Rhino Resource Partners LP - FORM 10-Q

Attached files

file	filename
EX-95.1 - Rhino Resource Partners LP	ex95-1.htm
EX-32.2 - Rhino Resource Partners LP	ex32-2.htm
EX-32.1 - Rhino Resource Partners LP	ex32-1.htm
EX-31.2 - Rhino Resource Partners LP	ex31-2.htm
EX-31.1 - Rhino Resource Partners LP	ex31-1.htm
EX-10.2 - Rhino Resource Partners LP	ex10-2.htm

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 30, 2018

[ ]

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

For the transition period from ________ to ________

Commission file number 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

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 2, 2018, 13,098,353 common units, 1,145,743 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 30, 2018 and December 31, 2017	4
Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2018 and 2017	5
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 4. Controls and Procedures	48
PART II—Other Information	48
Item 1. Legal Proceedings	48
Item 1A. Risk Factors	48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3. Defaults upon Senior Securities	48
Item 4. Mine Safety Disclosure	48
Item 5. Other Information	48
Item 6. Exhibits	49
SIGNATURES	51

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, (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

See notes to unaudited condensed consolidated financial statements.

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine Months Ended September 30,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)	$	(10,386	)	$	(67	)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		16,733			16,495
Accretion on asset retirement obligations		954			1,422
Amortization of advance royalties		502			876
Amortization of debt issuance costs		1,432			1,068
Provision for doubtful accounts		294			-
Amortization of debt discount		316			-
Equity in net loss/(income) of unconsolidated affiliates		-			(36	)
Loss on retirement of advance royalties		108			136
(Gain) on sale/disposal of assets—net		(719	)		(40	)
(Gain) on sale of Mammoth shares		(6,498	)		-
Equity based compensation		230			260
Changes in assets and liabilities:
Accounts receivable		(5,223	)		(4,820	)
Inventories		3,319			(3,285	)
Advance royalties		(904	)		(962	)
Prepaid expenses and other assets		(1,618	)		(1,923	)
Accounts payable		8,865			1,239
Accrued expenses and other liabilities		391			2,888
Asset retirement obligations		(259	)		(34	)
Net cash provided by operating activities		7,537			13,217
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment		(20,525	)		(14,306	)
Proceeds from sales of property, plant, and equipment		4,802			506
Proceeds from business disposal		-			890
Proceeds from sale of Mammoth shares		11,887			-
Net cash used in investing activities		(3,836	)		(12,910	)
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	)		-
Proceeds from issuance of other debt		1,622			-
Repayments on other debt		(540	)		-
Deposit for workers’ compensation and surety programs		(8,209	)		-
Payments on debt issuance costs		(879	)		(227	)
Preferred distributions paid		(6,039	)		-
Net cash used in financing activities		(19,253	)		(327	)
NET (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(15,552	)		(20	)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH—Beginning of period		21,120			47
CASH, CASH EQUIVALENTS AND RESTRICTED CASH—End of period	$	5,568		$	27

Summary Statement of Financial Position:
Cash and cash equivalents	$	5,568		$	27
Restricted cash		-			-
	$	5,568		$	27

See notes to unaudited condensed consolidated financial statements.

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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 30, 2018, condensed consolidated statements of operations and comprehensive income for the three and nine months ended September 30, 2018 and 2017 and the condensed consolidated statements of cash flows for the nine months ended September 30, 2018 and 2017 include all adjustments that the Partnership considers necessary for a fair presentation of the financial position, operating results and cash flows for the periods presented. The condensed consolidated statement of financial position as of December 31, 2017 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 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 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 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 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. 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.

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 in Unconsolidated Affiliates. Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Partnership is determined to be 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.

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 in the first quarter of 2019 and elect this transition method to apply the standard prospectively. While the Partnership is currently evaluating the impact of adoption of this ASU, the adoption is expected to result in a material increase in the assets and liabilities recorded on the Condensed Consolidated Balance Sheets.

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 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 30, 2018 and December 31, 2017 consisted of the following:

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

5. PROPERTY, PLANT AND EQUIPMENT

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

	Useful Lives	September 30, 2018			December 31, 2017
		(in thousands)
Land		$	13,783		$	14,687
Mining and other equipment and related facilities	2 - 20 Years		305,595			298,293
Mine development costs	1 - 15 Years		60,422			58,566
Coal properties	1 - 15 Years		64,070			64,070
Construction work in process			6,437			5,227
Total			450,307			440,843
Less accumulated depreciation, depletion and amortization			(273,518	)		(263,520	)
Net		$	176,789		$	177,323

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties, amortization expense for mine development costs and amortization expense for asset retirement costs for the three and nine months ended September 30, 2018 and 2017 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	4,276	$	3,843	$	12,607	$	12,324
Depletion expense for coal properties and oil and natural gas properties		467		450		1,419		1,221
Amortization expense for mine development costs		777		721		2,348		2,265
Amortization expense for asset retirement costs		109		46		359		227
Total depreciation, depletion and amortization	$	5,629	$	5,060	$	16,733	$	16,037

On May 17, 2018, the Partnership entered into a sale leaseback agreement with Wintrust Commercial Finance for certain equipment previously owned by the Partnership. The Partnership received approximately $3.7 million of proceeds, of which $1.7 million was used to reduce debt. The lease agreement has a thirty-six month term. The Partnership recorded a loss of $0.2 million on the sale of the equipment which is included on the (Gain)/Loss on sale/disposal of assets-net line in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

6. OTHER NON-CURRENT ASSETS

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

	September 30, 2018			December 31, 2017
	(in thousands)
Deposits and other	$	1,260		$	423
Due (to)/from Rhino GP		(30	)		(61	)
Non-current receivable		27,806			27,806
Deferred expenses		318			340
Total	$	29,354		$	28,508

Non-current receivable. The non-current receivable balance of $27.8 million as of September 30, 2018 and December 31, 2017 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 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 30, 2018 and December 31, 2017 consisted of the following:

	September 30, 2018		December 31, 2017
	(in thousands)
Payroll, bonus and vacation expense	$	1,988	$	2,633
Non income taxes		2,878		2,738
Royalty expenses		1,713		2,410
Accrued interest		161		132
Health claims		746		871
Workers’ compensation & pneumoconiosis		1,750		1,750
Other		1,280		652
Total	$	10,516	$	11,186

8. DEBT

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

	September 30, 2018			December 31, 2017
	(in thousands)
Note payable-Financing Agreement	$	34,778		$	40,000
Note payable-other debt		1,095			-
Net unamortized debt issuance costs		(4,135	)		(4,688	)
Net unamortized original issue discount		(948	)		(1,264	)
Total		30,790			34,048
Less current portion		(7,595	)		(5,475	)
Long-term debt	$	23,195		$	28,573

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 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 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, 2018, the Partnership had $29.8 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”). 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 months ended September 30, 2018 and the year ended December 31, 2017 are as follows:

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

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 months ended September 30, 2018 and 2017 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

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

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) (“Mammoth Inc.”) 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 and December 31, 2017, the Partnership recorded 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 investment in Mammoth Inc. in its Other category for segment reporting purposes. As of September 30, 2018, the Partnership owned 104,100 shares of Mammoth Inc.

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, 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 30, 2018, the Partnership had accumulated arrearages of $614.5 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 30, 2018 and 2017:

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 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

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

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 for three and nine months ended September 30, 2018 and the nine months ended September 30, 2017, 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 30, 2017 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 months ended September 30, 2018.

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of September 30, 2018, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

Year	Tons (in thousands)		Number of customers
2018 Q4		1,283		14
2019		2,107		10
2020		1,446		6

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

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the three and nine months ended September 30, 2018 and 2017 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,
	2018		2017		2018		2017
	(in thousands)
Lease expense	$	1,242	$	725	$	2,648	$	3,198
Royalty expense	$	3,320	$	3,602	$	10,431	$	10,888

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
	(in thousands)
Javelin Global	$	4,628	$	2,470	$	29,267	$	-
Dominion Energy		593		1,232		17,166		17,148
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 months ended September 30, 2018 and 2017. Other revenues generally consist of coal royalty revenues, coal handling and processing revenues, rebates and rental income, which accounted for approximately 1.0% of the Partnership’s total revenues for the three and nine months ended September 30, 2018 and 2017.

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. 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 30, 2018:

	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated
	(in thousands)
Coal sales
Steam coal	$	13,979	$	5,229	$	10,254	$	12,529	$	-	$	41,991
Met coal		29,875		-		-		-		-		29,875
Other revenue		36		602		-		-		61		699
Total	$	43,890	$	5,831	$	10,254	$	12,529	$	61	$	72,565

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

	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated
	(in thousands)
Coal sales
Steam coal	$	9,580	$	4,361	$	9,080	$	14,960	$	-	$	37,981
Met coal		18,285		-		-		-		-		18,285
Other revenue		27		377		-		5		11		420
Total	$	27,892	$	4,738	$	9,080	$	14,965	$	11	$	56,686

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

	Central Appalachia		Northern Appalachia		Rhino Western		Illinois Basin		Other		Total Consolidated
	(in thousands)
Coal sales
Steam coal	$	38,840	$	12,821	$	26,970	$	37,748	$	-	$	116,379
Met coal		64,004		-		-		-		-		64,004
Other revenue		154		1,576		10		-		166		1,906
Total	$	102,998	$	14,397	$	26,980	$	37,748	$	166	$	182,289

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

	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

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 30, 2018. The fair value of the Partnership’s Financing Agreement is a Level 2 measurement.

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

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash payments for interest were $4.9 million and $2.1 million for the nine months ended September 30, 2018 and 2017, respectively.

The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2018 and 2017 excludes approximately $1.1 million and $1.3 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 30, 2018, 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 30, 2018 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

	Central		Northern			Rhino		Illinois						Total
	Appalachia		Appalachia			Western		Basin			Other			Consolidated
	(in thousands)
Total revenues	$	43,890	$	5,831		$	10,255	$	12,529		$	60		$	72,565
DD&A		2,200		385			978		1,974			92			5,629
Interest expense		-		-			-		-			2,831			2,831
Net income (loss) from continuing operations	$	3,619	$	(881	)	$	56	$	(3,232	)	$	(4,092	)	$	(4,530	)

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

	Central		Northern			Rhino		Illinois					Total
	Appalachia		Appalachia			Western		Basin		Other			Consolidated
	(in thousands)
Total revenues	$	27,891	$	4,738		$	9,080	$	14,965	$	12		$	56,686
DD&A		1,890		251			1,080		1,755		84			5,060
Interest expense		-		-			-		-		1,011			1,011
Net income (loss) from continuing operations	$	3,785	$	(449	)	$	1,416	$	107	$	(2,726	)	$	2,133

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

	Central		Northern			Rhino		Illinois						Total
	Appalachia		Appalachia			Western		Basin			Other			Consolidated
	(in thousands)
Total revenues	$	102,998	$	14,397		$	26,980	$	37,748		$	166		$	182,289
DD&A		6,659		825			3,080		5,892			277			16,733
Interest expense		1		-			-		-			6,628			6,629
Net income (loss) from continuing operations	$	5,546	$	(3,473	)	$	956	$	(7,441	)	$	(5,974	)	$	(10,386	)

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

	Central		Northern			Rhino		Illinois					Total
	Appalachia		Appalachia			Western		Basin		Other			Consolidated
	(in thousands)
Total revenues	$	76,880	$	11,500		$	25,141	$	49,377	$	20		$	162,918
DD&A		5,812		836			3,396		5,708		285			16,037
Interest expense		-		-			-		-		3,131			3,131
Net income (loss) from continuing operations	$	9,416	$	(2,480	)	$	1,570	$	1,736	$	(9,522	)	$	720

19. SUBSEQUENT EVENTS

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 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.

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.

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, we controlled an estimated 252.7 million tons of proven and probable coal reserves, consisting of an estimated 200.1 million tons of steam coal and an estimated 52.6 million tons of metallurgical coal. In addition, as of December 31, 2017, we controlled an estimated 185.2 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 months ended September 30, 2018, we generated revenues of approximately $72.6 million and $182.3 million, respectively, and we generated net losses of $4.5 million and $10.4 million for the three and nine months ended September 30, 2018. For the three months ended September 30, 2018, we produced approximately 1.1 million tons of coal and sold approximately 1.3 million tons of coal, of which approximately 60% were sold pursuant to supply contracts. For the nine months ended September 30, 2018, we produced approximately 3.3 million tons of coal and sold approximately 3.4 million tons of coal, of which approximately 65% were sold pursuant to supply contracts.

Current Liquidity and Outlook

As of September 30, 2018, our available liquidity was $5.6 million. We also have a delayed draw term loan commitment in the amount of $40 million (under which we have drawn approximately $5 million) contingent upon the satisfaction of certain conditions precedent specified in the Financing Agreement discussed below.

On December 27, 2017, we entered into a financing agreement (“Financing Agreement”), which provides us with a multi-draw loan in the aggregate principal amount of $80 million. The total principal amount is divided into a $40 million commitment, the conditions for which were satisfied at the execution of the Financing Agreement and an additional $40 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 and Restated Credit Agreement with PNC Bank, National Association, as Administrative Agent. The Financing Agreement terminates on December 27, 2020. For more information about our new Financing Agreement, please read “— 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

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 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 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.

Common Unit Warrants

In December 2017, we entered into a warrant agreement with certain parties that are also parties to the Financing Agreement discussed above. The warrant agreement included the issuance of a total of 683,888 warrants of our common units (“Common Unit Warrants”) at an exercise price of $1.95 per unit, which was the closing price of our 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 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 dilutive to the amount of Rhino’s common units outstanding. The warrant agreement includes a provision for a cashless exercise where the warrant holders can receive a net number of common units. Per the warrant agreement, the warrants are detached from the Financing Agreement and fully transferable.

Letter of Credit Facility – PNC Bank

On December 27, 2017, 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”). 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 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 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 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. 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.

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, 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 30, 2018, we had accumulated arrearages of $614.5 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 30, 2018, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

Year	Tons (in thousands)		Number of customers
2018 Q4		1,283		14
2019		2,107		10
2020		1,446		6

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

Results of Operations

Segment Information

As of September 30, 2018, 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 30, 2018, 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 30, 2018. 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 30, 2018 and 2017:

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

Coal revenues	$	71.9		$	56.3		$	15.6			27.7	%
Other revenues		0.7			0.4			0.3			66.4	%
Total revenues		72.6			56.7			15.9			28.0	%
Costs and expenses:
Cost of operations (exclusive of DD&A shown separately below)		60.8			44.8			16.0			35.8	%
Freight and handling costs		5.8			1.2			4.6			372.7	%
Depreciation, depletion and amortization		5.6			5.1			0.5			11.2	%
Selling, general and administrative (exclusive of DD&A shown separately above)		2.8			2.7			0.1			4.6	%
(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:
Interest expense and other		2.8			1.0			1.8			180.0	%
Interest income and other		-			(0.1	)		0.1			(100.0	%)
Total interest and other (income) expense		2.8			0.9			1.9			206.1	%
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	%)

Total tons sold		1,255.2			1,044.8			210.4			20.1	%
Coal revenues per ton	$	57.25		$	53.86		$	3.39			6.3	%
Cost of operations per ton	$	48.43		$	42.83		$	5.60			13.1	%

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	%)

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

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

Revenues. Our coal revenues for the three months ended September 30, 2018 increased by approximately $15.6 million, or 27.7%, to approximately $71.9 million from approximately $56.3 million for the three months ended September 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. Coal revenues per ton was $57.25 for the three months ended September 30, 2018, an increase of $3.39 or 6.3%, from $53.86 per ton for the three months ended September 30, 2017. This increase in coal revenues per ton was primarily the result of higher contract sale prices for met coal sold from our Central Appalachia operations during the third quarter of 2018 compared to the same period in 2017.

Cost of Operations. Total cost of operations increased by $16.0 million or 35.8% to $60.8 million for the three months ended September 30, 2018 as compared to $44.8 million for the three months ended September 30, 2017. Our cost of operations per ton was $48.43 for the three months ended September 30, 2018, an increase of $5.60, or 13.1%, from the three months ended September 30, 2017. The increase in cost of operations was primarily due to increases in cost of production at our Central Appalachia operations for diesel fuel, contract services and equipment maintenance in the third quarter of 2018.

Freight and Handling. Total freight and handling cost increased to $5.8 million for the three months ended September 30, 2018 from approximately $1.2 million for the three months ended September 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.

Depreciation, Depletion and Amortization. Total DD&A expense for the three months ended September 30, 2018 was $5.6 million as compared to $5.1 million for the three months ended September 30, 2017.

For the three months ended September 30, 2018, our depreciation expense was 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.

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

For the three months ended September 30, 2018 and 2017, our amortization expense remained flat at approximately $0.8 million.

Selling, General and Administrative. SG&A expense for the three months ended September 30, 2018 increased slightly to $2.8 million as compared to $2.7 million for the three months ended September 30, 2017. We recorded a bad debt provision of $0.3 million during the third quarter of 2018.

Interest Expense. Interest expense for the three months ended September 30, 2018 increased to $2.8 million as compared to $1.0 million for the three months ended September 30, 2017. This increase was primarily due to the higher outstanding debt balance and effective interest rate on the new Financing Agreement.

Net Loss. Net loss was $4.5 million for the three months ended September 30, 2018 compared to net income of $2.1 million for the three months ended September 30, 2017. The net loss incurred during the three 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 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.

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

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	%

*	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 37.5% to approximately 0.5 million tons for the three months ended September 30, 2018 compared to the three 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 $16.0 million, or 57.4%, to approximately $43.9 million for the three months ended September 30, 2018 from approximately $27.9 million for the three months ended September 30, 2017. This increase was primarily due to the increase in demand for met and steam coal tons sold from this region. Coal revenues per ton for our Central Appalachia segment increased by $10.57, or 14.5%, to $83.59 per ton for the three months ended September 30, 2018 as compared to $73.02 for the three months ended September 30, 2017. This increase was primarily due to the increase in contract prices for our met coal from this region.

Cost of operations increased by $11.0 million, or 52.6%, to $31.9 million for the three months ended September 30, 2018 from $20.9 million for the three months ended September 30, 2017. Our cost of operations per ton of $60.75 for the three months ended September 30, 2018 increased 11.0% compared to $54.73 per ton for the three months ended September 30, 2017. Total 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 of operations per ton increased as we experienced an increase in diesel fuel, contract services and equipment maintenance during the three months ended September 30, 2018.

Total freight and handling cost increased to $5.8 million for the three months ended September 30, 2018 from approximately $1.2 million for the three months ended September 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.

For our Central Appalachia segment, net income was approximately $3.6 million for the three months ended September 30, 2018, a decrease of $0.2 million in net income as compared to the three months ended September 30, 2017. Net income was impacted by an increase in the cost of operations 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 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 %)	Three months ended September 30, 2018		Three months ended September 30, 2017		Increase (Decrease) %*
Met coal tons sold		264.0		196.8		34.2	%
Steam coal tons sold		260.6		184.8		41.0	%
Total tons sold		524.6		381.6		37.5	%

Met coal revenue	$	29,875	$	18,285		63.4	%
Steam coal revenue	$	13,979	$	9,580		45.9	%
Total coal revenue	$	43,854	$	27,865		57.4	%

Met coal revenues per ton	$	113.17	$	92.93		21.8	%
Steam coal revenues per ton	$	53.64	$	51.82		3.5	%
Total coal revenues per ton	$	83.59	$	73.02		14.5	%

Met coal tons produced		141.7		151.9		(6.7	%)
Steam coal tons produced		302.7		253.8		19.2	%
Total tons produced		444.4		405.7		9.5	%

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% for the three months ended September 30, 2018 compared to the three months ended September 30, 2017 as we experienced increased demand for coal from this region.

Coal revenues were approximately $5.2 million for the three months ended September 30, 2018, an increase of approximately $0.8 million, or 19.9%, from approximately $4.4 million for the three months ended September 30, 2017. Coal revenues per ton increased by $2.67 or 6.5% to $44.05 per ton for the three months ended September 30, 2018, as compared to $41.38 for the three months ended September 30, 2017, which was primarily due to higher contracted prices for tons sold from our Hopedale complex compared to the prior year.

Cost of operations increased by $1.4 million, or 28.5%, to $6.3 million for the three months ended September 30, 2018 from $4.9 million for the three months ended September 30, 2017. Our cost of operations per ton was $53.33 for the three months ended September 30, 2018, an increase of $6.60, or 14.1%, compared to $46.73 for the three months ended September 30, 2017. The increase in total cost of operations was primarily the result of an increase in maintenance costs and costs for outside services. The cost of operations per ton increased in Northern Appalachia as poor rail service led to fewer tons produced and sold from this region resulting in fixed costs being allocated to fewer tons during the three months ended September 30, 2018.

Net loss in our Northern Appalachia segment was $0.8 million for the three months ended September 30, 2018 compared to net loss of $0.5 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 the increase in the cost of operations partially offset by the increase in contracted prices of tons sold compared to the same period in 2017.

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	%

*	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 by approximately 20.9% for the three months ended September 30, 2018 compared to the same period in 2017 primarily due to an increase in demand for coal from this region.

Coal revenues increased by approximately $1.2 million, or 12.9%, to approximately $10.3 million for the three months ended September 30, 2018 from approximately $9.1 million for the three months ended September 30, 2018 primarily due to an increase in demand for tons sold from the Castle Valley mine compared to the three months ended September 30, 2017. Coal revenues per ton for our Rhino Western segment decreased by $2.47 or 6.6% to $35.06 per ton for the three months ended September 30, 2018 as compared to $37.53 per ton for the three months ended September 30, 2017 due to lower contracted prices.

Cost of operations increased by $2.6 million, or 37.9%, to $9.2 million for the three months ended September 30, 2018 from $6.6 million for the three months ended September 30, 2017. Our cost of operations per ton was $31.35 for the three months ended September 30, 2018, an increase of $3.87, or 14.1%, compared to $27.48 for the three months ended September 30, 2017. Total cost of operations and cost of operations per ton increased for the three months ended September 30, 2018 compared to the same period in 2017 as we began to transition our coal mining operation at Castle Valley to an adjacent coal seam at this 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 million for the three months ended September 30, 2017. This decrease in net income was primarily the result of higher operating costs at our Castle Valley operation.

Illinois Basin	Three months ended			Three months ended		Increase/(Decrease)
	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	%

*	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 1.2% for the three months ended September 30, 2018 compared to the three months ended September 30, 2017.

Coal revenues of approximately $12.5 million for the three months ended September 30, 2018 decreased by approximately $2.4 million, or 16.3%, compared to $14.9 million for the three months ended September 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. The decrease in coal revenues and coal revenues per ton were primarily due to lower contracted prices for tons sold from our Pennyrile mine in western Kentucky.

Cost of operations was $13.7 million while cost of operations per ton was $43.00 for the three months ended September 30, 2018, both of which related to our Pennyrile mining complex in western Kentucky. For the three months ended September 30, 2017, cost of operations in our Illinois Basin segment was $13.1 million and cost of operations per ton was $41.40. The increase in cost of operations and cost of operations per ton for the three months ended September 30, 2018 was primarily the result of adverse geological conditions encountered at our Pennyrile mining complex during the three months ended September 30, 2018.

For our Illinois Basin segment, we generated a net loss of $3.2 million for the three months ended September 30, 2018 compared to net income of $0.1 million for the three months ended September 30, 2017. The net loss was primarily the result of a decrease in the contract price for tons sold during the third quarter of 2018 compared to the same period in 2017.

Other	Three months ended			Three 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	$	-		$	-		$	-			n/a
Total revenues		-			-			-			n/a
Coal revenues per ton**		n/a			n/a			n/a			n/a
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		(0.3	)		(0.7	)		0.4			(59.1	%)
Freight and handling costs		-			-			-			n/a
Depreciation, depletion and amortization		0.1			-			0.1			8.9	%
Selling, general and administrative costs		2.3			2.6			(0.3	)		(7.9	%)
Cost of operations per ton**		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

*	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 million for the nine months ended September 30, 2018 as compared to net loss of $9.5 million for the nine months ended September 30, 2017. The decrease in net loss for the nine months ended September 30, 2018 was primarily due to 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.

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 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
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

*	Totals may not foot due to rounding.

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

	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

† EBITDA is 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 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 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 and 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.

Cash Flows

Net cash provided by operating activities was $7.5 million for the nine months ended September 30, 2018 as compared to $13.2 million for the nine months ended September 30, 2017. This decrease in cash provided by operating activities was primarily the result of lower net income as discussed above.

Net cash used in investing activities was $3.8 million for the nine months ended September 30, 2018 as compared to net cash used in investing activities of $12.9 million for the nine months ended September 30, 2017. The decrease in cash used in investing activities was primarily due to the proceeds received from the sale of Mammoth Inc. shares partially offset by an increase in capital expenditures for the nine months ended September 30, 2018.

Net cash used in financing activities was $19.3 million for the nine months ended September 30, 2018, which was primarily attributable to repayments on our Financing Agreement and 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 months ended September 30, 2018 were approximately $11.2 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the nine months ended September 30, 2018 were approximately $9.3 million, which were primarily related to the purchase of additional equipment to expand production at one of our Central Appalachia mines.

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 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.

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 2018, we paid $6.0 million in distributions earned for the year ended December 31, 2017 to holders of the Series A preferred units. We have accrued approximately $1.8 million for distributions to holders of the Series A preferred units for the nine months ended September 30, 2018.

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 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.

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.

At September 30, 2018, we had $29.8 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”). 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, 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. We then have historically used bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank letters of credit as a percentage of our aggregate bond liability. We recently terminated our letter of credit facility and have provided cash collateral as a percentage of our aggregate bond liability to secure our surety bonding obligations. 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 discussed above, we had no letters of credit outstanding as of September 30, 2018.

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. 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 30, 2018.

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 30, 2018 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 30, 2018 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.

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, which risks could materially affect our business, financial condition or future results. There has been no material change in our risk factors from those described in the Annual Report on Form 10-K for the year ended December 31, 2017. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

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

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 30, 2018 is included in 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		Consent to Financing Agreement dated as 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 Agent

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

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

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

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