in tons sold from our Central Appalachia operations as demand for met and steam coal remains strong in this region.~~2018. Coal revenues per ton was ~~$57.25~~$57.95 for the three months ended ~~September~~June 30, ~~2018,~~2019, an increase of ~~$3.39~~$8.76 or ~~6.3%~~17.8%, from ~~$53.86~~$49.19 per ton for the three months ended ~~September~~June 30, ~~2017. This~~2018. The increase in coal revenues and coal revenues per ton was primarily the result of higher ~~contract~~contracted sale prices for ~~met~~ coal sold ~~from~~across all of our ~~Central Appalachia operations~~locations during the ~~third~~second quarter of ~~2018~~2019 compared to the same period in ~~2017.~~2018.

Cost of Operations. Total cost of operations increased by ~~$16.0~~$10.2 million or ~~35.8%~~20.5% to ~~$60.8~~$59.8 million for the three months ended ~~September~~June 30, ~~2018~~2019 as compared to ~~$44.8~~$49.6 million for the three months ended ~~September~~June 30, ~~2017.~~2018. Our cost of operations per ton was ~~$48.43~~$53.20 for the three months ended ~~September~~June 30, ~~2018,~~2019, an increase of ~~$5.60,~~$8.23, or ~~13.1%~~18.3%, from the three months ended ~~September~~June 30, ~~2017.~~2018. The increase in total cost of operations and cost of operations per ton was primarily due to increases in the cost of ~~production at our Central Appalachia operations for diesel fuel,~~labor, contract services and equipment maintenance at several of our operations in the ~~third~~second quarter of 2019 compared to the same period in 2018.

Freight and Handling.Total freight and handling cost increased to ~~$5.8~~$1.8 million for the three months ended ~~September~~June 30, ~~2018~~2019 from approximately ~~$1.2~~$1.4 million for the three months ended ~~September~~June 30, ~~2017.~~2018. The increase in freight and handling costs was primarily the result of ~~rail transportation costs at~~a new sales contract for coal shipped from our ~~Central~~Northern Appalachia ~~operations as we executed more export coal sales in the period~~operation that ~~required~~requires us to pay ~~for railroad transportation~~the freight and handling to the ~~port of export. We also incurred $0.9 million in demurrage charges due to rail transportation constraints that caused shipments to be delayed to the port of export.~~customer’s destination.

Depreciation, Depletion and ~~Amortization.~~Amortization (“DD&A”). Total DD&A expense for the three months ended ~~September~~June 30, ~~2018~~2019 was $5.6 million as compared to ~~$5.1~~$5.7 million for the three months ended ~~September~~June 30, ~~2017.~~2018.

For the three months ended ~~September~~June 30, 2019 and 2018, our depreciation expense ~~was~~remained relatively flat at approximately ~~$4.3 million compared to $3.8 million for the three months ended September 30, 2017, as we added new equipment to meet the increased demand for coal.~~$4.2 million.

For the three months ended ~~September~~June 30, ~~2018~~2019 and ~~2017,~~2018, our depletion expense remained relatively flat at approximately $0.5 million.

For the three months ended ~~September~~June 30, ~~2018 and 2017,~~2019 our amortization expense ~~remained flat at~~was approximately ~~$0.8~~$0.9 million and for the three months ended June 30, 2018 it was $1.0 million.

Selling, General and Administrative. SG&A expense for the three months ended ~~September~~June 30, ~~2018~~2019 increased ~~slightly~~ to ~~$2.8~~$3.5 million as compared to ~~$2.7~~$2.8 million for the three months ended ~~September~~June 30, ~~2017. We recorded a bad debt provision of $0.3 million during the third quarter of 2018.~~2018 as we experienced an increase in corporate overhead expense.

Interest Expense.Interest expense for the three months ended ~~September~~June 30, ~~2018 increased~~2019 decreased to ~~$2.8~~$1.7 million as compared to ~~$1.0~~$1.9 million for the three months ended ~~September~~June 30, ~~2017.~~2018. This ~~increase~~decrease was primarily due to ~~the higher~~a lower outstanding debt balance ~~and effective interest rate on~~for the ~~new Financing Agreement.~~three months ended June 30, 2019 compared to the same period in 2018.

Net Income/Loss. Net ~~loss~~income was ~~$4.5~~$0.1 million for the three months ended ~~September~~June 30, ~~2018~~2019 compared to net ~~income~~loss of ~~$2.1~~$3.0 million for the three months ended ~~September~~June 30, ~~2017. The net~~2018. Net income was positively impacted by a gain of $6.9 million resulting from the settlement agreement discussed above but negatively impacted by higher cost of operations discussed above. Net loss ~~incurred during~~for the three months ended ~~September~~June 30, 2018 was ~~primarily due to~~positively impacted from a decrease in contract prices for tons sold from our Pennyrile mine and an increase in freight and handling costs as discussed above. Interest expense also increased by $1.8 million during the nine months ended September 30, 2018 compared to the same period in 2017.gain on sale of assets of $3.5 million.

Adjusted EBITDA. Adjusted EBITDA ~~for the three months ended September 30, 2018 decreased~~increased by ~~$4.0 million to $4.2 million from $8.2~~$2.9 million for the three months ended ~~September~~June 30, ~~2017. Adjusted EBITDA decreased period over period primarily due~~2019 to ~~the decrease in net income at our Pennyrile mining operation in the Illinois Basin as discussed below. Adjusted EBITDA~~$7.5 million from $4.6 million for the three months ended ~~September~~June 30, ~~2017~~2018. The increase was ~~$7.9 million once~~primarily due to the ~~results from discontinued operations were included. We did not incur a gain or loss from discontinued operations~~increase in net income for the three months ended ~~September~~June 30, ~~2018.~~2019. 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 three months ended ~~September~~June 30, ~~2018~~2019 and ~~2017:~~2018:

Central Appalachia Three months ended Three months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 43.9 $ 27.9 $ 16.0 57.4 %
Freight and handling revenues - - - n/a
Other revenues - - - n/a
Total revenues 43.9 27.9 16.0 57.4 %
Coal revenues per ton $ 83.59 $ 73.02 $ 10.57 14.5 %
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 31.9 20.9 11.0 52.6 %
Freight and handling costs 5.8 1.2 4.6 372.7 %
Depreciation, depletion and amortization 2.2 1.9 0.3 16.4 %
Selling, general and administrative costs 0.4 - 0.4 567.5 %
Cost of operations per ton $ 60.75 $ 54.73 $ 6.02 11.0 %
Net income from continuing operations 3.6 3.8 (0.2 ) (4.4 %)
Adjusted EBITDA from continuing operations 6.1 5.7 0.4 7.7 %
Tons sold 524.6 381.6 143.0 37.5 %

Central Appalachia

	Three months ended		Three months ended		Increase/(Decrease)
	June 30, 2019		June 30, 2018		$			% *
	(in millions, except per ton data and %)

Coal revenues	$	35.2	$	28.1	$	7.1			25.3	%
Freight and handling revenues		-		-		-			n/a
Other revenues		-		0.1		(0.1	)		(36.2	)%
Total revenues		35.2		28.2		7.0			25.2	%
Coal revenues per ton	$	89.08	$	67.05	$	22.03			32.9	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		32.4		23.3		9.1			39.0	%
Freight and handling costs		1.3		1.4		(0.1	)		(12.3	)%
Depreciation, depletion and amortization		1.9		2.3		(0.4	)		(17.7	)%
Selling, general and administrative costs		0.1		0.1		-			(62.7	)%
Cost of operations per ton	$	82.07	$	55.69	$	26.38			47.4	%
Net income		6.6		1.0		5.6			558.1	%
Adjusted EBITDA		8.5		3.3		5.1			158.4	%
Tons sold (in thousands except %)		395.0		418.8		(23.8	)		(5.7	)%

*	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 ~~increased~~decreased by approximately ~~37.5% to approximately 0.5 million tons~~5.7% for the three months ended ~~September~~June 30, ~~2018~~2019 compared to the three months ended ~~September~~June 30, ~~2017,~~2018 primarily due to ~~an increase~~a decrease in customer demand for ~~met and~~ steam coal ~~tons~~ from this region.

Coal revenues increased by approximately ~~$16.0~~$7.1 million, or ~~57.4%~~25.3%, to approximately ~~$43.9~~$35.2 million for the three months ended ~~September~~June 30, ~~2018~~2019 from approximately ~~$27.9~~$28.1 million for the three months ended ~~September~~June 30, ~~2017. This increase was primarily due to the increase in demand for met and steam coal tons sold from this region.~~2018. Coal revenues per ton for our Central Appalachia segment increased by ~~$10.57,~~$22.03, or ~~14.5%~~32.9%, to ~~$83.59~~$89.08 per ton for the three months ended ~~September~~June 30, ~~2018~~2019 as compared to ~~$73.02~~$67.05 for the three months ended ~~September~~June 30, ~~2017. This~~2018. The increase in coal revenues and coal revenues per ton was primarily due to ~~the increase in contract prices for our~~a higher mix of higher priced met coal ~~from this region.~~tons sold during the second quarter of 2019 compared to the same period in 2018.

Cost of operations increased by ~~$11.0~~$9.1 million, or ~~52.6%~~39.0%, to ~~$31.9~~$32.4 million for the three months ended ~~September~~June 30, ~~2018~~2019 from ~~$20.9~~$23.3 million for the three months ended ~~September~~June 30, ~~2017.~~2018. Our cost of operations per ton of ~~$60.75~~$82.07 for the three months ended ~~September~~June 30, ~~2018~~2019 increased ~~11.0%~~47.4% compared to ~~$54.73~~$55.69 per ton for the three months ended ~~September~~June 30, ~~2017. Total cost~~2018. Cost of operations ~~increased period over period as we increased sales in this region during the third quarter of 2018 compared to the same period in 2017. Cost~~and cost of operations per ton increased as we experienced an increase in ~~diesel fuel,~~operating costs including labor, contract services and equipment maintenance, in addition to fewer tons of coal sold during the three months ended ~~September~~June 30, ~~2018.~~2019 that increased our cost of operations per ton.

Total freight and handling cost ~~increased to $5.8~~was $1.3 million for the three months ended ~~September~~June 30, ~~2018 from approximately $1.2~~2019, which was relatively flat to $1.4 million for the three months ended ~~September~~June 30, 2017. The increase in freight and handling costs was primarily the result of rail transportation costs at our Central Appalachia operations as we executed more export coal sales in the period that required us to pay for railroad transportation to the port of export. We also incurred $0.9 million in demurrage charges due to rail transportation constraints that caused shipments to be delayed to the port of export.2018.

For our Central Appalachia segment, net income was approximately ~~$3.6~~$6.6 million for the three months ended ~~September~~June 30, ~~2018, a decrease~~2019, an increase of ~~$0.2~~$5.6 million ~~in net income~~ as compared to the three months ended ~~September~~June 30, ~~2017. Net income was impacted by an~~2018. The increase in net income for the ~~cost of operations~~three months ended June 30, 2019 was primarily due to the $6.9 million gain resulting from the settlement discussed above.

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 ~~September~~June 30, 2019 and 2018, is presented below. Note that our Northern Appalachia, Rhino Western and Illinois Basin segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)	Three months ended September 30, 2018		Three months ended September 30, 2017		Increase (Decrease) %*			Three months ended June 30, 2019		Three months ended June 30, 2018		Increase (Decrease) %*
Met coal tons sold		264.0		196.8		34.2	%		226.6		151.6		49.4	%
Steam coal tons sold		260.6		184.8		41.0	%		168.4		267.2		(37.0	)%
Total tons sold		524.6		381.6		37.5	%		395.0		418.8		(5.7	)%

Met coal revenue	$	29,875	$	18,285		63.4	%	$	25,437	$	14,878		71.0	%
Steam coal revenue	$	13,979	$	9,580		45.9	%	$	9,749	$	13,199		(26.1	)%
Total coal revenue	$	43,854	$	27,865		57.4	%	$	35,186	$	28,077		25.3	%

Met coal revenues per ton	$	113.17	$	92.93		21.8	%	$	112.26	$	98.12		14.4	%
Steam coal revenues per ton	$	53.64	$	51.82		3.5	%	$	57.89	$	49.41		17.2	%
Total coal revenues per ton	$	83.59	$	73.02		14.5	%	$	89.08	$	67.05		32.9	%

Met coal tons produced		141.7		151.9		(6.7	%)		118.8		124.0		(4.2	)%
Steam coal tons produced		302.7		253.8		19.2	%		275.4		358.2		(23.1	)%
Total tons produced		444.4		405.7		9.5	%		394.2		482.2		(18.3	)%

Northern Appalachia

	Three months ended			Three months ended			Increase/(Decrease)
	June 30, 2019			June 30, 2018			$			% *
	(in millions, except per ton data and %)

Coal revenues	$	8.4		$	3.9		$	4.5			115.0	%
Freight and handling revenues		-			-			-			n/a
Other revenues		0.5			0.5			-			(10.9	)%
Total revenues		8.9			4.4			4.5			100.3	%
Coal revenues per ton	$	48.63		$	40.79		$	7.84			19.2	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		8.6			5.6			3.0			54.2	%
Freight and handling costs		0.5			-			0.5			n/a
Depreciation, depletion and amortization		0.4			0.3			0.1			44.6	%
Selling, general and administrative costs		-			-			-			n/a
Cost of operations per ton	$	49.91		$	58.40		$	(8.49	)		(14.5	)%
Net loss		(0.7	)		(1.5	)		0.8			(53.1	)%
Adjusted EBITDA		(0.3	)		(1.2	)		0.9			(78.2	)%
Tons sold (in thousands except %)		172.6			95.7			76.9			80.4	%

Northern Appalachia Three months ended Three months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 5.2 $ 4.4 $ 0.8 19.9 %
Freight and handling revenues - - - n/a
Other revenues 0.7 0.4 0.3 59.7 %
Total revenues 5.9 4.8 1.1 23.1 %
Coal revenues per ton $ 44.05 $ 41.38 $ 2.67 6.5 %
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 6.3 4.9 1.4 28.5 %
Freight and handling costs - - - n/a
Depreciation, depletion and amortization 0.3 0.3 - 53.2 %
Selling, general and administrative costs - 0.1 (0.1 ) (55.9 %)
Cost of operations per ton $ 53.33 $ 46.73 $ 6.60 14.1 %
Net loss from continuing operations (0.8 ) (0.5 ) (0.3 ) 96.3 %
Adjusted EBITDA from continuing operations (0.5 ) (0.2 ) (0.3 ) 150.9 %
Tons sold 118.7 105.5 13.2 12.6 %

*	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 ~~12.6%~~80.4% for the three months ended ~~September~~June 30, ~~2018~~2019 compared to the three months ended ~~September~~June 30, ~~2017~~2018 as we experienced increased demand for coal from this region.

Coal revenues were approximately ~~$5.2~~$8.4 million for the three months ended ~~September~~June 30, ~~2018,~~2019, an increase of approximately ~~$0.8~~$4.5 million, or ~~19.9%~~115.0%, from approximately ~~$4.4~~$3.9 million for the three months ended ~~September~~June 30, ~~2017.~~2018. Coal revenues per ton ~~increased by $2.67 or 6.5% to $44.05 per ton~~were $48.63 for the three months ended ~~September~~June 30, ~~2018,~~2019 as compared to ~~$41.38~~$40.79 for the three months ended ~~September~~June 30, ~~2017, which~~2018. The increase in coal revenues and coal revenues per ton was primarily due to ~~higher contracted prices for~~the increase in tons of coal sold from our Hopedale ~~complex~~operation resulting from increased demand in this region and higher contracted sale prices for the tons sold compared to the ~~prior year.~~same period in 2018.

Cost of operations increased by ~~$1.4~~$3.0 million, or ~~28.5%~~54.2%, to ~~$6.3~~$8.6 million for the three months ended ~~September~~June 30, ~~2018~~2019 from ~~$4.9~~$5.6 million for the three months ended ~~September~~June 30, ~~2017.~~2018. Our cost of operations per ton was ~~$53.33~~$49.91 for the three months ended ~~September~~June 30, ~~2018, an increase~~2019, a decrease of ~~$6.60,~~$8.49, or ~~14.1%~~14.5%, compared to ~~$46.73~~$58.40 for the three months ended ~~September~~June 30, ~~2017.~~2018. The increase in total cost of operations was primarily the result of ~~an increase in maintenance costs~~increased production and ~~costs for outside services.~~sales from this region. The cost of operations per ton ~~increased~~decreased in Northern Appalachia as ~~poor rail service led to fewer~~more tons ~~produced and~~were sold from this region resulting in fixed costs being allocated to ~~fewer~~higher tons sold during the ~~three months ended September 30, 2018.~~current period.

Net loss in our Northern Appalachia segment was ~~$0.8~~$0.7 million for the three months ended ~~September~~June 30, ~~2018~~2019 compared to net loss of ~~$0.5~~$1.5 million for the three months ended ~~September~~June 30, ~~2017.~~2018. The ~~increase~~decrease in net loss ~~for the three months ended September 30, 2018~~ was primarily due to the increase in ~~the cost of operations partially offset by the increase in contracted prices of~~ tons sold ~~compared to~~and the ~~same period in 2017.~~higher contracted sale price for tons sold at our Hopedale operation.

Rhino Western

Rhino Western Three months ended Three months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 10.3 $ 9.1 $ 1.2 12.9 %
Freight and handling revenues - - - n/a
Other revenues - - - n/a
Total revenues 10.3 9.1 1.2 12.9 %
Coal revenues per ton $ 35.06 $ 37.53 $ (2.47 ) (6.6 %)
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 9.2 6.6 2.6 37.9 %
Freight and handling costs - - - n/a
Depreciation, depletion and amortization 1.0 1.1 (0.1 ) (9.4 %)
Selling, general and administrative costs 0.1 - 0.1 49.1 %
Cost of operations per ton $ 31.35 $ 27.48 $ 3.87 14.1 %
Net income/(loss) from continuing operations - 1.4 (1.4 ) (96.0 %)
Adjusted EBITDA from continuing operations 1.0 2.5 (1.5 ) (58.6 %)
Tons sold 292.5 241.9 50.6 20.9 %

	Three months ended		Three months ended		Increase/(Decrease)
	June 30, 2019		June 30, 2018		$			% *
	(in millions, except per ton data and %)

Coal revenues	$	8.4	$	8.6	$	(0.2	)		(2.7	)%
Freight and handling revenues		-		-		-			n/a
Other revenues		-		-		-			n/a
Total revenues		8.4		8.6		(0.2	)		(2.7	)%
Coal revenues per ton	$	37.62	$	35.86	$	1.76			4.9	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		5.9		7.6		(1.7	)		(22.4	)%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		1.1		1.0		0.1			6.5	%
Selling, general and administrative costs		-		-		-			n/a
Cost of operations per ton	$	26.32	$	31.44	$	(5.12	)		(16.3	)%
Net income		1.3		-		1.3			(2201.7	)%
Adjusted EBITDA		2.5		1.0		1.5			154.5	%
Tons sold (in thousands except %)		223.8		241.3		(17.5	)		(7.3	)%

*	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 ~~increased~~decreased by approximately ~~20.9%~~7.3% for the three months ended ~~September~~June 30, ~~2018~~2019 compared to the same period in ~~2017~~2018 primarily due to ~~an increase~~a decrease in demand for coal from this region.

Coal revenues ~~increased~~decreased by approximately ~~$1.2~~$0.2 million, or ~~12.9%~~2.7%, to approximately ~~$10.3~~$8.4 million for the three months ended ~~September~~June 30, ~~2018~~2019 from approximately ~~$9.1~~$8.6 million for the three months ended ~~September~~June 30, 2018 primarily due to ~~an increase~~a decrease in ~~demand for~~ tons sold from ~~the~~our Castle Valley ~~mine compared to the three months ended September 30, 2017.~~mine. Coal revenues per ton for our Rhino Western segment ~~decreased~~increased by ~~$2.47~~$1.76 or ~~6.6%~~4.9% to ~~$35.06~~$37.62 per ton for the three months ended ~~September~~June 30, ~~2018~~2019 as compared to ~~$37.53~~$35.86 per ton for the three months ended ~~September~~June 30, ~~2017~~2018 due to ~~lower~~higher contracted sale prices.

Cost of operations ~~increased~~decreased by ~~$2.6~~$1.7 million, or ~~37.9%~~22.4%, to ~~$9.2~~$5.9 million for the three months ended ~~September~~June 30, ~~2018~~2019 from ~~$6.6~~$7.6 million for the three months ended ~~September~~June 30, ~~2017.~~2018. Our cost of operations per ton was ~~$31.35~~$26.32 for the three months ended ~~September~~June 30, ~~2018, an increase~~2019, a decrease of ~~$3.87,~~$5.12, or ~~14.1%~~16.3%, compared to ~~$27.48~~$31.44 for the three months ended ~~September~~June 30, ~~2017.~~2018. Total cost of operations and cost of operations per ton ~~increased~~decreased for the three months ended ~~September~~June 30, ~~2018~~2019 compared to the same period in ~~2017 as we began~~2018 due to ~~transition~~a decrease in operating costs at our ~~coal mining operation at~~ Castle Valley ~~to an adjacent coal seam at this~~mine operation.

Net income in our Rhino Western segment was ~~$56,000 for the three months ended September 30, 2018, compared to net income of $1.4~~$1.3 million for the three months ended ~~September~~June 30, ~~2017.~~2019, compared to zero net income for the three months ended June 30, 2018. This ~~decrease~~increase in net income was primarily the result of ~~higher operating costs~~an increase in our contracted sale prices for tons sold at our Castle Valley ~~operation.~~operation and lower operating costs during the second quarter of 2019.

Illinois Basin Three months ended Three months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 12.5 $ 14.9 $ (2.4 ) (16.3 %)
Freight and handling revenues - - - n/a
Other revenues - - - n/a
Total revenues 12.5 14.9 (2.4 ) (16.3 %)
Coal revenues per ton $ 39.22 $ 47.37 $ (8.15 ) (17.2 %)
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 13.7 13.1 0.6 5.1 %
Freight and handling costs - - - n/a
Depreciation, depletion and amortization 2.0 1.8 0.2 12.5 %
Selling, general and administrative costs - - - n/a
Cost of operations per ton $ 43.00 $ 41.40 $ 1.60 3.9 %
Net (loss)/income from continuing operations (3.2 ) 0.1 (3.3 ) (3107.7 %)
Adjusted EBITDA from continuing operations (1.3 ) 1.9 (3.2 ) (167.6 %)
Tons sold 319.4 315.8 3.6 1.2 %

Illinois Basin

	Three months ended			Three months ended			Increase/(Decrease)
	June 30, 2019			June 30, 2018			$			% *
	(in millions, except per ton data and %)

Coal revenues	$	13.1		$	13.6		$	(0.5	)		(3.8	)%
Freight and handling revenues		-			-			-			n/a
Other revenues		-			-			-			n/a
Total revenues		13.1			13.6			(0.5	)		(3.8	)%
Coal revenues per ton	$	39.45		$	39.22		$	0.23			0.6	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		13.7			13.5			0.2			1.6	%
Freight and handling costs		-			-			-			n/a
Depreciation, depletion and amortization		2.1			2.0			0.1			7.3	%
Selling, general and administrative costs		-			0.1			(0.1	)		(100.0	)%
Cost of operations per ton	$	41.31		$	38.86		$	2.45			6.3	%
Net (loss)		(2.8	)		(1.9	)		(0.9	)		46.8	%
Adjusted EBITDA		(0.7	)		0.1			(0.7	)		(748.5	)%
Tons sold (in thousands except %)		331.8			347.0			(15.2	)		(4.4	)%

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

For our Illinois Basin segment, tons of coal sold ~~increased~~decreased by approximately ~~1.2%~~4.4% for the three months ended ~~September~~June 30, ~~2018~~2019 compared to the three months ended ~~September~~June 30, ~~2017.~~2018 due to decreased customer demand for coal from this region.

Coal revenues of approximately ~~$12.5~~$13.1 million for the three months ended ~~September~~June 30, ~~2018~~2019 decreased by approximately ~~$2.4~~$0.5 million, or ~~16.3%~~3.8%, compared to ~~$14.9~~$13.6 million for the three months ended ~~September~~June 30, 2017. Coal revenues per ton for our Illinois Basin segment were $39.22 for the three months ended September 30, 2018, a decrease of $8.15, or 17.2%, from $47.37 for the three months ended September 30, 2017.2018. The decrease in coal revenues ~~and coal revenues per ton were~~was primarily due to ~~lower contracted prices for~~the decrease in tons sold from our Pennyrile mine in western Kentucky. Coal revenues per ton for this segment were $39.45 for the three months ended June 30, 2019, an increase of $0.23, or 0.6%, from $39.22 for the three months ended June 30, 2018. The increase in coal revenues per ton was due to higher contracted prices for tons sold from this region.

Cost of operations was $13.7 million while cost of operations per ton was ~~$43.00~~$41.31 for the three months ended ~~September~~June 30, ~~2018,~~2019, both of which related to our Pennyrile mining complex in western Kentucky. For the three months ended ~~September~~June 30, ~~2017,~~2018, cost of operations in our Illinois Basin segment was ~~$13.1~~$13.5 million and cost of operations per ton was ~~$41.40.~~$38.86. The increase in cost of operations and cost of operations per ton was the result of increases in labor and equipment maintenance costs during the second quarter of 2019.

For our Illinois Basin segment, we generated a net loss of $2.8 million for the three months ended June 30, 2019 compared to net loss of $1.9 million for the three months ended June 30, 2018. The increase in net loss was primarily the result of the decrease in tons sold and the increase in cost of operations discussed above.

Other

	Three months ended			Three months ended			Increase/(Decrease)
	June 30, 2019			June 30, 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	$	-		$	0.1		$	(0.1	)		(100.0	)%
Total revenues		-			0.1			(0.1	)		(100.0	)%
Coal revenues per ton**		n/a			n/a			n/a			n/a
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		(0.8	)		(0.4	)		(0.4	)		123.1	%
Freight and handling costs		-			-			-			n/a
Depreciation, depletion and amortization		0.1			0.1			-			(5.2	)%
Selling, general and administrative costs		3.4			2.6			0.8			28.3	%
Cost of operations per ton**		n/a			n/a			n/a			n/a
Net (loss)		(4.3	)		(0.6	)		(3.7	)		603.6	%
Adjusted EBITDA		(2.5	)		1.4			(3.9	)		(279.0	)%
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 $4.3 million for the three months ended June 30, 2019 as compared to net loss of $0.6 million for the three months ended June 30, 2018. The net loss for the three months ended June 30, 2018 was positively impacted by a $3.6 million gain on sale of Mammoth Inc. shares.

Summary.

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

	Six months ended			Six months ended			Increase/(Decrease)
	June 30, 2019			June 30, 2018			$			% *
	(in millions, except per ton data and %)
Statement of Operations Data:

Coal revenues	$	122.9		$	108.5		$	14.4			13.3	%
Other revenues		1.4			1.2			0.2			13.7	%
Total revenues		124.3			109.7			14.6			13.3	%
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below)		114.4			99.3			15.1			15.3	%
Freight and handling costs		2.9			2.3			0.6			23.4	%
Depreciation, depletion and amortization		11.2			11.1			0.1			0.6	%
Selling, general and administrative (exclusive of DD&A shown separately above)		6.2			5.5			0.7			13.1	%
(Gain) on sale/disposal of assets		(6.6	)		(6.4	)		(0.2	)		3.5	%
(Loss) from operations		(3.8	)		(2.1	)		(1.7	)		80.7	%
Interest and other (income) expense:
Interest expense and other		3.4			3.8			(0.4	)		(9.5	)%
Interest income and other		-			-			-			n/a
Total interest and other (income) expense		3.4			3.8			(0.4	)		(9.4	)%
Net (loss)	$	(7.2	)	$	(5.9	)		(1.3	)		22.4	%

Total tons sold (in thousands except %)		2,200.5			2,175.4			25.1			1.2	%
Coal revenues per ton	$	55.88		$	49.88		$	6.00			12.0	%
Cost of operations per ton	$	51.99		$	45.62		$	6.37			14.0	%

Other Financial Data
Adjusted EBITDA	$	8.2		$	9.0		$	(0.8	)		(9.4	)%

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

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Revenues.Our coal revenues for the six months ended June 30, 2019 increased by approximately $14.4 million, or 13.3%, to approximately $122.9 million from approximately $108.5 million for the six months ended June 30, 2018. Coal revenues per ton were $55.88 for the six months ended June 30, 2019, an increase of $6.00, or 12.0%, from $49.88 per ton for the six months ended June 30, 2018. The increase in coal revenues and coal revenues per ton was primarily due to an increase in the contracted sale prices across all segments for the six months ended June 30, 2019 compared to the same period in 2018.

Cost of Operations. Total cost of operations increased by $15.1 million or 15.3% to $114.4 million for the six months ended June 30, 2019 as compared to $99.3 million for the six months ended June 30, 2018. Our cost of operations per ton was $51.99 for the six months ended June 30, 2019, an increase of $6.37, or 14.0%, from the six months ended June 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 six months ended June 30, 2019 compared to the same period in 2018.

Freight and Handling.Total freight and handling cost increased to $2.9 million for the six months ended June 30, 2019 as compared to $2.3 million for the six months ended June 30, 2018. The increase in freight and handling costs was primarily the result of a new sales contract for coal shipped from our Northern Appalachia operation that requires us to pay the freight and handling to the customer’s destination.

Depreciation, Depletion and Amortization. Total DD&A expense for the six months ended June 30, 2019 was $11.2 million as compared to $11.1 million for the six months ended June 30, 2018.

For the six months ended June 30, 2019, our depreciation expense was approximately $8.4 million compared to approximately $8.3 million for the same period in 2018.

For the six months ended June 30, 2019 and 2018, our depletion expense remained flat at approximately $1.0 million.

For the six months ended June 30, 2019 and 2018, our amortization expense remained relatively flat at $1.8 million.

Selling, General and Administrative. SG&A expense for the six months ended June 30, 2019 increased to $6.2 million as compared to $5.5 million for the six months ended June 30, 2018 primarily due to higher corporate overhead expenses.

Interest Expense.Interest expense for the six months ended June 30, 2019 decreased to $3.4 million as compared to $3.8 million for the six months ended June 30, 2018. This decrease was primarily due to the lower outstanding debt balance for the six months ended June 30, 2019 compared to the same period in 2018.

Net Loss. Net loss was $7.2 million for the six months ended June 30, 2019 compared to net loss of $5.9 million for the six months ended June 30, 2018. Our net loss increased during the six months ended June 30, 2019 compared to 2018 primarily due to an increase in operating costs including labor, contract services and equipment maintenance at several of our operations.

Adjusted EBITDA. Adjusted EBITDA for the six months ended June 30, 2019 decreased by $0.8 million to $8.2 million from $9.0 million for the six months ended June 30, 2018. Adjusted EBITDA decreased period over period primarily due to the increase in net loss resulting from an increase in operating costs discussed above. 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 six months ended June 30, 2019 and 2018:

Central Appalachia

	Six months ended		Six months ended		Increase/(Decrease)
	June 30, 2019		June 30, 2018		$			% *
	(in millions, except per ton data and %)

Coal revenues	$	65.2	$	59.0	$	6.2			10.7	%
Freight and handling revenues		-		-		-			n/a
Other revenues		0.4		0.1		0.3			203.3	%
Total revenues		65.6		59.1		6.5			11.0	%
Coal revenues per ton	$	83.23	$	67.25	$	15.98			23.8	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		59.0		50.2		8.8			17.6	%
Freight and handling costs		1.9		2.3		(0.4	)		(17.1	)%
Depreciation, depletion and amortization		3.8		4.5		(0.7	)		(15.6	)%
Selling, general and administrative costs		0.1		0.1		-			(48.0	)%
Cost of operations per ton	$	75.27	$	57.25	$	18.02			31.5	%
Net income		7.7		1.9		5.8			301.9	%
Adjusted EBITDA		11.5		6.4		5.1			80.2	%
Tons sold (in thousands except %)		784.3		877.2		(92.9	)		(10.6	)%

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

Tons of coal sold in our Central Appalachia segment decreased by approximately 10.6% to approximately 0.8 million tons for the six months ended June 30, 2019 compared to the six months ended June 30, 2018, primarily due to a decrease in demand for steam coal from this region.

Coal revenues increased by approximately $6.2 million, or 10.7%, to approximately $65.2 million for the six months ended June 30, 2019 from approximately $59.0 million for the six months ended June 30, 2018. Coal revenues per ton for our Central Appalachia segment increased by $15.98, or 23.8%, to $83.23 per ton for the six months ended June 30, 2019 as compared to $67.25 for the six months ended June 30, 2018. The increase was primarily due to higher contracted sales prices for met and steam tons sold in Central Appalachia during the six months ended June 30, 2019 compared to the same period in 2018.

Cost of operations increased by $8.8 million, or 17.6%, to $59.0 million for the six months ended June 30, 2019 from $50.2 million for the six months ended June 30, 2018. Our cost of operations per ton of $75.27 for the six months ended June 30, 2019 increased 31.5% compared to $57.25 per ton for the six months ended June 30, 2018. This increase in cost of operations and cost of operations per ton was primarily due to the increase in labor costs, contract services and equipment maintenance at our Central Appalachia operation during the six months ended June 30, 2019 compared to the same period of 2018.

For our Central Appalachia segment, net income was approximately $7.7 million for the six months ended June 30, 2019, an increase of $5.8 million in net income as compared to the six months ended June 30, 2018. The increase in net income was primarily due to the $6.9 million gain resulting from the settlement discussed above, which was partially offset by the increase in operating costs discussed above for the six months ended June 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 six months ended June 30, 2019, is presented below. Note that our Northern Appalachia, Rhino Western and Illinois Basin segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)	Six months ended June 30, 2019		Six months ended June 30, 2018		Increase (Decrease) %*
Met coal tons sold		375.7		364.2		3.2	%
Steam coal tons sold		408.6		513.0		(20.4	)%
Total tons sold		784.3		877.2		(10.6	)%

Met coal revenue	$	42,135	$	34,129		23.5	%
Steam coal revenue	$	23,138	$	24,861		(6.9	)%
Total coal revenue	$	65,273	$	58,990		10.7	%

Met coal revenues per ton	$	112.15	$	93.72		19.7	%
Steam coal revenues per ton	$	56.63	$	48.46		16.9	%
Total coal revenues per ton	$	83.23	$	67.25		23.8	%

Met coal tons produced		241.3		250.5		(3.7	)%
Steam coal tons produced		584.2		639.1		(8.6	)%
Total tons produced		825.5		889.6		(7.2	)%

Northern Appalachia	Six months ended			Six months ended			Increase/(Decrease)
	June 30, 2019			June 30, 2018			$			% *
	(in millions, except per ton data and %)

Coal revenues	$	14.5		$	7.6		$	6.9			90.5	%
Freight and handling revenues		-			-			-			n/a
Other revenues		1.0			0.9			0.1			4.1	%
Total revenues		15.5			8.5			7.0			80.7	%
Coal revenues per ton	$	49.27		$	40.96		$	8.31			20.3	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		15.5			10.7			4.8			44.2	%
Freight and handling costs		1.0			-			1.0			n/a
Depreciation, depletion and amortization		0.8			0.4			0.4			91.1	%
Selling, general and administrative costs		-			-			-			n/a
Cost of operations per ton	$	52.67		$	57.82		$	(5.15	)		(8.9	)%
Net loss		(1.8	)		(2.5	)		0.7			(30.0	)%
Adjusted EBITDA		(1.0	)		(2.1	)		1.1			(55.1	)%
Tons sold (in thousands except %)		293.5			185.3			108.2			58.4	%

*	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 58.4% for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 due to increase in demand for coal from this region during the six months ended June 30, 2019.

Coal revenues were approximately $14.5 million for the six months ended June 30, 2019, an increase of approximately $6.9 million, or 90.5%, from approximately $7.6 million for the six months ended June 30, 2018. Coal revenues per ton increased by $8.31 or 20.3% to $49.27 per ton for the six months ended June 30, 2108, as compared to $40.96 for the six months ended June 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 half of 2019.

Cost of operations increased by $4.8 million, or 44.2%, to $15.5 million for the six months ended June 30, 2019 from $10.7 million for the six months ended June 30, 2018. The increase in total cost of operations was due to increased production and sales during the six months ended June 30, 2019. Our cost of operations per ton was $52.67 for the six months ended June 30, 2019, a decrease of $5.15, or 8.9%, compared to $57.82 for the six months ended June 30, 2018. 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 sold during the first six months of 2019.

Net loss in our Northern Appalachia segment was $1.8 million for the six months ended June 30, 2019 compared to net loss of $2.5 million for the six months ended June 30, 2018. The decrease in net loss for the six months ended June 30, 2018 was primarily due to the increase in production and sales and higher contracted sales prices as discussed above compared to the same period in 2018.

Rhino Western	Six months ended		Six months ended		Increase/(Decrease)
	June 30, 2019		June 30, 2018		$			% *
	(in millions, except per ton data and %)

Coal revenues	$	17.1	$	16.7	$	0.4			2.5	%
Freight and handling revenues		-		-		-			n/a
Other revenues		-		0.1		(0.1	)		(98.1	)%
Total revenues		17.1		16.8		0.3			2.4	%
Coal revenues per ton	$	37.10	$	35.90	$	1.20			3.3	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		13.1		13.6		(0.5	)		(3.7	)%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		2.2		2.1		0.1			4.8	%
Selling, general and administrative costs		-		0.1		(0.1	)		(31.6	)%
Cost of operations per ton	$	28.40	$	29.24	$	(0.84	)		(2.9	)%
Net income		1.0		0.9		0.1			10.3	%
Adjusted EBITDA		4.0		3.0		0.9			31.3	%
Tons sold (in thousands except %)		461.7		465.6		(3.9	)		(0.8	)%

*	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 for the six months ended June 30, 2019 was relatively flat compared to the same period in 2018.

Coal revenues increased by approximately $0.4 million, or 2.5%, to approximately $17.1 million for the six months ended June 30, 2019 from approximately $16.7 million for the six months ended June 30, 2018. Coal revenues per ton for our Rhino Western segment increased by $1.20 or 3.3% to $37.10 per ton for the six months ended June 30, 2019 as compared to $35.90 per ton for the six months ended June 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 six months ended June 30, 2019.

Cost of operations decreased by $0.5 million, or 3.7%, to $13.1 million for the six months ended June 30, 2019 from $13.6 million for the six months ended June 30, 2018. Our cost of operations per ton was $28.40 for the six months ended June 30, 2019, a decrease of $0.84, or 2.9%, compared to $29.24 for the six months ended June 30, 2018. The decrease in total cost of operations and cost of operations per ton was primarily due to lower operating costs during the six months ended June 30, 2019.

Net income from our Rhino Western segment was $1.0 million for the six months ended June 30, 2019, compared to net income of $0.9 million for the six months ended June 30, 2018.

Illinois Basin	Six months ended			Six months ended			Increase/(Decrease)
	June 30, 2019			June 30, 2018			$			% *
	(in millions, except per ton data and %)

Coal revenues	$	26.1		$	25.2		$	0.9			3.4	%
Freight and handling revenues		-			-			-			n/a
Other revenues		-			-			-			n/a
Total revenues		26.1			25.2			0.9			3.4	%
Coal revenues per ton	$	39.47		$	38.97		$	0.50			1.3	%
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		28.2			25.5			2.7			10.8	%
Freight and handling costs		-			-			-			n/a
Depreciation, depletion and amortization		4.2			3.9			0.3			6.7	%
Selling, general and administrative costs		0.1			0.1			-			(2.7	)%
Cost of operations per ton	$	42.73		$	39.39		$	3.34			8.5	%
Net (loss)		(6.4	)		(4.2	)		(2.2	)		50.8	%
Adjusted EBITDA		(2.2	)		(0.3	)		(1.8	)		643.7	%
Tons sold (in thousands except %)		661.0			647.3			13.7			2.1	%

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

For our Illinois Basin segment, tons of coal sold increased by approximately 2.1% for the six months ended June 30, 2019 compared to the six months ended June 30, 2018.

Coal revenues of approximately $26.1 million for the six months ended June 30, 2019 increased by approximately $0.9 million, or 3.4%, compared to $25.2 million for the six months ended June 30, 2018. Coal revenues per ton for our Illinois Basin segment were $39.47 for the six months ended June 30, 2019, an increase of $0.50, or 1.3%, from $38.97 for the six months ended June 30, 2018. The increase in coal revenues and coal revenues per ton was primarily due to higher contracted prices for tons sold from our Pennyrile mine in western Kentucky during the first half of 2019.

Cost of operations was $28.2 million while cost of operations per ton was $42.73 for the six months ended June 30, 2019, both of which related to our Pennyrile mining complex in western Kentucky. For the six months ended June 30, 2018, cost of operations was $25.5 million and cost of operations per ton was $39.39. The increase in cost of operations and cost of operations per ton for the ~~three~~six months ended ~~September~~June 30, ~~2018~~2019 was primarily the result of ~~adverse geological conditions encountered at our Pennyrile mining complex during the three months ended September 30, 2018.~~an increase in operating expenses including labor, contract services and equipment maintenance.

For our Illinois Basin segment, we generated a net loss of ~~$3.2~~$6.4 million for the ~~three~~six months ended ~~September~~June 30, ~~2018~~2019, which was an increase in net loss of $2.2 million compared to ~~net income of $0.1 million for~~ the ~~three~~six months ended ~~September~~June 30, ~~2017. The~~2018. This increase in net loss was primarily the result of ~~a decrease~~the increase in ~~the contract price for tons sold during the third quarter of 2018 compared to the same period in 2017.~~operating expenses discussed above.

Other	Three months ended			Three months ended			Increase/(Decrease)						Six months ended			Six months ended			Increase/(Decrease)
	September 30, 2018			September 30, 2017			$			% *			June 30, 2019			June 30, 2018			$			% *
	(in millions, except per ton data and %)												(in millions, except per ton data and %)

Coal revenues		n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a
Freight and handling revenues		n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a
Other revenues	$	-		$	-		$	-			n/a		$	-		$	0.1		$	(0.1	)		99.6	%
Total revenues		-			-			-			n/a			-			0.1			(0.1	)		99.6	%
Coal revenues per ton**		n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		(0.3	)		(0.7	)		0.4			(59.1	%)		(1.4	)		(0.7	)		(0.7	)		80.2	%
Freight and handling costs		-			-			-			n/a			-			-			-			n/a
Depreciation, depletion and amortization		0.1			-			0.1			8.9	%		0.2			0.2			-			(4.3	)%
Selling, general and administrative costs		2.3			2.6			(0.3	)		(7.9	%)		6.0			5.2			0.8			14.7	%
Cost of operations per ton**		n/a			n/a			n/a			n/a			n/a			n/a			n/a			n/a
Net loss from continuing operations		(4.1	)		(2.7	)		(1.4	)		50.1	%
Adjusted EBITDA from continuing operations		(1.1	)		(1.7	)		0.6			(28.3	%)
Tons sold		n/a			n/a			n/a			n/a
Net (loss)														(7.7	)		(2.0	)		(5.7	)		311.3	%
Adjusted EBITDA														(4.1	)		2.0			(6.1	)		(296.6	)%
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.

~~Other revenues for our Other category were flat for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.~~

For the Other category, we had net loss from continuing operations of $4.1 million for the three months ended September 30, 2018 as compared to net loss from continuing operations of $2.7 million for the three months ended September 30, 2017. The increase in net loss for the three months ended September 30, 2018 was primarily due to an increase of approximately $1.8 million in interest expense for the three months ended September 30, 2018 compared to the same period in 2017.

~~Summary. (The following discussions of financial and operational data for the nine months ended September 30, 2018 and 2017 pertain to continuing operations unless otherwise specified.)~~

~~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, 2018 and 2017:~~

Nine months ended Nine months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)
Statement of Operations Data:

Coal revenues $ 180.4 $ 161.8 $ 18.6 11.5 %
Other revenues 1.9 1.1 0.8 73.5 %
Total revenues 182.3 162.9 19.4 11.9 %
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below) 160.0 132.9 27.1 20.4 %
Freight and handling costs 8.3 1.8 6.5 349.0 %
Depreciation, depletion and amortization 16.7 16.0 0.7 4.3 %
Selling, general and administrative (exclusive of DD&A shown separately above) 8.3 8.5 (0.2 ) (1.6 %)
(Gain) on sale/disposal of assets (7.2 ) - (7.2 ) n/a
(Loss)/income from operations (3.8 ) 3.7 (7.5 ) (200.9 %)
Interest and other (income) expense:
Interest expense and other 6.6 3.1 3.5 111.7 %
Interest income and other - (0.1 ) 0.1 (92.3 %)
Total interest and other (income) expense 6.6 3.0 3.6 120.1 %
Net (loss)/income from continuing operations (10.4 ) 0.7 (11.1 ) (1541.6 %)
Net (loss) from discontinued operations - (0.8 ) 0.8 (100.0 %)
Net (loss) $ (10.4 ) $ (0.1 ) $ (10.3 ) 15455.4 %

Total tons sold 3,430.6 3,017.3 413.3 13.7 %
Coal revenues per ton $ 52.58 $ 53.63 $ (1.05 ) (2.0 %)
Cost of operations per ton $ 46.65 $ 44.06 $ 2.59 5.9 %

Other Financial Data
Adjusted EBITDA from continuing operations $ 13.2 $ 19.9 $ (6.7 ) (33.4 %)
Adjusted EBITDA from discontinued operations - (0.3 ) 0.3 (100.0 %)
Adjusted EBITDA $ 13.2 $ 19.6 $ (6.4 ) (32.2 %)

*	~~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, 2018 Compared to Nine Months Ended September 30, 2017~~

~~Revenues.~~Our coal revenues for the nine months ended September 30, 2018 increased by approximately $18.6 million, or 11.5%, to approximately $180.4 million from approximately $161.8 million for the nine months ended September 30, 2017. The increase in coal revenues was primarily due to an increase in met and steam coal tons sold in Central Appalachia as we saw increased demand for met and steam coal from this region during the period. Coal revenues per ton was $52.58 for the nine months ended September 30, 2018, a decrease of $1.05, or 2.0%, from $53.63 per ton for the nine months ended September 30, 2017. This decrease in coal revenues per ton was primarily the result of lower contracted prices for tons sold from our Pennyrile operation in the Illinois Basin during the nine months ended September 30, 2018 compared to the same period in 2017.

~~Cost of Operations~~. Total cost of operations increased by $27.1 million or 20.4% to $160.0 million for the nine months ended September 30, 2018 as compared to $132.9 million for the nine months ended September 30, 2017. Our cost of operations per ton was $46.65 for the nine months ended September 30, 2018, an increase of $2.59, or 5.9%, from the nine months ended September 30, 2017. The increase in cost of operations was primarily due to the $22.4 million increase in cost of operations at our Central Appalachia operations as demand for met and steam coal increased in this region. We also experienced an increase in the cost for diesel fuel, contract services and equipment maintenance in our Central Appalachia segment which resulted in the cost of operations per ton increasing during the period.

~~Freight and Handling.~~Total freight and handling cost increased to $8.3 million for the nine months ended September 30, 2018 as compared to $1.8 million for the nine months ended September 30, 2017. The increase in freight and handling costs was primarily the result of rail transportation costs in our Central Appalachia operations as we executed more export coal sales in the period that required us to pay for railroad transportation to the port of export. We also incurred $1.1 in demurrage charges due to rail transportation constraints that caused shipments to be delayed to the port of export.

~~Depreciation, Depletion and Amortization.~~ ~~Total DD&A expense for the nine months ended September 30, 2018 was $16.7 million as compared to $16.0 million for the nine months ended September 30, 2017.~~

For the nine months ended September 30, 2018, our depreciation expense increased to $12.6 million compared to $12.3 million for the nine months ended September 30, 2017. This increase was the result of adding new equipment to meet the increased demand for coal.

For the nine months ended September 30, 2018, our depletion expense increased to $1.4 million compared to $1.2 million for the nine months ended September 30, 2017. This increase is primarily due to increased production and sales tons for 2018 compared to 2017.

~~For the nine months ended September 30, 2018, our amortization expense increased slightly to $2.7 million as compared to $2.5 million for the nine months ended September 30, 2017.~~

~~Selling, General and Administrative.~~ SG&A expense for the nine months ended September 30, 2018 decreased to $8.3 million as compared to $8.5 million for the nine months ended September 30, 2017 primarily due to lower corporate overhead expenses.

~~Interest Expense~~.Interest expense for the nine months ended September 30, 2018 increased to $6.6 million as compared to $3.1 million for the nine months ended September 30, 2017. This increase was primarily due to the higher outstanding debt balance and effective interest rate on our new Financing Agreement.

~~Net Loss.~~ Net loss was $10.4 million for the nine months ended September 30, 2018 compared to net income of $0.7 million for the nine months ended September 30, 2017. The net loss during the nine months ended September 30, 2018 was primarily due to a decrease in contract prices for tons sold from our Pennyrile mine and an increase in freight and handling costs at our Central Appalachia operations as discussed above. Interest expense also increased by $3.5 million during the nine months ended September 30, 2018 compared to the same period in 2017 as discussed above. Net loss was positively impacted by the $6.5 million gain recognized on the sale of Mammoth Inc. shares during the first half of 2018.

~~Adjusted EBITDA~~. Adjusted EBITDA for the nine months ended September 30, 2018 decreased by $6.7 million to $13.2 million from $19.9 million for the nine months ended September 30, 2017. Adjusted EBITDA decreased period over period primarily due to the decrease in net income at our Pennyrile and Central Appalachia mining operations as discussed below. Adjusted EBITDA for the nine months ended September 30, 2017 was $19.6 million once the results from discontinued operations were included. We did not incur a gain or loss from discontinued operations 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, 2018 and 2017:

Central Appalachia Nine months ended Nine months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 102.8 $ 76.8 $ 26.0 34.0 %
Freight and handling revenues - - - n/a
Other revenues 0.1 0.1 - 34.6 %
Total revenues 102.9 76.9 26.0 34.0 %
Coal revenues per ton $ 73.37 $ 70.38 $ 2.99 4.2 %
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 82.1 59.7 22.4 37.4 %
Freight and handling costs 8.3 1.8 6.5 349.0 %
Depreciation, depletion and amortization 6.7 5.8 0.9 14.6 %
Selling, general and administrative costs 0.4 0.2 0.2 195.4 %
Cost of operations per ton $ 58.56 $ 54.76 $ 3.80 6.9 %
Net income from continuing operations 5.5 9.4 (3.9 ) (41.1 %)
Adjusted EBITDA from continuing operations 12.5 15.2 (2.7 ) (17.9 %)
Tons sold 1,401.8 1,090.7 311.1 28.5 %

*	~~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 increased by approximately 28.5% to approximately 1.4 million tons for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, primarily due to an increase in demand for met and steam coal tons from this region.

Coal revenues increased by approximately $26.0 million, or 34.0%, to approximately $102.8 million for the nine months ended September 30, 2018 from approximately $76.8 million for the nine months ended September 30, 2017. This increase was primarily due to the increase in demand for met and steam coal sold from this region. Coal revenues per ton for our Central Appalachia segment increased by $2.99, or 4.2%, to $73.37 per ton for the nine months ended September 30, 2018 as compared to $70.38 for the nine months ended September 30, 2017, which was primarily due to an increase of higher priced met coal sold in Central Appalachia compared to the prior period.

Cost of operations increased by $22.4 million, or 37.4%, to $82.1 million for the nine months ended September 30, 2018 from $59.7 million for the nine months ended September 30, 2017. This increase was primarily due to the increase in production and sales from our Central Appalachia operations and an increase in operating costs during the nine months ended September 30, 2018 as compared to the same period in 2017. Our cost of operations per ton of $58.56 for the nine months ended September 30, 2018 increased 6.9% compared to $54.76 per ton for the nine months ended September 30, 2017 due to an increase in operating costs including diesel fuel, contract services and equipment maintenance.

For our Central Appalachia segment, net income was approximately $5.5 million for the nine months ended September 30, 2018, a decrease of $3.9 million in net income as compared to the nine months ended September 30, 2017. The decrease in net income was primarily due to higher cost of operations as discussed above.

~~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, 2018, is presented below. Note that our Northern Appalachia, Rhino Western and Illinois Basin segments currently produce and sell only steam coal.

(In thousands, except per ton data and %) Nine months ended September 30, 2018 Nine months ended September 30, 2017 Increase (Decrease) %*
Met coal tons sold 628.2 575.2 9.2 %
Steam coal tons sold 773.6 515.5 50.1 %
Total tons sold 1,401.8 1,090.7 28.5 %

Met coal revenue $ 64,004 $ 50,131 27.7 %
Steam coal revenue $ 38,840 $ 26,634 45.8 %
Total coal revenue $ 102,844 $ 76,765 34.0 %

Met coal revenues per ton $ 101.89 $ 87.16 16.9 %
Steam coal revenues per ton $ 50.20 $ 51.66 (2.8 %)
Total coal revenues per ton $ 73.37 $ 70.38 4.2 %

Met coal tons produced 392.2 504.6 (22.3 %)
Steam coal tons produced 941.8 631.8 49.1 %
Total tons produced 1,334.0 1,136.4 17.4 %

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

Northern Appalachia Nine months ended Nine months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 12.8 $ 10.5 $ 2.3 21.6 %
Freight and handling revenues - - - n/a
Other revenues 1.6 1.0 0.6 65.0 %
Total revenues 14.4 11.5 2.9 25.2 %
Coal revenues per ton $ 42.17 $ 41.96 $ 0.21 0.5 %
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 17.0 13.0 4.0 30.2 %
Freight and handling costs - - - n/a
Depreciation, depletion and amortization 0.8 0.8 - (1.3 %)
Selling, general and administrative costs - 0.1 (0.1 ) (85.9 %)
Cost of operations per ton $ 56.07 $ 52.11 $ 3.96 7.6 %
Net loss from continuing operations (3.5 ) (2.5 ) (1.0 ) 40.1 %
Adjusted EBITDA from continuing operations (2.7 ) (1.6 ) (1.1 ) 62.1 %
Tons sold 304.0 251.3 52.7 21.0 %

*	~~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 21.0% for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 due to increase in demand for coal from this region.

Coal revenues were approximately $12.8 million for the nine months ended September 30, 2018, an increase of approximately $2.3 million, or 21.6%, from approximately $10.5 million for the nine months ended September 30, 2017. Coal revenues per ton increased by $0.21 or 0.5% to $42.17 per ton for the nine months ended September 30, 2018, as compared to $41.96 for the nine months ended September 30, 2017, which was primarily due to higher contracted prices for tons sold during the period.

Cost of operations increased by $4.0 million, or 30.2%, to $17.0 million for the nine months ended September 30, 2018 from $13.0 million for the nine months ended September 30, 2017. Our cost of operations per ton was $56.07 for the nine months ended September 30, 2018, an increase of $3.96, or 7.6%, compared to $52.11 for the nine months ended September 30, 2017. Total cost of operations increased period over period as we increased sales in the region and we incurred increases in operating costs. The increase in cost of operations per ton in Northern Appalachia was primarily due to the increase in maintenance costs and costs for outside services during the nine months ended September 30, 2018. We also experienced adverse geological conditions during the third quarter of 2018.

Net loss in our Northern Appalachia segment was $3.5 million for the nine months ended September 30, 2018 compared to net loss of $2.5 million for the nine months ended September 30, 2017. The increase in net loss for the nine months ended September 30, 2018 was primarily due to the increase in operating expenses as discussed above compared to the same period in 2017.

Rhino Western Nine months ended Nine months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 27.0 $ 25.1 $ 1.9 7.3 %
Freight and handling revenues - - - n/a
Other revenues - - - 218.2 %
Total revenues 27.0 25.1 1.9 7.3 %
Coal revenues per ton $ 35.58 $ 37.99 $ (2.41 ) (6.4 %)
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 22.8 20.1 2.7 13.7 %
Freight and handling costs - - - n/a
Depreciation, depletion and amortization 3.1 3.4 (0.3 ) (9.3 %)
Selling, general and administrative costs 0.1 0.1 - 37.0 %
Cost of operations per ton $ 30.06 $ 30.30 $ (0.24 ) (0.8 %)
Net income/(loss) from continuing operations 1.0 1.6 (0.6 ) (39.1 %)
Adjusted EBITDA from continuing operations 4.0 5.0 (1.0 ) (18.7 %)
Tons sold 758.1 661.7 96.4 14.6 %

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

~~Coal sales from our Rhino Western segment increased by approximately 14.6% for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to increased customer demand.~~

Coal revenues increased by approximately $1.9 million, or 7.3%, to approximately $27.0 million for the nine months ended September 30, 2018 from approximately $25.1 million for the nine months ended September 30, 2017 primarily due to an increase in tons sold from the Castle Valley mine for the nine months ended September 30, 2018. Coal revenues per ton for our Rhino Western segment decreased by $2.41 or 6.4% to $35.58 per ton for the nine months ended September 30, 2018 as compared to $37.99 per ton for the nine months ended September 30, 2017 due to lower contracted sale prices.

Cost of operations increased by $2.7 million, or 13.7%, to $22.8 million for the nine months ended September 30, 2018 from $20.1 million for the nine months ended September 30, 2017. Total cost of operations increased period over period as we increased sales in the region and we incurred higher operating costs. The cost of operations per ton was $30.06 for the nine months ended September 30, 2018, a decrease of $0.24, or 0.8%, compared to $30.30 for the nine months ended September 30, 2017. The decrease in the cost of operations per ton was primarily due to fixed operating costs being allocated to higher tons of coal sold during the nine months ended September 30, 2018.

Net income in our Rhino Western segment was $1.0 million for the nine months ended September 30, 2018, compared to net income of $1.6 million for the nine months ended September 30, 2017. This decrease in net income was primarily the result of lower contracted sale prices for tons sold at our Castle Valley operation.

Illinois Basin Nine months ended Nine months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(in millions, except per ton data and %)

Coal revenues $ 37.8 $ 49.4 $ (11.6 ) (23.5 %)
Freight and handling revenues - - - n/a
Other revenues - - - n/a
Total revenues 37.8 49.4 (11.6 ) (23.6 %)
Coal revenues per ton $ 39.05 $ 48.71 $ (9.66 ) (19.8 %)
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) 39.2 41.8 (2.6 ) (6.2 %)
Freight and handling costs - - - n/a
Depreciation, depletion and amortization 5.9 5.7 0.2 3.2 %
Selling, general and administrative costs 0.2 0.1 0.1 12.9 %
Cost of operations per ton $ 40.59 $ 41.26 $ (0.67 ) (1.6 %)
Net (loss)/income from continuing operations (7.4 ) 1.7 (9.1 ) (528.7 %)
Adjusted EBITDA from continuing operations (1.5 ) 7.4 (8.9 ) (120.8 %)
Tons sold 966.7 1,013.6 (46.9 ) (4.6 %)

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

For our Illinois Basin segment, tons of coal sold decreased by approximately 4.6% for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 due to timing of shipments.

Coal revenues of approximately $37.8 million for the nine months ended September 30, 2018 decreased by approximately $11.6 million, or 23.5%, compared to $49.4 million for the nine months ended September 30, 2017. Coal revenues per ton for our Illinois Basin segment were $39.05 for the nine months ended September 30, 2018, a decrease of $9.66, or 19.8%, from $48.71 for the nine months ended September 30, 2017. The decrease in coal revenues and coal revenues per ton was primarily due to lower contracted prices for tons sold from our Pennyrile mine in western Kentucky during the nine months ended September 30, 2018.

Cost of operations was $39.2 million while cost of operations per ton was $40.59 for the nine months ended September 30, 2018, both of which related to our Pennyrile mining complex in western Kentucky. For the nine months ended September 30, 2017, cost of operations in our Illinois Basin segment was $41.8 million and cost of operations per ton was $41.26. The decrease in cost of operations for the nine months ended September 30, 2018 was primarily the result of a decrease in production and sales during the period.

For our Illinois Basin segment, we generated a net loss of $7.4 million for the nine months ended September 30, 2018, which was a decrease in net income of $9.1 million compared to the nine months ended September 30, 2017. This decrease in net income was primarily the result of a decrease in the contracted sale prices for tons sold and fewer tons shipped during the period.

Other Nine months ended Nine months ended Increase/(Decrease)
September 30, 2018 September 30, 2017 $ % *
(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 $ 0.2 $ - $ 0.2 704.4 %
Total revenues 0.2 - 0.2 704.4 %
Coal revenues per ton** n/a n/a n/a n/a
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below) (1.1 ) (1.7 ) 0.6 (35.8 %)
Freight and handling costs - - - n/a
Depreciation, depletion and amortization 0.2 0.3 (0.1 ) (2.6 %)
Selling, general and administrative costs 7.6 8.0 (0.4 ) (5.6 %)
Cost of operations per ton** n/a n/a n/a n/a
Net loss from continuing operations (6.0 ) (9.5 ) 3.5 (37.3 %)
Adjusted EBITDA from continuing operations 0.9 (6.1 ) 7.0 (115.2 %)
Tons sold 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.

~~Other revenues for our Other category were $0.2 million for the nine months ended September 30, 2018 as compared to $21,000 for the nine months ended September 30, 2017.~~

For the Other category, we had net loss of ~~$6.0~~$7.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 as compared to net loss of ~~$9.5~~$2.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018. The ~~decrease in~~ net loss for the ~~nine~~six months ended ~~September~~June 30, 2018 was ~~primarily due to~~positively impacted by a gain of $6.5 million recognized on the sale of Mammoth Inc. ~~shares during the first half of 2018 offset by an increase in interest expense of $3.5 million.~~shares.

Reconciliations of Adjusted EBITDA

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

Central Northern Rhino Illinois
Three months ended September 30, 2018 Appalachia Appalachia Western Basin Other Total
(in millions)
Net income/(loss) from continuing operations $ 3.6 $ (0.8 ) $ - $ (3.2 ) $ (4.1 ) $ (4.5 )
Plus:
DD&A 2.2 0.3 1.0 2.0 0.1 5.6
Interest expense - - - - 2.8 2.8
EBITDA from continuing operations† $ 5.8 $ (0.5 ) $ 1.0 $ (1.2 ) $ (1.2 ) $ 3.9
Plus: Provision for doubtful accounts 0.3 $ - $ - $ - $ - $ 0.3
Adjusted EBITDA from continuing operations† 6.1 (0.5 ) 1.0 (1.2 ) (1.2 ) 4.2
EBITDA from discontinued operations - - - - - -
Adjusted EBITDA † $ 6.1 $ (0.5 ) $ 1.0 $ (1.2 ) $ (1.2 ) $ 4.2

	Central		Northern			Rhino		Illinois
Three months ended June 30, 2019	Appalachia		Appalachia			Western		Basin			Other			Total
	(in millions)
Net income/(loss)	$	6.6	$	(0.7	)	$	1.3	$	(2.8	)	$	(4.3	)	$	0.1
Plus:
DD&A		1.9		0.4			1.1		2.1			0.1			5.6
Interest expense		-		-			-		-			1.7			1.7
EBITDA†*	$	8.5	$	(0.3	)	$	2.4	$	(0.7	)	$	(2.5	)	$	7.4
Plus: Loss from sale of non-core assets (1)							0.1								0.1
Adjusted EBITDA †	$	8.5	$	(0.3	)	$	2.5	$	(0.7	)	$	(2.5	)	$	7.5

Central Northern Rhino Illinois
Three months ended September 30, 2017 Appalachia Appalachia Western Basin Other Total
(in millions)
Net income/(loss) from continuing operations $ 3.8 $ (0.5 ) $ 1.4 $ 0.1 $ (2.7 ) $ 2.1
Plus:
DD&A 1.9 0.3 1.1 1.8 - 5.1
Interest expense - - - - 1.0 1.0
EBITDA from continuing operations† $ 5.7 $ (0.2 ) $ 2.5 $ 1.9 $ (1.7 ) $ 8.2
Adjusted EBITDA from continuing operations† 5.7 (0.2 ) 2.5 1.9 (1.7 ) 8.2
EBITDA from discontinued operations - (0.3 ) - - - (0.3 )
Adjusted EBITDA $ 5.7 $ (0.5 ) $ 2.5 $ 1.9 $ (1.7 ) $ 7.9

	Central		Northern			Rhino		Illinois
Three months ended June 30, 2018	Appalachia		Appalachia			Western		Basin			Other			Total
	(in millions)
Net (loss)/income	$	1.0	$	(1.5	)	$	-	$	(1.9	)	$	(0.6	)	$	(3.0	)
Plus:															-
DD&A		2.3		0.3			1.0		2.0			0.1			5.7
Interest expense		-		-			-		-			1.9			1.9
EBITDA †	$	3.3	$	(1.2	)	$	1.0	$	0.1		$	1.4		$	4.6
Adjusted EBITDA †	$	3.3	$	(1.2	)	$	1.0	$	0.1		$	1.4		$	4.6

Central Northern Rhino Illinois
Nine months ended September 30, 2018 Appalachia Appalachia Western Basin Other Total
(in millions)
Net income/(loss) from continuing operations $ 5.5 $ (3.5 ) $ 1.0 $ (7.4 ) $ (6.0 ) $ (10.4 )
Plus:
DD&A 6.7 0.8 3.1 5.9 0.2 16.7
Interest expense - - - - 6.6 6.6
EBITDA from continuing operations† $ 12.2 $ (2.7 ) $ 4.1 $ (1.5 ) $ 0.8 $ 12.9
Plus: Provision for doubtful accounts 0.3 - - - - 0.3
Adjusted EBITDA from continuing operations† 12.5 (2.7 ) 4.1 (1.5 ) 0.8 13.2
EBITDA from discontinued operations - - - - - -
Adjusted EBITDA † $ 12.5 $ (2.7 ) $ 4.1 $ (1.5 ) $ 0.8 $ 13.2
Central Northern Rhino Illinois
Nine months ended September 30, 2017 Appalachia Appalachia Western Basin Other Total*
(in millions)
Net income/(loss) from continuing operations $ 9.4 $ (2.5 ) $ 1.6 $ 1.7 $ (9.5 ) $ 0.7
Plus:
DD&A 5.8 0.8 3.4 5.7 0.3 16.0
Interest expense - - - - 3.1 3.1
EBITDA from continuing operations†* $ 15.2 $ (1.7 ) $ 5.0 $ 7.4 $ (6.1 ) $ 19.9
Adjusted EBITDA from continuing operations†* 15.2 (1.7 ) 5.0 7.4 (6.1 ) 19.9
EBITDA from discontinued operations - (0.3 ) - - - (0.3 )
Adjusted EBITDA †* $ 15.2 $ (2.0 ) $ 5.0 $ 7.4 $ (6.1 ) $ 19.6

	Central		Northern			Rhino		Illinois
Six months ended June 30, 2019	Appalachia		Appalachia			Western		Basin			Other			Total
	(in millions)
Net income/(loss)	$	7.7	$	(1.8	)	$	1.0	$	(6.4	)	$	(7.7	)	$	(7.2	)
Plus:
DD&A		3.8		0.8			2.2		4.2			0.2			11.2
Interest expense		-		-			-		-			3.4			3.4
EBITDA†*	$	11.5	$	(1.0	)	$	3.2	$	(2.2	)	$	(4.1	)	$	7.4
Plus: Loss from sale of non-core assets (1)							0.8								0.8
Adjusted EBITDA †	$	11.5	$	(1.0	)	$	4.0	$	(2.2	)	$	(4.1	)	$	8.2

*	~~Totals may not foot due to rounding.~~

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

	Central		Northern			Rhino		Illinois
Six months ended June 30, 2018	Appalachia		Appalachia			Western		Basin			Other			Total
	(in millions)
Net (loss)/income	$	1.9	$	(2.5	)	$	0.9	$	(4.2	)	$	(2.0	)	$	(5.9	)
Plus:															-
DD&A		4.5		0.4			2.1		3.9			0.2			11.1
Interest expense		-		-			-		-			3.8			3.8
EBITDA †	$	6.4	$	(2.1	)	$	3.0	$	(0.3	)	$	2.0		$	9.0
Adjusted EBITDA †	$	6.4	$	(2.1	)	$	3.0	$	(0.3	)	$	2.0		$	9.0

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(in millions)
Net cash (used in)/provided by operating activities	$	(1.7	)	$	(1.7	)	$	(1.2	)	$	6.6
Plus:
Increase in net operating assets		2.2			1.9			1.7			-
Gain on sale of assets		6.9			3.5			6.6			6.4
Interest expense		1.7			1.9			3.4			3.8
Decrease in deferred revenue		-			0.2			-			0.2
Less:
Decrease in net operating assets		-			-						5.7
Amortization of advance royalties		0.6			0.2			1.0			0.4
Amortization of debt discount		0.1			0.1			0.2			0.2
Amortization of debt issuance costs		0.6			0.4			1.1			0.8
Loss on retirement of advance royalties		0.1			-			0.2			0.1
Equity based compensation		-			0.2			-			0.2
Accretion on asset retirement obligations		0.3			0.3			0.6			0.6
EBITDA†		7.4			4.6			7.4			9.0
Plus: Loss from sale of non-core assets (1)		0.1			-			0.8			-
Adjusted EBITDA†	$	7.5		$	4.6		$	8.2		$	9.0

Three months ended September 30, Nine months ended September 30,
2018 2017 2018 2017
(in millions)
Net cash provided by operating activities $ 0.9 $ 5.9 $ 7.5 $ 13.2
Plus:
Increase in net operating assets - 2.0 - 6.9
Gain on sale of assets 0.8 0.1 7.2 0.1
Interest expense 2.8 1.0 6.6 3.1
Decrease in deferred revenue 0.9 - - -
Equity in net income of unconsolidated affiliate - - - 0.1
Less:
Decrease in net operating assets 0.1 - 4.6 -
Amortization of advance royalties 0.1 0.3 0.5 0.9
Amortization of debt issuance costs 0.6 0.4 1.4 1.1
Amortization of debt discount 0.1 - 0.3 -
Loss on retirement of advanced royalties - - 0.1 0.1
Increase in provision for doubtful accounts 0.3 - 0.3 -
Equity-based compensation - - 0.2 0.3
Accretion on asset retirement obligations 0.3 0.4 1.0 1.4
EBITDA† $ 3.9 $ 7.9 $ 12.9 $ 19.6
Plus: Non-cash bad debt expense 0.3 - 0.3 -
Adjusted EBITDA† 4.2 7.9 13.2 19.6
Less: EBITDA from discontinued operations - (0.3 ) - (0.3 )
Adjusted EBITDA from continuing operations † $ 4.2 $ 8.2 $ 13.2 $ 19.9

(1) During the three and six months ended June 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.

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

Liquidity and Capital Resources

Liquidity

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 an additional ~~$40~~$35 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement. We used approximately $17.3 million of the net proceeds thereof to repay all amounts outstanding and terminate the ~~Amended~~amended and ~~Restated Credit Agreement~~restated credit agreement with PNC Bank. The Financing Agreement terminates on December 27, 2020. For more information about our ~~new~~ Financing Agreement, please read “—Financing Agreement” 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. We may also be required to consider other options, such as selling assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time.

We continue to take measures, including the suspension of cash distributions on our common and subordinated units and ~~cost~~taking steps to improve productivity and ~~productivity improvements,~~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 $1.2 million for the six months ended June 30, 2019 as compared to net cash provided by operating activities ~~was $7.5~~of $6.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018 as compared to $13.2 million for the nine months ended September 30, 2017.~~2018. This decrease in cash provided by operating activities was ~~primarily~~ the result of ~~lower~~a higher net ~~income as discussed above.~~loss and negative working capital changes primarily due to the increase in our inventory during the six months ended June 30, 2019.

Net cash used in investing activities was ~~$3.8~~$0.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 as compared to net cash used in investing activities of ~~$12.9~~$0.1 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017.~~2018. The decrease in cash ~~used in~~provided by investing activities was primarily due to ~~the~~a decrease in proceeds ~~received~~ from the sale of ~~Mammoth Inc. shares~~assets during the six months ended June 30, 2019 partially offset by ~~an increase~~a decrease in capital expenditures ~~for~~during the ~~nine~~first six months ~~ended September 30,~~of 2019 compared to the same period in 2018.

Net cash used in financing activities was ~~$19.3~~$3.1 million and $20.9 million for the ~~nine~~six months ended ~~September~~June 30, 2019 and 2018, ~~which~~respectively. Net cash used in financing activities for the six months ended June 30, 2018 was primarily attributable to repayments on our Financing Agreement and deposits paid on our workers’ compensation and surety bond programs. The periods ending June 30, 2019 and 2018 were both impacted by payment of the distribution on the Series A preferred units. ~~Net cash used in financing activities was $0.3 million for the nine months ended September 30, 2017, which was primarily due to payments of debt issuance costs.~~

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 ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 were approximately ~~$11.2~~$3.7 million. ~~These amounts were~~This amount was primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 were approximately ~~$9.3~~$0.6 million, which were primarily related to the ~~purchase~~construction of ~~additional equipment to expand production~~a new airshaft at ~~one of~~ our ~~Central Appalachia mines.~~

Hopedale mining complex in Northern Appalachia.

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”)~~, an entity wholly owned by certain investment partnerships managed by Yorktown,~~ and Royal. Under the Preferred Unit Agreement, Weston and Royal agreed to purchase 1,300,000 and 200,000, respectively, of Series A preferred units representing limited partner interests in 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.

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

The Preferred Unit Agreement stipulates that upon the request of the holder of the majority of our common units following their conversion from Series A preferred units, as outlined in our partnership agreement, we will enter into a registration rights agreement with such holder. Such majority holder has the right to demand two shelf registration statements and registration statements on Form S-1, as well as piggyback registration rights.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 Series A preferred units rank senior to all classes or series of our equity securities 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 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. The Series A preferred units will be liquidated in accordance with their capital accounts and upon liquidation will be entitled to distributions of property and cash in accordance with the balances of their capital accounts prior to such distributions to equity securities that rank junior to the Series A preferred units.

The Series A preferred units vote on an as-converted basis with the common units, and we are 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 us or our affiliates that is in existence at the time of such acquisition or (vi) the modification of CAM Mining’s accounting principles or the financial or operational reporting principles of our Central Appalachia business segment, subject to certain exceptions.

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 to holders of the Series A preferred units.~~2017. We have accrued approximately ~~$1.8~~$0.6 million for distributions to holders of the Series A preferred units for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~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 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 for which were satisfied at the execution of the Financing Agreement (the “Effective Date Term Loan Commitment”) and an additional ~~$40~~$35 million commitment that is contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement (“Delayed Draw Term Loan Commitment”). Loans made pursuant to the Financing Agreement are secured by substantially all of our assets. The Financing Agreement terminates on December 27, 2020.

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 due on December 27, 2020. 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.

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 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.

At ~~September~~June 30, ~~2018,~~2019, we had ~~$29.8~~$28.3 million of borrowings outstanding at a variable interest rate of Libor plus 10.00% ~~(12.25%) and $5.0 million of borrowings outstanding at a fixed interest rate of 12.34%.~~

~~Letter of Credit Facility-PNC Bank~~

On December 27, 2017, we entered into a master letter of credit facility, security agreement and reimbursement agreement (the “LoC Facility Agreement”) with PNC Bank, National Association (“PNC”), pursuant to which PNC agreed to provide us with a facility for the issuance of standby letters of credit used in the ordinary course of our business (the “LoC Facility”(12.41%). The LoC Facility Agreement provided that we pay a quarterly fee at a rate equal to 5% per annum calculated based on the daily average of letters of credit outstanding under the LoC Facility, as well as administrative costs incurred by PNC and a $100,000 closing fee. The LoC Facility Agreement provided that we reimburse PNC for any drawing under a letter of credit by a specified beneficiary as soon as possible after payment was made. Our obligations under the LoC Facility Agreement were secured by a first lien security interest on a cash collateral account that is required to contain no less than 105% of the face value of the outstanding letters of credit. In the event the amount in such cash collateral account was insufficient to satisfy our reimbursement obligations, the amount outstanding would bear interest at a rate per annum equal to the Base Rate (as that term was defined in the LoC Facility Agreement) plus 2.0%. We would indemnify PNC for any losses which PNC may incur as a result of the issuance of a letter of credit or PNC’s failure to honor any drawing under a letter of credit, subject in each case to certain exceptions. We provided cash collateral to our counterparties during the third quarter of 2018 and as of September 30, 2018, the LoC Facility was terminated. We had no outstanding letters of credit at September 30, 2018.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. No liabilities related to these arrangements are reflected in our consolidated ~~balance sheet,~~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, either of which would require a greater use of our liquidity.~~credit. We then ~~have historically used bank letters of credit~~provide cash collateral to secure our surety bonding obligations asin an amount up to a ~~lower cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank letters of credit as a~~certain percentage of ~~our aggregate bond liability. We recently terminated our letter of credit facility and have provided cash collateral as a percentage of our~~the aggregate bond liability ~~to secure our~~that we negotiate with the surety ~~bonding obligations.~~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 June 30, 2019, we had $7.9 million in cash collateral held by third-parties of which $3.0 million serves as collateral for approximately $39.2 million in surety bonds outstanding that secure the performance of our reclamation obligations. The other $4.9 million serves as collateral for our self-insured workers’ compensation program. Of the $39.2 million in surety bonds, approximately $0.4 million relates to surety bonds for Deane Mining, LLC, which have not been transferred or replaced by the buyers of Deane Mining LLC as was agreed to by the parties as part of the transaction. We can provide no assurances that a surety company will underwrite the surety bonds of the purchaser of 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 buyer of Deane Mining, LLC, then we may be responsible to the surety company for any amounts it pays in respect of such claim. While the buyer is required to indemnify us for damages, including reclamation liabilities, pursuant the agreements governing the sales of this entity, we may not be successful in obtaining any indemnity or any amounts received may be inadequate. Of the $39.2 million in outstanding surety bonds, approximately $3.4 million related to surety bonds for Sands Hill Mining LLC, which are to be replaced by a third party pursuant to an agreement dated July 9, 2019. Please refer to Note 19 of the notes to the unaudited condensed consolidated financial statements for further discussion of the agreement.

~~As discussed above, we~~

We had no letters of credit outstanding as of ~~September~~June 30, ~~2018.~~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, ~~2017.~~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 ~~September~~June 30, ~~2018.~~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 unaudited condensed consolidated statements of operations. Please refer to Note 5 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 ~~September~~June 30, ~~2018~~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 ~~September~~June 30, ~~2018~~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.

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, ~~2017,~~2018, which risks could materially affect our business, financial condition or future results. ~~There~~Except 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, ~~2017.~~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 ~~September~~June 30, ~~2018~~2019 is included inas Exhibit 95.1 to this report.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number		Description

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 October 5, 2010, by and between Rhino Resource Partners LP and Rhino Energy Holdings LLC, incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 8, 2010

~~4.2~~		~~Registration Rights Agreement, dated as of~~ March 21, 2016, by and between Rhino Resource Partners LP and Royal Energy Resources, Inc., incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on March 23, 2016

~~10.1~~4.2*		~~Consent to Financing Agreement dated as~~Form of July 27, 2018, 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. 001-34982) filed on July 31, 2018.

10.2*		First amendment to Financing Agreement dated as of November 8, 2018, 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 AgentCommon Unit Warrant.

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 ~~September 30, 2018~~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.

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: ~~November~~August 9, ~~2018~~2019	By:	/s/ Richard A. Boone
		Richard A. Boone
		President, Chief Executive Officer and Director
		(Principal Executive Officer)

Date: ~~November~~August 9, ~~2018~~2019	By:	/s/ W. Scott Morris
		W. Scott Morris
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

RHINO RESOURCE PARTNERS LP
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME
(in thousands, except per unit data)

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2018			2017			2018			2017
REVENUES:
Coal sales	$	71,866		$	56,266		$	180,383		$	161,820
Other revenues		699			420			1,906			1,098
Total revenues		72,565			56,686			182,289			162,918
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		60,786			44,751			160,031			132,939
Freight and handling costs		5,848			1,237			8,225			1,832
Depreciation, depletion and amortization		5,629			5,060			16,733			16,037
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)		2,785			2,663			8,281			8,419
(Gain) on sale/disposal of assets—net		(784	)		(83	)		(7,217	)		(38	)
Total costs and expenses		74,264			53,628			186,053			159,189
(LOSS)/INCOME FROM OPERATIONS		(1,699	)		3,058			(3,764	)		3,729
INTEREST AND OTHER EXPENSE/(INCOME):
Interest expense		2,831			1,011			6,629			3,131
Interest income and other		-			(86	)		(7	)		(86	)
Equity in net (income) of unconsolidated affiliates		-			-			-			(36	)
Total interest and other expense		2,831			925			6,622		��	3,009
NET (LOSS)/INCOME BEFORE INCOME TAXES FROM CONTINUING OPERATIONS		(4,530	)		2,133			(10,386	)		720
INCOME TAXES		-			-			-			-
NET (LOSS)/INCOME FROM CONTINUING OPERATIONS		(4,530	)		2,133			(10,386	)		720
DISCONTINUED OPERATIONS (NOTE 3)
Loss from discontinued operations		-			(461	)		-			(787	)
NET (LOSS)/INCOME		(4,530	)		1,672			(10,386	)		(67	)
Other comprehensive (loss)/income:
Fair market value adjustment for available-for-sale investment		(506	)		(990	)		3,874			1,030
Reclass for disposition		-			-			(6,621	)		-
Total other comprehensive (loss)/income		(506	)		(990	)		(2,747	)		1,030
COMPREHENSIVE (LOSS)/INCOME	$	(5,036	)	$	682		$	(13,133	)	$	963

General partner’s interest in net (loss)/income:
Net (loss)/income from continuing operations	$	(24	)	$	2		$	(51	)	$	(15	)
Net (loss) from discontinued operations		-			(1	)		-			(3	)
General partner’s interest in net (loss)/income	$	(24	)	$	1		$	(51	)	$	(18	)
Common unitholders’ interest in net (loss)/income:
Net (loss)/income from continuing operations	$	(5,228	)	$	445		$	(11,144	)	$	(3,088	)
Net (loss) from discontinued operations		-			(420	)		-			(715	)
Common unitholders’ interest in net (loss)/income:	$	(5,228	)	$	25		$	(11,144	)	$	(3,803	)
Subordinated unitholders’ interest in net (loss)/income:
Net (loss)/income from continuing operations	$	(457	)	$	42		$	(979	)	$	(295	)
Net (loss) from discontinued operations		-			(40	)		-			(69	)
Subordinated unitholders’ interest in net (loss)/income:	$	(457	)	$	2		$	(979	)	$	(364	)
Preferred unitholders’ interest in net income:
Net income from continuing operations	$	1,179		$	1,644		$	1,788		$	4,118
Net income from discontinued operations		-			-			-			-
Preferred unitholders’ interest in net income	$	1,179		$	1,644		$	1,788		$	4,118
Net (loss)/income per limited partner unit, basic:
Common units:
Net (loss)/income per unit from continuing operations	$	(0.40	)	$	0.03		$	(0.86	)	$	(0.24	)
Net (loss) per unit from discontinued operations		-			(0.03	)		-			(0.05	)
Net (loss) per common unit, basic	$	(0.40	)	$	-		$	(0.86	)	$	(0.29	)
Subordinated units
Net (loss)/income per unit from continuing operations		(0.40	)	$	0.03		$	(0.86	)	$	(0.24	)
Net (loss) per unit from discontinued operations		-			(0.03	)		-			(0.05	)
Net (loss) per subordinated unit, basic	$	(0.40	)	$	-		$	(0.86	)	$	(0.29	)
Preferred units
Net income per unit from continuing operations	$	0.79		$	1.10		$	1.19		$	2.75
Net income per unit from discontinued operations		-			-			-			-
Net income per preferred unit, basic	$	0.79		$	1.10		$	1.19		$	2.75
Net (loss)/income per limited partner unit, diluted:
Common units
Net (loss)/income per unit from continuing operations	$	(0.40	)	$	0.03		$	(0.86	)	$	(0.24	)
Net (loss) per unit from discontinued operations		-			(0.03	)		-			(0.05	)
Net (loss) per common unit, diluted	$	(0.40	)	$	-		$	(0.86	)	$	(0.29	)
Subordinated units
Net (loss)/income per unit from continuing operations	$	(0.40	)	$	0.03		$	(0.86	)	$	(0.24	)
Net (loss) per unit from discontinued operations		-			(0.03	)		-			(0.05	)
Net (loss) per subordinated unit, diluted	$	(0.40	)	$	-		$	(0.86	)	$	(0.29	)
Preferred units
Net income per unit from continuing operations	$	0.79		$	1.10		$	1.19		$	2.75
Net income per unit from discontinued operations		-			-			-			-
Net income per preferred unit, diluted	$	0.79		$	1.10		$	1.19		$	2.75

Weighted average number of limited partner units outstanding, basic:
Common units		13,098			12,994			13,035			12,942
Subordinated units		1,146			1,236			1,146			1,236
Preferred units		1,500			1,500			1,500			1,500
Weighted average number of limited partner units outstanding, diluted:
Common units		13,098			12,994			13,035			12,942
Subordinated units		1,146			1,236			1,146			1,236
Preferred units		1,500			1,500			1,500			1,500

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	$	(51	)	$	(11,144	)	$	(979	)	$	1,788
Net (loss)/income from discontinued operations		-			-			-			-
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		$	(0.86	)	$	(0.86	)	$	1.19
Net (loss)/income per unit from discontinued operations		n/a			-			-			-
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		$	(0.86	)	$	(0.86	)		1.19
Net (loss)/income per unit from discontinued operations		n/a			-			-			-
Net (loss)/income per common unit, diluted		n/a		$	(0.86	)	$	(0.86	)		1.19

Nine months ended September 30, 2017	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	$	(15	)	$	(3,088	)	$	(295	)		4,118
Net (loss) from discontinued operations		(3	)		(715	)		(69	)		-
Total interest in net (loss)/income	$	(18	)	$	(3,803	)	$	(364	)		4,118
Denominator:
Weighted average units used to compute basic EPU		n/a			12,942			1,236			1,500
Weighted average units used to compute diluted EPU		n/a			12,942			1,236			1,500

Net (loss)/income per limited partner unit, basic
Net (loss)/income per unit from continuing operations		n/a		$	(0.24	)	$	(0.24	)	$	2.75
Net (loss) per unit from discontinued operations		n/a			(0.05	)		(0.05	)		-
Net (loss)/income per common unit, basic		n/a		$	(0.29	)	$	(0.29	)	$	2.75
Net (loss)/income per limited partner unit, diluted
Net (loss)/income per unit from continuing operations		n/a		$	(0.24	)	$	(0.24	)	$	2.75
Net (loss) per unit from discontinued operations		n/a			(0.05	)		(0.05	)		-
Net (loss)/income per common unit, diluted		n/a		$	(0.29	)	$	(0.29	)	$	2.75

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
	(in millions)
Net cash provided by operating activities	$	0.9	$	5.9		$	7.5	$	13.2
Plus:
Increase in net operating assets		-		2.0			-		6.9
Gain on sale of assets		0.8		0.1			7.2		0.1
Interest expense		2.8		1.0			6.6		3.1
Decrease in deferred revenue		0.9		-			-		-
Equity in net income of unconsolidated affiliate		-		-			-		0.1
Less:
Decrease in net operating assets		0.1		-			4.6		-
Amortization of advance royalties		0.1		0.3			0.5		0.9
Amortization of debt issuance costs		0.6		0.4			1.4		1.1
Amortization of debt discount		0.1		-			0.3		-
Loss on retirement of advanced royalties		-		-			0.1		0.1
Increase in provision for doubtful accounts		0.3		-			0.3		-
Equity-based compensation		-		-			0.2		0.3
Accretion on asset retirement obligations		0.3		0.4			1.0		1.4
EBITDA†	$	3.9	$	7.9		$	12.9	$	19.6
Plus: Non-cash bad debt expense		0.3		-			0.3		-
Adjusted EBITDA†		4.2		7.9			13.2		19.6
Less: EBITDA from discontinued operations		-		(0.3	)		-		(0.3	)
Adjusted EBITDA from continuing operations †	$	4.2	$	8.2		$	13.2	$	19.9