UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

OR

oTRANSITION 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	(IRS Employer
incorporation or organization)	Identification No.)
424 Lewis Hargett Circle, Suite 250 Lexington, KY (Address of principal executive offices)	40503 (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  o  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   o  No

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

Large accelerated filer   o	Accelerated filer                    x
Non-accelerated filer     o (Do not check if a smaller reporting company)	Smaller reporting company   o

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

As of May 2, 2014, 16,681,133 common units and 12,397,000 subordinated units were outstanding.

TABLE OF CONTENTS

Cautionary Note Regarding Forward-Looking Statements	1
Part I.—Financial Information (Unaudited)	2
ITEM 1. FINANCIAL STATEMENTS	2
Condensed Consolidated Statements of Financial Position as of March 31, 2014 and December 31, 2013	2
Condensed Consolidated Statements of Operations and Comprehensive Income for the Three Months Ended March 31, 2014 and 2013	3
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	4
Notes to Condensed Consolidated Financial Statements	5
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.    Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.    Controls and Procedures	49
PART II—Other Information	50
Item 1.    Legal Proceedings	50
Item 1A. Risk Factors	50
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 3.    Defaults upon Senior Securities	50
Item 4.    Mine Safety Disclosure	50
Item 5.    Other Information	50
Item 6.    Exhibits	51
SIGNATURES	53

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 plans for growth of the business, future capital expenditures, competitive strengths, goals, 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 past 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 forecast in these statements.

Any differences could be caused by a number of factors, including, but not limited to: changes in governmental regulation of the mining industry or the electric utility industry; adverse weather conditions and natural disasters; weakness in global economic conditions; decreases in demand for electricity and changes in demand for coal; poor mining conditions resulting from geological conditions or the effects of prior mining; equipment problems at mining locations; the availability of transportation for coal shipments; the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives; the availability and prices of competing electricity generation fuels; our ability to secure or acquire high-quality coal reserves; our ability to successfully diversify our operations into other non-coal natural resources; and our ability to find buyers for coal under favorable supply contracts. Other factors that could cause our actual results to differ from our projected results are described in (1) Part II, “Item 1A. Risk Factors” and elsewhere in this Form 10-Q, (2) our Annual Report on Form 10-K for the year ended December 31, 2013, (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 than 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, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

PART I.—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands)

	March 31,			December 31,
	2014			2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,097		$	423
Accounts receivable, net of allowance for doubtful accounts ($0 as of March 31, 2014 and December 31, 2013)	24,034			25,461
Inventories	16,822			18,580
Advance royalties, current portion	55			179
Prepaid expenses and other	3,668			4,572
Current assets held for sale	—			454
Total current assets	45,676			49,669
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	690,998			674,708
Less accumulated depreciation, depletion and amortization	(257,144		)	(249,718		)
Net property, plant and equipment	433,854			424,990
Advance royalties, net of current portion	5,951			5,580
Investment in unconsolidated affiliates	21,594			21,243
Intangible assets	1,127			1,148
Other non-current assets	7,646			9,640
Non-current assets held for sale	—			55,497
TOTAL	$	515,848		$	567,767
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	18,304		$	17,710
Accrued expenses and other	17,802			20,567
Current portion of long-term debt	821			1,024
Current portion of asset retirement obligations	2,220			1,614
Current portion of postretirement benefits	334			334
Current liabilities held for sale	—			5,241
Total current liabilities	39,481			46,490
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion	7,162			170,022
Asset retirement obligations, net of current portion	32,493			32,837
Other non-current liabilities	16,605			16,220
Postretirement benefits, net of current portion	5,853			5,786
Non-current liabilities held for sale	—			41
Total non-current liabilities	62,113			224,906
Total liabilities	101,594			271,396
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners	399,064			283,339
General partner	13,051			10,801
Accumulated other comprehensive income	2,139			2,231
Total partners’ capital	414,254			296,371
TOTAL	$	515,848		$	567,767

See notes to unaudited condensed consolidated financial statements.

2

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands, except per unit data)

	Three Months
	Ended March 31,
	2014			2013
REVENUES:
Coal sales	$	51,235		$	67,414
Freight and handling revenues	338			622
Other revenues	8,369			6,431
Total revenues	59,942			74,467
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	46,399			54,772
Freight and handling costs	301			235
Depreciation, depletion and amortization	9,232			10,092
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	5,557			5,488
(Gain)/loss on sale/disposal of assets—net	(679		)	925
Total costs and expenses	60,810			71,512
(LOSS)/INCOME FROM OPERATIONS	(868		)	2,955
INTEREST AND OTHER (EXPENSE)/INCOME:
Interest expense	(3,184		)	(1,854		)
Interest income and other	3			—
Equity in net (loss) of unconsolidated affiliates	(917		)	(1,372		)
Total interest and other (expense)	(4,098		)	(3,226		)
NET (LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS	(4,966		)	(271		)
INCOME TAXES	—			—
NET (LOSS) FROM CONTINUING OPERATIONS	(4,966		)	(271		)
DISCONTINUED OPERATIONS (NOTE 3)
Income from discontinued operations	130,511			94
NET INCOME/(LOSS)	125,545			(177		)
Other comprehensive income:
Amortization of actuarial gain under ASC Topic 715	(92		)	(36		)
COMPREHENSIVE INCOME/(LOSS)	$	125,453		$	(213	)
General partner’s interest in net (loss)/income:
Net (loss) from continuing operations	$	(99	)	$	(6	)
Net income from discontinued operations	2,610			2
General partner’s interest in net income/(loss)	$	2,511		$	(4	)
Common unitholders’ interest in net (loss)/income:
Net (loss) from continuing operations	$	(2,795	)	$	(152	)
Net income from discontinued operations	73,343			51
Common unitholders’ interest in net income/(loss)	$	70,548		$	(101	)
Subordinated unitholders’ interest in net (loss)/income:
Net (loss) from continuing operations	$	(2,072	)	$	(113	)
Net income from discontinued operations	54,558			41
Subordinated unitholders’ interest in net income/(loss)	$	52,486		$	(72	)
Net (loss)/income per limited partner unit, basic:
Common units:
Net (loss) per unit from continuing operations	$	(0.17	)	$	(0.01	)
Net income per unit from discontinued operations	4.40			—
Net income/(loss) per common unit, basic	$	4.23		$	(0.01	)
Subordinated units
Net (loss) per unit from continuing operations	$	(0.17	)	$	(0.01	)
Net income per unit from discontinued operations	4.40			—
Net income/(loss) per subordinated unit, basic	$	4.23		$	(0.01	)
Net (loss)/income per limited partner unit, diluted:
Common units
Net (loss) per unit from continuing operations	$	(0.17	)	$	(0.01	)
Net income per unit from discontinued operations	4.40			—
Net income/(loss) per common unit, diluted	$	4.23		$	(0.01	)
Subordinated units
Net (loss) per unit from continuing operations	$	(0.17	)	$	(0.01	)
Net income per unit from discontinued operations	4.40			—
Net income/(loss) per subordinated unit, diluted	$	4.23		$	(0.01	)
Distributions paid per limited partner unit (1)	$	0.445		$	0.445
Weighted average number of limited partner units outstanding, basic:
Common units	16,667			15,354
Subordinated units	12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units	16,673			15,354
Subordinated units	12,397			12,397

(1) No distributions were paid on the subordinated units for the three months ended March 31, 2014 and 2013.

See notes to unaudited condensed consolidated financial statements.

3

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	125,545		$	(177	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	9,232			10,212
Accretion on asset retirement obligations	589			589
Accretion on interest-free debt	—			57
Amortization of deferred revenue	(327		)	(302		)
Amortization of advance royalties	35			25
Amortization of debt issuance costs	1,410			269
Amortization of actuarial gain	(92		)	(36		)
Equity in net loss/(income) of unconsolidated affiliates	917			1,372
Loss on retirement of advance royalties	—			10
(Gain)/loss on sale/disposal of assets—net	(130,778		)	925
Equity-based compensation	89			283
Changes in assets and liabilities:
Accounts receivable	719			(2,734		)
Inventories	1,758			3,706
Advance royalties	(282		)	(393		)
Prepaid expenses and other assets	1,593			347
Accounts payable	2,487			(947		)
Accrued expenses and other liabilities	(783		)	(2,361		)
Asset retirement obligations	(326		)	(341		)
Postretirement benefits	67			99
Net cash provided by operating activities	11,853			10,603
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(28,065		)	(6,089		)
Proceeds from sales of property, plant, and equipment	189,088			523
Investment in unconsolidated affiliates	(1,269		)	(677		)
Net cash provided by/(used in) investing activities	159,754			(6,243		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	50,900			39,700
Repayments on line of credit	(213,710		)	(35,470		)
Repayments on long-term debt	(254		)	(1,229		)
Distributions to unitholders	(7,722		)	(7,097		)
General partner’s contributions	3			2
Net settlement of employee withholding taxes on unit awards vested	(44		)	(25		)
Payments on debt issuance costs	(104		)	—
Payment of offering costs	(2		)	—
Net cash used in financing activities	(170,933		)	(4,119		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	674			241
CASH AND CASH EQUIVALENTS—Beginning of period	423			461
CASH AND CASH EQUIVALENTS—End of period	$	1,097		$	702

See notes to unaudited condensed consolidated financial statements.

4

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2014 AND DECEMBER 31, 2013 AND FOR THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013

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.

Unaudited Interim Financial Information—The accompanying unaudited interim financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. The condensed consolidated statement of financial position as of March 31, 2014, condensed consolidated statements of operations and comprehensive income for the three months ended March 31, 2014 and 2013 and the condensed consolidated statements of cash flows for the three months ended March 31, 2014 and 2013 include all adjustments (consisting of normal recurring adjustments) which 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, 2013 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, 2013 with the Securities and Exchange Commission (“SEC”), which included all information and notes necessary for such presentation. The results of operations for the interim period 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, 2013 filed with the SEC.

Organization—Rhino Resource Partners LP is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor” or the “Operating Company”). Rhino Resource Partners LP had no operations during the period from April 19, 2010 (date of inception) to October 5, 2010 (the consummation of the initial public offering (“IPO”) of the Partnership). 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 domestic utilities and other coal-related organizations in the United States. In addition to operating coal properties, the Operating Company manages and leases coal properties and collects royalties from such management and leasing activities. The Operating Company was formed in April 2003 and has been built primarily via acquisitions.

In addition to its coal operations, the Partnership has invested in oil and natural gas properties, mineral rights and other oil and gas infrastructure-related activities that generate revenues for the Partnership.

5

Follow-on Offering

On September 13, 2013, the Partnership completed a public offering of 1,265,000 common units, representing limited partner interests in the Partnership, at a price of $12.30 per common unit. Of the common units issued, 165,000 units were issued in connection with the exercise of the underwriter’s option to purchase additional units. Net proceeds from the offering were approximately $14.6 million, after deducting underwriting discounts and estimated offering expenses of approximately $1.0 million. The Partnership used the net proceeds from this offering, and a related capital contribution by Rhino GP LLC, the Partnership’s general partner (the “General Partner”), of approximately $0.3 million, to repay approximately $14.9 million of outstanding indebtedness under the Partnership’s credit facility.

Reclassifications—Certain prior year amounts have been reclassified from continuing operations to discontinued operations to conform to the current year presentation (see note 3).

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Investment in Joint Ventures.  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 investment 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 must continue 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.

In May 2008, the Operating Company entered into a joint venture, Rhino Eastern LLC (“Rhino Eastern”), with an affiliate of Patriot Coal Corporation (“Patriot”) to acquire the Eagle mining complex. To initially capitalize the joint venture, the Operating Company contributed approximately $16.1 million for a 51% ownership interest in the joint venture. The Partnership accounts for the investment in the joint venture and its results of operations under the equity method. The Partnership considers the operations of this entity to comprise a reporting segment (“Eastern Met”) and has provided additional detail related to this operation in Note 18, “Segment Information.” As of March 31, 2014 and December 31, 2013, the Partnership has recorded its Rhino Eastern equity method investment of $19.5 million and $19.4 million, respectively, as a long-term asset. During the three months ended March 31, 2014, the Partnership contributed additional capital based upon its ownership share to the Rhino Eastern joint venture in the amount of $1.0 million.

On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. Patriot successfully exited bankruptcy in December 2013 and normal operations have continued at the Rhino Eastern joint venture.

6

In March 2012, the Partnership made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf, with affiliates of Wexford Capital LP (“Wexford Capital”).  Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio.  The initial investment was the Partnership’s proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during 2013 or the three months ended March 31, 2014. The Partnership has included its Timber Wolf investment in its Other category for segment reporting purposes.

In December 2012, the Partnership made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States. The Partnership recorded its proportionate share of the operating losses for Muskie for the three months ended March 31, 2014 and 2013 of approximately $42,000 and $150,000, respectively. During the three months ended March 31, 2014, the Partnership contributed additional capital based upon its ownership share to the Muskie joint venture in the amount of $0.2 million. In addition, during 2013, the Partnership provided a loan based upon its ownership share to Muskie in the amount of $0.2 million that remained outstanding as of March 31, 2014. As of March 31, 2014 and December 31, 2013, the Partnership has recorded its Muskie equity method investment of $2.0 million and $1.8 million, respectively, as a long-term asset. The Partnership includes any operating activities of Muskie in its Oil and Natural Gas segment for segment reporting purposes.

3. DISCONTINUED OPERATIONS

Divestiture of Utica Shale Oil and Natural Gas Assets

The Partnership and an affiliate of Wexford Capital have participated with Gulfport Energy (“Gulfport”), a publicly traded company, to acquire interests in a portfolio of oil and gas leases in the Utica Shale. During the year ended December 31, 2011, the Partnership completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio, which consisted of a 10.8% interest in approximately 80,000 acres. During the third quarter of 2012, the Partnership completed an exchange of its initial 10.8% position for a pro rata interest in 125,000 acres under lease by Gulfport and an affiliate of Wexford Capital. The non-cash transaction was an exchange of the Partnership’s operating interest for the operating interest owned by another party in order to diversify the Partnership’s risk in its oil and gas investment. Thus, the Partnership determined that the non-cash exchange of the Partnership’s ownership interest in the Utica acreage did not result in any gain or loss. Also during the third quarter of 2012, the Partnership’s position was adjusted to a 5% net interest in the 125,000 acres, or approximately 6,250 net acres. As of December 31, 2013, the Partnership had invested approximately $31.1 million for its pro rata interest in the Utica Shale portfolio of oil and gas leases, which consisted of a 5% interest in a total of approximately 152,300 gross acres, or approximately 7,615 net acres. In addition, per the joint operating agreement among the Partnership, Gulfport and an affiliate of Wexford Capital, the Partnership had funded its proportionate share of drilling costs to Gulfport for wells being drilled on the Partnership’s acreage. As of December 31, 2013, the Partnership had funded approximately $23.3 million of drilling costs. The Partnership’s investment in the Utica Shale oil and gas leases as well as the

7

proportionate amount of funded drilling costs are recorded in Non-current assets held for sale in the unaudited condensed consolidated statements of financial position as of December 31, 2013. For the three months ended March 31, 2013, the Partnership recorded revenue from its Utica Shale investment of approximately $0.3 million and recognized approximately $0.1 million in pre-tax profit that is recorded in Income from discontinued operations in the unaudited condensed consolidated statements of operations and comprehensive income.

In March 2014, the Partnership completed a purchase and sale agreement (the “Purchase Agreement”) with Gulfport to sell the Partnership’s oil and gas properties in the Utica Shale region for approximately $184.0 million (the “Purchase Price”). The Purchase Agreement was effective as of January 1, 2014 and the Purchase Price was adjusted for any unsettled expenditures made and/or proceeds received from the Partnership’s portion of its Utica Shale properties prior to the effective date. At the closing of the Purchase Agreement, the Partnership was immediately due approximately $179.0 million, net of any adjustments described above, and the remaining approximately $5.0 million is scheduled to be paid within approximately 90 days of March 20, 2014, subject to ongoing legal title work related to specific properties. The remaining $5.0 million to be paid per the Purchase agreement was not recognized in the financial statements of the Partnership at March 31, 2014 since this consideration is contingent upon legal title work related to specific properties included in the transaction. The Partnership recorded a gain of approximately $121.7 million during the three months ended March 31, 2014 related to this sale, which is recorded in Income from discontinued operations in the unaudited condensed consolidated statements of operations and comprehensive income. The gain from the Utica Shale transaction is included in the (Gain)/loss on sale/disposal of assets—net line in the operating activities section of the Partnership’s unaudited condensed consolidated statements of cash flows. The proceeds from the Utica Shale transaction are included in the Proceeds from sales of property, plant, and equipment line in the investing activities section of the Partnership’s unaudited condensed consolidated statements of cash flows.

Other Oil and Natural Gas Activities

In January 2014, the Partnership received approximately $8.4 million of net proceeds from the sale by Blackhawk Midstream LLC (“Blackhawk”) of its equity interest in two entities, Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, to Summit Midstream Partners, LLC. As part of the joint operating agreement for the Utica Shale investment discussed above, the Partnership had the right to approximately 5% of the proceeds of the sale by Blackhawk. The Partnership recorded this $8.4 million in Income from discontinued operations in the unaudited condensed consolidated statements of operations and comprehensive income. The gain from the Blackhawk transaction is included in the (Gain)/loss on sale/disposal of assets—net line in the operating activities section of the Partnership’s unaudited condensed consolidated statements of cash flows. The proceeds from the Blackhawk transaction are included in the Proceeds from sales of property, plant, and equipment line in the investing activities section of the Partnership’s unaudited condensed consolidated statements of cash flows.

8

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31,		December 31,
	2014		2013
	(in thousands)
Other prepaid expenses	$	819	$	951
Prepaid insurance	1,005		1,958
Prepaid leases	95		122
Supply inventory	1,429		1,221
Deposits	320		320
Total Prepaid expenses and other	$	3,668	$	4,572

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of March 31, 2014 and December 31, 2013 are summarized by major classification as follows:

	Useful Lives	March 31, 2014			December 31, 2013
		(in thousands)
Land and land improvements		$	35,038		$	35,078
Mining and other equipment and related facilities	2 - 20 Years	300,796			302,114
Mine development costs	1 - 15 Years	76,709			73,344
Coal properties	1 - 15 Years	238,213			238,975
Oil and natural gas properties		8,093			8,093
Construction work in process		32,149			17,104
Total		690,998			674,708
Less accumulated depreciation, depletion and amortization		(257,144		)	(249,718		)
Net		$	433,854		$	424,990

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Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties and oil and gas properties, amortization expense for mine development costs, amortization expense for intangible assets and amortization expense for asset retirement costs for the three months ended March 31, 2014 and 2013 were as follows:

	Three Months Ended March 31,
	2014		2013
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	7,532	$	8,120
Depletion expense for coal properties and oil and natural gas properties	1,194		1,275
Amortization expense for mine development costs	424		671
Amortization expense for intangible assets	21		21
Amortization expense for asset retirement costs	61		5
Total depreciation, depletion and amortization	$	9,232	$	10,092

Long-Lived Asset Impairment

During the fourth quarter of 2013, the Partnership’s management made a strategic decision to permanently close the mining operations at its McClane Canyon complex in Colorado. Since the McClane Canyon complex had been idled at the end of 2010, the Partnership had been actively marketing the coal from this complex to potential buyers, but had not been able to obtain suitable sales contracts. Due to the unfavorable long-term prospects for the coal market in the Colorado area and to avoid the ongoing costs that were being incurred to temporarily idle this complex, the Partnership’s management made the decision to permanently close this operation at the end of 2013. While a portion of the equipment from this operation was relocated to other operating locations, the Partnership incurred an impairment charge of approximately $1.7 million during 2013 related to specific property, plant and equipment.

Acquisition of Coal Properties

In May 2012, the Partnership completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for approximately $1.5 million. In addition, the Partnership was subsequently required to pay an additional $2.0 million related to this acquisition after certain conditions were met, of which $1.6 million was paid in the third quarter of 2012 and the remaining $0.4 million was paid in the fourth quarter of 2013. The $2.0 million in total payments was recorded in Property, plant and equipment. An additional $1.0 million in potential payments has not yet been recorded because the conditions requiring payment of this amount have not occurred.

As of December 31, 2013, the coal leases and property were estimated to contain approximately 32.6 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is fully permitted and provides the Partnership with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers. The Partnership has commenced the construction of a new underground mining operation on this property with production targeted to begin in late May or early June 2014.

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6. GOODWILL AND INTANGIBLE ASSETS

Accounting Standards Codification (“ASC”) Topic 350 addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under the provisions of ASC Topic 350, goodwill and other intangible assets with indefinite useful lives are no longer amortized but instead tested for impairment at least annually.

Intangible assets as of March 31, 2014 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	218	$	510
Developed Technology	78		23		55
Trade Name	184		26		158
Customer List	470		66		404
Total	$	1,460	$	333	$	1,127

Intangible assets as of December 31, 2013 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	207	$	521
Developed Technology	78		22		56
Trade Name	184		23		161
Customer List	470		60		410
Total	$	1,460	$	312	$	1,148

The Partnership considers the patent and developed technology intangible assets to have a useful life of 17 years and the trade name and customer list intangible assets to have a useful life of 20 years. All of the intangible assets are amortized over their useful life on a straight line basis.

Amortization expense for the three months ended March 31, 2014 and 2013 is included in the depreciation, depletion and amortization table included in Note 5. The future total amortization expense for each of the five succeeding years related to intangible assets that are currently recorded in the unaudited condensed consolidated statement of financial position is estimated to be as follows at March 31, 2014:

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			Developed				Customer
	Patent		Technology		Trade Name		List		Total
	(in thousands)
2014 (from Apr 1 to Dec 31)	$	32	$	3	$	7	$	18	$	60
2015	43		5		9		23		80
2016	43		5		9		23		80
2017	43		5		9		23		80
2018	43		5		9		23		80

7. OTHER NON-CURRENT ASSETS

Other non-current assets as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31,		December 31,
	2014		2013
	(in thousands)
Deposits and other	$	543	$	1,223
Debt issuance costs—net	2,229		3,535
Non-current receivable	4,327		4,327
Note receivable	206		206
Deferred expenses	341		349
Total	$	7,646	$	9,640

Debt issuance costs were approximately $9.1 million and $9.0 million as of March 31, 2014 and December 31, 2013, respectively. Accumulated amortization of debt issuance costs were approximately $6.9 million and approximately $5.5 million as of March 31, 2014 and December 31, 2013, respectively. In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility that reduced the borrowing capacity to $200 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, which was recorded as an addition to Debt issuance costs. In addition, the Partnership wrote-off approximately $1.1 million of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility. See Note 9 for further information on the amendment to the amended and restated senior secured credit facility.

The non-current receivable balance of $4.3 million as of March 31, 2014 and December 31, 2013 consisted of the amount due from the Partnership’s workers’ compensation insurance providers for potential claims that are the primary responsibility of the Partnership, but are covered under the Partnership’s insurance policies. The $4.3 million is also included in the Partnership’s accrued workers’ compensation benefits liability balance, which is included in the 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. This presentation has no impact on the Partnership’s results of operations or cash flows.

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8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31,		December 31,
	2014		2013
	(in thousands)
Payroll, bonus and vacation expense	$	3,024	$	3,573
Non income taxes	4,285		2,750
Royalty expenses	1,920		2,001
Accrued interest	383		760
Health claims	856		1,036
Workers’ compensation & pneumoconiosis	1,190		1,190
Deferred revenues	3,793		3,592
Accrued insured litigation claims	1,418		2,579
Other	933		3,086
Total	$	17,802	$	20,567

The $1.4 million and $2.6 million accrued for insured litigation claims as of March 31, 2014 and December 31, 2013, respectively, consists of probable and estimable litigation claims that are the primary obligation of the Partnership. The amount accrued for litigation claims decreased due to the settlement of various litigation claims during the three months ended March 31, 2014. The amount accrued for litigation claims is also due from the Partnership’s insurance providers and is included in Accounts receivable, net of allowance for doubtful accounts on the Partnership’s unaudited condensed consolidated statements of financial position. The Partnership presents this amount on a gross asset and liability basis as a right of setoff does not exist per the accounting guidance in ASC Topic 210. This presentation has no impact on the Partnership’s results of operations or cash flows.

9. DEBT

Debt as of March 31, 2014 and December 31, 2013 consisted of the following:

	March 31,			December 31,
	2014			2013
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$	4,230		$	167,040
Note payable to H&L Construction Co., Inc.	603			800
Other notes payable	3,150			3,206
Total	7,983			171,046
Less current portion	(821		)	(1,024		)
Long-term debt	$	7,162		$	170,022

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Senior Secured Credit Facility with PNC Bank, N.A.—On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility was $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million was available for letters of credit. As described below, in March 2014 the amended and restated credit facility was amended and the borrowing capacity under the facility was reduced to $200 million, with the amount available for letters of credit unchanged. Borrowings under the facility bear interest, which varies depending upon the levels of certain financial ratios. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability that also varies depending upon the levels of certain financial ratios. Borrowings on the amended and restated senior secured credit facility are collateralized by all of the unsecured assets of the Partnership. The amended and restated senior secured credit facility requires the Partnership to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Partnership was in compliance with all covenants contained in the amended and restated senior secured credit facility as of and for the period ended March 31, 2014. The amended and restated senior secured credit facility expires in July 2016.

In April 2013, the Partnership entered into an amendment of its amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The amendment provided for an increase in the maximum allowed investments in coal-related entities outside of the Partnership (i.e. joint ventures) under the amended and restated senior secured credit facility from $25 million to $40 million. The amendment also altered the maximum leverage ratio allowed under the amended and restated senior secured credit facility and also altered the pricing grid to include applicable interest rates for borrowings, letter of credit fees and commitment fees on unused borrowings based upon the new maximum leverage ratio. The amendment increased the maximum leverage ratio of the amended and restated senior secured credit facility to 3.75 from April 1, 2013 through March 31, 2015, then stepped the maximum leverage ratio down to its previous level of 3.0 after December 31, 2015. All other terms of the amended and restated senior secured credit facility were not affected by the amendment. As part of executing the amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $1.0 million to the lenders in April 2013, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position.

In March 2014, the Partnership entered into a second amendment of its amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. This second amendment permitted the Partnership to sell certain assets to Gulfport, as described in Note 3, which previously constituted a portion of the collateral under the amended and restated senior secured credit facility. This second amendment also reduces the borrowing capacity under the amended and restated senior secured credit facility to a maximum of $200 million and alters the maximum leverage ratio to 3.5 from January 1, 2014 through September 30, 2015. The maximum leverage ratio decreases to 3.25 from October

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1, 2015 through December 31, 2015 and then decreases to 3.0 after December 31, 2015. In addition, the second amendment adjusts the maximum investments (other than by the Partnership) in hydrocarbons, hydrocarbon interests and assets and activities related to hydrocarbons, in each case, excluding coal, in an aggregate amount not to exceed $50 million. As part of executing the second amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.1 million to the lenders in March 2014, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position. In addition, the Partnership recorded a non-cash charge of approximately $1.1 million to write-off a portion of its unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility.

As discussed in Note 3, the Partnership sold its Utica Shale oil and natural gas assets in March 2014 for approximately $184.0 million. The Partnership used the initial proceeds from this sale of approximately $179.0 million to reduce the outstanding debt on its amended and restated senior secured credit facility. At March 31, 2014, the Operating Company had borrowed $4.2 million at a variable interest rate of LIBOR plus 3.00% (3.16% at March 31, 2014). In addition, the Operating Company had outstanding letters of credit of approximately $20.3 million at a fixed interest rate of 3.00% at March 31, 2014. Based upon a maximum borrowing capacity of 3.5 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $171.8 million of the borrowing availability at March 31, 2014.

Note payable to H&L Construction Co., Inc.— The note payable to H&L Construction Co., Inc. was originally a non-interest bearing note and the Partnership has recorded a discount for imputed interest at a rate of 5.0% on this note that is being amortized over the life of the note using the effective interest method. The note payable matures in January 2015. The note is secured by mineral rights purchased by the Partnership from H&L Construction Co., Inc. with a carrying amount of approximately $11.0 million and approximately $11.1 million at March 31, 2014 and December 31, 2013, respectively.

10. ASSET RETIREMENT OBLIGATIONS

The changes in asset retirement obligations for the three months ended March 31, 2014 and the year ended December 31, 2013 are as follows:

	March 31, 2014			December 31, 2013
	(in thousands)
Balance at beginning of period (including current portion)	$	34,451		$	32,962
Accretion expense	589			2,356
Adjustment resulting from disposal of property	—			—
Adjustments to the liability from annual recosting and other	—			61
Liabilities settled	(327		)	(928		)
Balance at end of period	34,713			34,451
Less current portion of asset retirement obligation	(2,220		)	(1,614		)
Long-term portion of asset retirement obligation	$	32,493		$	32,837

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11. EMPLOYEE BENEFITS

In conjunction with the acquisition of the coal operations of American Electric Power on April 16, 2004, the Operating Company acquired a postretirement benefit plan providing healthcare to eligible employees at its Hopedale operations. The Partnership has no other postretirement plans.

Net periodic benefit cost for the three months ended March 31, 2014 and 2013 are as follows:

	Three months ended March 31,
	2014			2013
	(in thousands)
Service costs	$	74		$	96
Interest cost	59			46
Amortization of (gain)	(92		)	(36		)
Total	$	41		$	106

For the three months ended March 31, 2014 and 2013, net periodic benefit costs, including the amortization of actuarial gain included in the table above, are included in Cost of operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

401(k) Plans—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Operating Company’s discretion. The expense under these plans for the three months ended March 31, 2014 and 2013 is included in Cost of operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income and was as follows:

	Three months ended March 31,
	2014		2013
	(in thousands)
401(k) plan expense	$	568	$	580

12. EQUITY-BASED COMPENSATION

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

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As of March 31, 2014, the General Partner had granted phantom units to certain employees and restricted units and unit awards to its directors. These grants consisted of annual restricted unit awards to directors and phantom unit awards with tandem distribution equivalent rights (“DERs”) granted in the first quarters of 2012, 2013 and 2014 to certain employees in connection with the prior year’s performance. The DERs consist of rights to accrue quarterly cash distributions in an amount equal to the cash distribution the Partnership makes to unitholders during the vesting period. These awards are subject to service based vesting conditions and any accrued distributions will be forfeited if the related awards fail to vest according to the relevant service based vesting conditions.

A total of 29,657 phantom units were granted in the first quarter of 2014 and these awards vest in equal annual installments over a three year period from the date of grant. The remaining terms and conditions of these phantom unit awards are equivalent to the terms described above. The total fair value of the awards granted in the first quarter of 2014 was approximately $0.4 million at the grant date and the fair value of these awards was approximately $0.4 million as of March 31, 2014. The expense related to these awards will be recognized ratably over the three year vesting period, plus any mark-to-market adjustments, and the amount of expense recognized in the three months ended March 31, 2014 related to these awards was immaterial.

The Partnership accounts for its unit-based awards as liabilities with applicable mark-to-market adjustments at each reporting period because the Compensation Committee of the board of directors of the General Partner has historically elected to pay some of the awards in cash in lieu of issuing common units.

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of March 31, 2014, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

Year	Tons (in thousands)	Number of customers
2014 Q2-Q4	2,368	20
2015	1,796	4
2016	1,100	2
2017	1,100	2

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

Purchase Commitments—As of March 31, 2014, the Partnership had approximately 0.4 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2014 for approximately $1.4 million.

In addition, as of March 31, 2014, the Partnership had a commitment to purchase 1,800 tons of ammonia nitrate at fixed prices through December 2014 for approximately $0.8 million.

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Purchased Coal Expenses—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts. Purchased coal expense from coal purchase contracts for the three months ended March 31, 2014 and 2013 are included in Cost of operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income and were as follows:

	Three months ended March 31,
	2014		2013
	(in thousands)
Purchased coal expense	$	1,850	$	972

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 months ended March 31, 2014 and 2013 are included in Cost of operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income and was as follows:

	Three months ended March 31,
	2014		2013
	(in thousands)
Lease expense	$	799	$	867
Royalty expense	$	2,760	$	2,908

Joint Ventures—Pursuant to the Rhino Eastern joint venture agreement with Patriot, the Partnership is required to contribute additional capital to assist in funding the development and operations of the Rhino Eastern joint venture. During the three months ended March 31, 2014, the Partnership made capital contributions of approximately $1.0 million to the Rhino Eastern joint venture. The Partnership may be required to contribute additional capital to the Rhino Eastern joint venture in subsequent periods.

The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012.  The Partnership made an initial capital contribution of approximately $0.1 million during the year ended December 31, 2012 based upon its proportionate ownership interest.

The Partnership may contribute additional capital to the Muskie Proppant joint venture that was formed in the fourth quarter of 2012. The Partnership made an initial capital contribution of approximately $2.0 million during the fourth quarter of 2012 and an additional capital contribution of approximately $0.5 million during the year ended December 31, 2013, each based upon its proportionate ownership interest. During the three months ended March 31, 2014, the Partnership made capital contributions based upon its proportionate ownership interest of approximately $0.2 million to the Muskie Proppant joint venture. In addition, during the year ended December 31, 2013, the Partnership provided a loan based upon its ownership share to Muskie in the amount of $0.2 million that remained outstanding as of March 31, 2014.

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14. EARNINGS PER UNIT (“EPU”)

The following tables present a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended March 31, 2014 and 2013:

Three months ended March 31, 2014	General Partner			Common Unitholders			Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net (loss) from continuing operations	$	(99	)	$	(2,795	)	$	(2,072	)
Net income from discontinued operations	2,610			73,343			54,558
Total interest in net income	$	2,511		$	70,548		$	52,486
Denominator:
Weighted average units used to compute basic EPU	n/a			16,667			12,397
Effect of dilutive securities — LTIP awards:
Dilutive securities for net (loss) from continuing operations	n/a			—			—
Dilutive securities for net income from discontinued operations	n/a			6			—
Total dilutive securities	n/a			6			—
Weighted average units used to compute diluted EPU	n/a			16,673			12,397
Net (loss)/income per limited partner unit, basic
Net (loss) per unit from continuing operations	n/a			$	(0.17	)	$	(0.17	)
Net income per unit from discontinued operations	n/a			4.40			4.40
Net income per common unit, basic	n/a			$	4.23		$	4.23
Net (loss)/income per limited partner unit, diluted
Net (loss) per unit from continuing operations	n/a			$	(0.17	)	$	(0.17	)
Net income per unit from discontinued operations	n/a			4.40			4.40
Net income per common unit, diluted	n/a			$	4.23		$	4.23

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Three months ended March 31, 2013	General Partner			Common Unitholders			Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net (loss) from continuing operations	$	(6	)	$	(152	)	$	(113	)
Net income from discontinued operations	2			51			41
Total interest in net (loss)	$	(4	)	$	(101	)	$	(72	)
Denominator:
Weighted average units used to compute basic EPU	n/a			15,354			12,397
Effect of dilutive securities — LTIP awards:
Dilutive securities for net (loss) from continuing operations	n/a			—			—
Dilutive securities for net income from discontinued operations	n/a			—			—
Total dilutive securities	n/a			—			—
Weighted average units used to compute diluted EPU	n/a			15,354			12,397
Net (loss)/income per limited partner unit, basic
Net (loss) per unit from continuing operations	n/a			$	(0.01	)	$	(0.01	)
Net income per unit from discontinued operations	n/a			—			—
Net (loss) per common unit, basic	n/a			$	(0.01	)	$	(0.01	)
Net (loss)/income per limited partner unit, diluted
Net (loss) per unit from continuing operations	n/a			$	(0.01	)	$	(0.01	)
Net income per unit from discontinued operations	n/a			—			—
Net (loss) per common unit, diluted	n/a			$	(0.01	)	$	(0.01	)

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. For the three months ended March 31, 2014, approximately 6,000 LTIP granted phantom units were anti-dilutive. There were no anti-dilutive units for the three months ended March 31, 2013.

15. MAJOR CUSTOMERS

The Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues (Note: customers with “n/a” had revenue below the 10% threshold in any period where this is indicated):

	March 31		Three months		Three months
	2014		ended		ended
	Receivable		March 31		March 31
	Balance		2014 Sales		2013 Sales
	(in thousands)
NRG Energy, Inc. (fka GenOn Energy, Inc.)	$	1,040	$	6,820	$	12,431
Indiana Harbor Coke Company, L.P	n/a		n/a		7,981
American Electric Power Company, Inc.	n/a		n/a		9,598

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16. FAIR VALUE OF FINANCIAL INSTRUMENTS

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 senior secured credit facility was determined based upon a market approach and approximates the carrying value at March 31, 2014. The fair value of the Partnership’s senior secured credit facility is a Level 2 measurement.

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

The unaudited condensed consolidated statement of cash flows for the three months ended March 31, 2014 excludes approximately $3.0 million of property additions, which are recorded in accounts payable, and approximately $0.2 million related to the value of phantom and restricted units that were issued to certain employees and directors of the General Partner. The unaudited condensed consolidated statement of cash flows for the three months ended March 31, 2013 excludes approximately $2.7 million of property additions, which are recorded in accounts payable,  and approximately $0.1 million related to the value of phantom and restricted units that were issued to certain employees and directors of the general partner.

18. SEGMENT INFORMATION

The Partnership 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. The Partnership also leases coal reserves to third parties in exchange for royalty revenues. For the three months ended March 31, 2014, the Partnership had four reportable segments: Central Appalachia (comprised of both surface and underground mines located in Eastern Kentucky and Southern West Virginia, along with the Elk Horn coal leasing operations), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Rhino Western (comprised of an underground mine in Utah) and Eastern Met (comprised solely of the joint venture with Patriot).

Beginning with 2013 year-end reporting, the Partnership included a reportable business segment for its oil and natural gas activities since the total assets for these operations met the quantitative threshold for separate segment reporting. The Oil and Natural Gas segment included the Partnership’s Utica Shale activities, which were sold during the first quarter of 2014 as described in Note 3, as well as the Partnership’s Cana Woodford activities, the Razorback drill pad construction operations and the Muskie joint venture to provide sand for fracking operations. Prior to 2013, the Partnership’s oil and natural gas activities were included in its Other category for segment reporting purposes. Since the majority of the Partnership’s oil and natural gas activities were in the Utica Shale and the Utica Shale financial results are now included in discontinued operations due to their sale, the segment data for the Partnership’s remaining oil and natural gas activities has been included in the Other category for segment reporting purposes for 2014 and the 2013 comparable period since they are immaterial.

The Partnership’s Other category is comprised of the Partnership’s ancillary businesses and its remaining oil and natural gas activities. The Partnership has not provided disclosure of

21

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.

The Partnership accounts for the Rhino Eastern joint venture under the equity method. Under the equity method of accounting, the Partnership has only presented limited information (net income). The Partnership considers this operation to comprise a separate operating segment and has presented additional operating detail, with corresponding eliminations and adjustments, to reflect its percentage of ownership.

Reportable segment results of operations for the three months ended March 31, 2014 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

									Eastern Met
												Equity			Equity
	Central			Northern		Rhino			Complete			Method			Method						Total
	Appalachia			Appalachia		Western			Basis			Eliminations			Presentation			Other			Consolidated
	(in thousands)
Total revenues	$	30,561		$	18,764	$	9,586		$	7,529		$	(7,529	)	$	—		$	1,031		$	59,942
DD&A	5,402			1,878		1,418			500			(500		)	—			534			9,232
Interest expense	1,053			177		150			15			(15		)	—			1,804			3,184
Net Income (loss) from continuing operations	$	(3,818	)	$	1,104	$	(346	)	$	(1,717	)	$	841		$	(876	)	$	(1,030	)	$	(4,966	)

Reportable segment results of operations for the three months ended March 31, 2013 are as follows:

									Eastern Met
												Equity			Equity
	Central			Northern		Rhino			Complete			Method			Method						Total
	Appalachia			Appalachia		Western			Basis			Eliminations			Presentation			Other			Consolidated
	(in thousands)
Total revenues	$	41,942		$	21,867	$	9,597		$	6,168		$	(6,168	)	$	—		$	1,061		$	74,467
DD&A	6,266			2,052		1,350			475			(475		)	—			424			10,092
Interest expense	972			190		159			—			—			—			533			1,854
Net Income (loss) from continuing operations	$	(2,204	)	$	4,623	$	(103	)	$	(2,397	)	$	1,174		$	(1,223	)	$	(1,364	)	$	(271	)

Additional summarized financial information for the Rhino Eastern equity method investment for the periods ended March 31, 2014 and 2013:

	Three months ended March 31,
	2014			2013
	(in thousands)
Total costs and expenses	$	9,231		$	8,566
(Loss) from operations	(1,702		)	(2,398		)

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19.  SUBSEQUENT EVENTS

On April 21, 2014, the Partnership announced a cash distribution of $0.445 per common unit, or $1.78 per unit on an annualized basis. This distribution will be paid on May 15, 2014 to all common unit holders of record as of the close of business on May 1, 2014. No distributions will be paid on the subordinated units.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or similar terms refer to 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 the historical audited consolidated financial statements and accompanying notes of our Annual Report on Form 10-K for the year ended December 31, 2013 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2013 included in this 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. See 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, 2013.

Overview

We are a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition to operating coal properties, we manage and lease coal properties and collect royalties from those management and leasing activities. Our diversified energy portfolio also includes investments in oil and natural gas mineral rights in the Cana Woodford region of western Oklahoma. We receive royalty revenue from any hydrocarbons produced and sold by operators on our Cana Woodford acreage. In addition, we have expanded our business to include infrastructure support services, including the formation of Razorback, a service company to provide drill pad construction for operators in the Utica Shale, as well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in a joint venture that provides sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S.

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region and oil and natural gas investments in the Cana Woodford region in western Oklahoma. As of December 31, 2013, we controlled an estimated 457.7 million tons of proven and probable coal reserves, consisting of an estimated 438.0 million tons of steam coal and an estimated 19.7 million tons of metallurgical coal. In addition, as of December 31, 2013, we controlled an estimated 277.0

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million tons of non-reserve coal deposits. As of December 31, 2013, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 43.9 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 18.8 million tons of non-reserve coal deposits. As of March 31, 2014, we operated nine mines, including four underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. Our Rhino Eastern joint venture operates one underground mine in West Virginia. 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 oil and natural gas investments as of March 31, 2014 consisted of approximately 1,900 net mineral acres that we own in the Cana Woodford region.

Our principal business strategy is to safely, efficiently and profitably produce, sell and lease both steam and metallurgical coal from our diverse asset base in order to maintain and, over time, increase our quarterly cash distributions. In addition, we intend to continue to expand and diversify our operations through strategic acquisitions, including the acquisition of long-term, cash generating natural resource assets, such as our oil and natural gas investments in the Cana Woodford region. 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 months ended March 31, 2014, we generated revenues of approximately $59.9 million and net income of approximately $125.5 million, consisting primarily of the approximate $121.7 million gain from the sale of our Utica Shale oil and natural gas assets. Excluding results from the Rhino Eastern joint venture, for the three months ended March 31, 2014, we produced and sold approximately 0.8 million tons of coal, approximately 83% of which were sold pursuant to supply contracts. Additionally, the Rhino Eastern joint venture produced and sold approximately 0.1 million tons of premium mid-vol metallurgical coal for the three months ended March 31, 2014.

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Recent Developments

Utica Shale Oil and Natural Gas Investment Sale

We and an affiliate of Wexford participated with Gulfport Energy (“Gulfport”), a publicly traded company, to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. Our initial position in the Utica Shale consisted of a 10.8% net interest in approximately 80,000 gross acres. During the third quarter of 2012, we completed an exchange of our initial 10.8% position for a pro rata interest in 125,000 gross acres under lease by Gulfport and an affiliate of Wexford Capital. Also during the third quarter of 2012, our position was adjusted to a 5% net interest in the 125,000 gross acres, or approximately 6,250 net acres. As of December 31, 2013, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 152,300 gross acres, or approximately 7,615 net acres, for a total purchase price of approximately $31.1 million. In addition, per the joint operating agreement among Rhino, Gulfport and an affiliate of Wexford Capital, we funded our proportionate share of drilling costs to Gulfport for wells drilled on our acreage. As of December 31, 2013, we funded approximately $23.3 million of drilling costs. We received approximately $5.6 million of revenue from this investment for the year ended December 31, 2013.

In March 2014, we completed a purchase and sale agreement (the “Purchase Agreement”) with Gulfport to sell our oil and natural gas properties in the Utica Shale region for approximately $184.0 million (the “Purchase Price”). The Purchase Agreement was effective as of January 1, 2014 and the Purchase Price was adjusted for any unsettled expenditures made and/or proceeds received from our portion of the Utica Shale properties prior to the effective date. At the closing of the Purchase Agreement, we were immediately due approximately $179.0 million, net of any adjustments described above, and the remaining approximately $5.0 million is scheduled to be paid within approximately 90 days of March 20, 2014, subject to ongoing legal title work related to specific properties. We recorded a gain of approximately $121.7 million during the three months ended March 31, 2014 related to this sale. The sale of our investment in the Utica Shale allowed us to eliminate substantially all of our debt, which provides us with significant financial flexibility. The elimination of our debt provides us the capability to opportunistically expand our operations and increase our cash flow through the development of existing coal reserves or the potential acquisition of MLP qualifying assets.

Credit Facility

In March 2014, we entered into a second amendment of our amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. This second amendment permitted us to sell certain assets per an agreement with Gulfport, as described above in the sale of the Utica Shale investment, which previously constituted a portion of the collateral of the administrative agent and lenders under the amended and restated senior secured credit facility. This second amendment also reduces the borrowing capacity under the amended and restated senior secured credit facility to a maximum of $200 million and alters the maximum leverage ratio to 3.5 from January 1, 2014 through September 30, 2015. The maximum leverage ratio decreases to 3.25 from October 1, 2015 through December 31, 2015 and then decreases to 3.0 after December 31, 2015. In addition, the second amendment adjusts the maximum investments (other than directly by us) in

26

hydrocarbons, hydrocarbon interests and assets and activities related to hydrocarbons, in each case, excluding coal, in an aggregate amount not to exceed $50 million. All other terms of the amended and restated senior secured credit facility were not affected by the second amendment. Due to the second amendment, we recorded a non-cash charge of approximately $1.1 million to write-off a portion of our unamortized debt issuance costs since the second amendment reduced the borrowing capacity under the amended and restated senior secured credit facility.

Other Oil and Natural Gas Activities

In January 2014, we received approximately $8.4 million of net proceeds from the sale by Blackhawk Midstream LLC (“Blackhawk”) of its equity interest in two entities, Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, to Summit Midstream Partners, LLC. As part of the joint operating agreement for the Utica Shale investment discussed above, we had the right to approximately 5% of the proceeds of the sale by Blackhawk.

Follow-on Offering

In September 2013, we completed a public offering of 1,265,000 common units, representing limited partner interests in us, at a price of $12.30 per common unit. Of the common units issued, 165,000 units were issued in connection with the exercise of the underwriters’ option to purchase additional units. Net proceeds from the offering were approximately $14.6 million, after deducting underwriting discounts and estimated offering expenses of approximately $1.0 million. We used the net proceeds from this offering, and a related capital contribution by our general partner of approximately $0.3 million, to repay approximately $14.9 million of outstanding indebtedness under our credit facility.

Patriot Coal Corporation Bankruptcy

We have a 51% equity interest in the Rhino Eastern joint venture, with Patriot Coal Corporation (“Patriot”) owning the remaining membership interest. On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection and Patriot successfully exited bankruptcy in December 2013.

Acquisition of Coal Property

In May 2012, we completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for approximately $1.5 million. In addition, we were subsequently required to pay an additional $2.0 million related to this acquisition after certain conditions were met, of which $1.6 million was paid in the third quarter of 2012 and the remaining $0.4 million was paid in the fourth quarter of 2013. The $2.0 million in total payments was recorded in Property, plant and equipment. An additional $1.0 million in potential payments has not yet been recorded because the conditions requiring payment of this amount have not occurred.

As of December 31, 2013, the coal leases and property were estimated to contain approximately 32.6 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is fully permitted and provides the Partnership with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S.

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customers. We have commenced the construction of a new underground mining operation on this property with production targeted to begin in late May or early June 2014.

Other Investments

We have invested in certain oil and natural gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. Our investment includes approximately 1,900 net mineral acres that we own in the Cana Woodford region which provide monthly royalty revenue to Rhino.

In December 2012, we made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the U.S. We recorded our proportionate portion of the operating loss for the three months ended March 31, 2014 and 2013 of approximately $42,000 and approximately $150,000, respectively. During the three months ended March 31, 2014, we contributed additional capital based upon our ownership share to the Muskie joint venture in the amount of $0.2 million. In addition, during the year ended December 31, 2013, the Partnership provided a loan based upon its ownership share to Muskie in the amount of $0.2 million that remained outstanding as of March 31, 2014.

In March 2012, we made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf Terminals LLC (“Timber Wolf”), with affiliates of Wexford Capital. Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio. The initial investment was our proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during the year ended 2012 or the three months ended March 31, 2014 and 2013.

In addition, during the second quarter of 2012 we formed Razorback, a services company to provide drill pad construction services in the Utica Shale for drilling operators. Razorback completed the construction of two drill pads during the three months ended March 31, 2014, in addition to the construction and upgrade of eleven drill pads during 2013. Two impoundments for fracking water were also constructed during 2013 and Razorback has constructed several access roads for operators in the Utica Shale region.

Factors That Impact Our Business

Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems at mining locations, (4) the availability of transportation for coal shipments or (5) 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) changes in governmental regulation, (2) the availability and prices of competing

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electricity-generation fuels, (3) our ability to secure or acquire high-quality coal reserves and (4) our ability to find buyers for coal under favorable supply contracts.

We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of March 31, 2014, we had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

Year	Tons (in thousands)	Number of customers
2014 Q2-Q4	2,368	20
2015	1,796	4
2016	1,100	2
2017	1,100	2

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

Results of Operations

Segment Information

We conduct business through four reportable business segments: Central Appalachia, Northern Appalachia, Eastern Met and Rhino Western. Additionally, we have an Other category that is described below. Our Central Appalachia segment consists of four mining complexes: Tug River, Rob Fork and Deane, which as of March 31, 2014, together included two underground mines, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, our Central Appalachia segment includes our Elk Horn coal leasing operations. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex, the Leesville field and the Springdale field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of March 31, 2014. Our Sands Hill mining complex, located in southern Ohio, included one surface mine, a preparation plant and a river terminal as of March 31, 2014. Our Rhino Western segment includes our one underground mine in the Western Bituminous at our Castle Valley mining complex in Utah. The Eastern Met segment includes our 51% equity interest in the results of operations of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. As of March 31, 2014, this complex was comprised of one underground mine and a preparation plant and loadout facility (owned by our Rhino Eastern joint venture partner).

Beginning with 2013 year-end reporting, we had included a reportable business segment for our oil and natural gas activities since the total assets for these operations met the quantitative threshold for separate segment reporting. The Oil and Natural Gas segment included our Utica Shale activities, which were sold during the first quarter of 2014 as described earlier, as well as our Cana Woodford activities, the Razorback drill pad construction operations and the Muskie joint venture to provide sand for fracking operations. Prior to 2013, our oil and natural gas activities were included in our Other category for segment reporting purposes. Since the majority

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of our oil and natural gas activities were in the Utica Shale and the Utica Shale financial results are now included in discontinued operations due to their sale, the segment data for our remaining oil and natural gas activities has been included in the Other category for segment reporting purposes for 2014 and the 2013 comparable period since they are immaterial. Our Other category is comprised of our ancillary businesses and our remaining oil and natural gas activities.

Evaluating Our Results of Operations

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

Adjusted EBITDA.  The discussion of our results of operations below includes references to, and analysis of, our segments’ Adjusted EBITDA results. Adjusted EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization, including our proportionate share of these expense items from our Rhino Eastern LLC joint venture, 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 “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA to net income by segment for each of the periods indicated.

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

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

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Summary

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the three months ended March 31, 2014 and 2013:

	Three months ended March 31,
	2014			2013
	(in millions)
Statement of Operations Data:
Total revenues	$	59.9		$	74.5
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	46.4			54.8
Freight and handling costs	0.3			0.2
Depreciation, depletion and amortization	9.2			10.1
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	5.6			5.5
(Gain)/loss on sale/disposal of assets-net	(0.7		)	0.9
Income from operations	(0.9		)	3.0
Interest and other income (expense):
Interest expense	(3.2		)	(1.9		)
Interest income	—			—
Equity in net (loss) of unconsolidated affiliates	(0.9		)	(1.4		)
Total interest and other (expense) income	(4.1		)	(3.3		)
Net (loss) from continuing operations	(5.0		)	(0.3		)
Net income from discontinued operations	130.5			0.1
Net income	$	125.5		$	(0.2	)
Other Financial Data
Adjusted EBITDA from continuing operations	$	7.7		$	13.0
Net income from discontinued operations	130.5			0.1
Total Adjusted EBITDA	$	138.2		$	13.1

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Summary.  For the three months ended March 31, 2014, our total revenues decreased to $59.9 million from $74.5 million for the three months ended March 31, 2013. We sold 0.8 million tons of coal for the three months ended March 31, 2014, which is a 15.9% decrease compared to the tons of coal sold for the three months ended March 31, 2013. This decrease was the result of continued weak demand in the met and steam coal markets. We believe the weak demand in the steam coal markets was primarily driven by an over-supply of low priced natural

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gas that increased stockpiles of coal at electric utilities. We believe utilities are still working to decrease their coal stockpiles, which has extended the weakness in the steam coal markets even though natural gas prices have risen from their previous historic lows. We believe the weak demand in the met coal markets was primarily driven by a decrease in world-wide steel production due to economic weakness in China and Europe.

Net loss from continuing operations and Adjusted EBITDA from continuing operations decreased for the three months ended March 31, 2014 from the three months ended March 31, 2013. We generated a net loss from continuing operations of approximately $5.0 million for the three months ended March 31, 2014 compared to a net loss from continuing operations of approximately $0.3 million for the three months ended March 31, 2013 as reductions in costs were offset by lower coal revenues. Net loss from continuing operations for the three months ended March 31, 2014 was negatively impacted period to period due to a $0.9 million net loss from our Rhino Eastern joint venture compared to net loss of $1.2 million for the three months ended March 31, 2013, which represents our proportionate share of income from Rhino Eastern in which we have a 51% membership interest and for which we serve as manager.

Adjusted EBITDA from continuing operations decreased to $7.7 million for the three months ended March 31, 2014 from $13.0 million for the three months ended March 31, 2013. Adjusted EBITDA from continuing operations decreased period to period primarily due to the increase in net loss from continuing operations as described above.

Including income from discontinued operations of approximately $130.5 million, our total net income and Adjusted EBITDA for the three months ended March 31, 2014 were $125.5 million and $138.2 million, respectively. Income from discontinued operations consisted primarily of the gain of approximately $121.7 million from the sale of our Utica Shale oil and natural gas properties.

Tons Sold.  The following table presents tons of coal sold by reportable segment for the three months ended March 31, 2014 and 2013:

	Three months	Three months	Increase/
	ended	ended	(Decrease)
Segment	March 31, 2014	March 31, 2013	Tons		% *
	(in thousands, except %)
Central Appalachia	352.9	420.5	(67.6	)	(16.1	)%
Northern Appalachia	262.0	348.8	(86.8	)	(24.9	)%
Rhino Western	231.6	236.9	(5.3	)	(2.2	)%
Total *†	846.5	1,006.2	(159.7	)	(15.9	)%

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

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†Excludes tons sold by the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

We sold approximately 0.8 million tons of coal for the three months ended March 31, 2014 compared to approximately 1.0 million tons for the three months ended March 31, 2013. The decrease in total tons sold year-to-year was primarily due to lower sales from our Hopedale complex in Northern Appalachia due to railroad transportation constraints, as well as fewer met coal tons sold from our Central Appalachia segment due to weak market conditions. Tons of coal sold in our Central Appalachia segment decreased by approximately 16.1% to approximately 0.4 million tons for the three months ended March 31, 2014 compared to the three months ended March 31, 2013, primarily due to a decrease in met coal tons sold in the three months ended March 31, 2014 compared to 2013. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.1 million tons, or 24.9%, to approximately 0.3 million tons for the three months ended March 31, 2014 compared to the three months ended March 31, 2013, primarily due to lower sales from our Hopedale complex as discussed above. Coal sales from our Rhino Western segment were relatively flat for the three months ended March 31, 2014 compared to 2013 as our Castle Valley mine continued to fulfill contracted customer shipments.

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Revenues.  The following table presents revenues and coal revenues per ton by reportable segment for the three months ended March 31, 2014 and 2013:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	March 31, 2014		March 31, 2013		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	25.7	$	37.5	$	(11.8	)	(31.5	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	4.9		4.4		0.5			10.5	%
Total revenues	$	30.6	$	41.9	$	(11.3	)	(27.1	)%
Coal revenues per ton*	$	72.89	$	89.32	$	(16.43	)	(18.4	)%
Northern Appalachia
Coal revenues	$	15.9	$	20.3	$	(4.4	)	(21.3	)%
Freight and handling revenues	0.3		0.6		(0.3		)	(45.7	)%
Other revenues	2.5		1.0		1.5			152.1	%
Total revenues	$	18.7	$	21.9	$	(3.2	)	(14.2	)%
Coal revenues per ton*	$	60.85	$	58.09	$	2.76		4.7	%
Rhino Western
Coal revenues	$	9.6	$	9.6	$	—		(0.2	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	9.6	$	9.6	$	—		(0.1	)%
Coal revenues per ton*	$	41.34	$	40.50	$	0.84		2.1	%
Other**
Coal revenues	n/a		n/a		n/a			n/a
Freight and handling revenues	n/a		n/a		n/a			n/a
Other revenues	1.0		1.1		(0.1		)	(2.8	)%
Total revenues	$	1.0	$	1.1	$	(0.1	)	(2.8	)%
Coal revenues per ton*	n/a		n/a		n/a			n/a
Total
Coal revenues	$	51.2	$	67.4	$	(16.2	)	(24.0	)%
Freight and handling revenues	0.3		0.6		(0.3		)	(45.7	)%
Other revenues	8.4		6.5		1.9			30.1	%
Total revenues	$	59.9	$	74.5	$	(14.6	)	(19.5	)%
Coal revenues per ton*	$	60.53	$	67.00	$	(6.47	)	(9.7	)%

*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 and our oil and natural gas investments. 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 this category.

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Our coal revenues for the three months ended March 31, 2014 decreased by approximately $16.2 million, or 24.0%, to approximately $51.2 million from approximately $67.4 million for the three months ended March 31, 2013. The decrease in coal revenues was primarily due to fewer met coal tons sold and lower met coal prices in Central Appalachia, as well as fewer tons sold from our Hopedale complex in Northern Appalachia due to railroad transportation constraints. Coal revenues per ton were $60.53 for the three months ended March 31, 2014, a decrease of $6.47, or 9.7%, from $67.00 per ton for the three months ended March 31, 2013. This decrease in coal revenues per ton was primarily the result of lower prices for met coal sold in Central Appalachia, partially offset by an increase in coal revenues per ton in our Northern Appalachia segment primarily due to fewer lower priced tons being sold from our Sands Hill complex for the three months ended March 31, 2014 compared to 2013.

For our Central Appalachia segment, coal revenues decreased by approximately $11.8 million, or 31.5%, to approximately $25.7 million for the three months ended March 31, 2014 from approximately $37.5 million for the three months ended March 31, 2013, primarily due to fewer met coal tons sold and a decrease in the price for met coal tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $16.43, or 18.4%, to $72.89 per ton for the three months ended March 31, 2014 as compared to $89.32 for the three months ended March 31, 2013, primarily due to lower prices for met coal sold, along with the expiration of a long-term, above-market steam coal sales contract. Other revenues increased slightly for our Central Appalachia segment primarily due to higher coal royalty revenue from our coal leasing business as our lessees mined more tons during the three months ended March 31, 2014 as compared to 2013.

For our Northern Appalachia segment, coal revenues were approximately $15.9 million for the three months ended March 31, 2014, a decrease of approximately $4.4 million, or 21.3%, from approximately $20.3 million for the three months ended March 31, 2013. This decrease was primarily due to fewer tons sold from our Hopedale complex in Northern Appalachia as mentioned earlier. Coal revenues per ton for our Northern Appalachia segment increased by $2.76, or 4.7%, to $60.85 per ton for the three months ended March 31, 2014 as compared to $58.09 per ton for the three months ended March 31, 2013. This increase was primarily due to the mix of fewer lower priced tons being sold from our Sands Hill complex compared to higher priced tons sold from our Hopedale complex.

For our Rhino Western segment, coal revenues were relatively flat for the three months ended March 31, 2014 compared to the three months ended March 31, 2013. Coal revenues per ton for our Rhino Western segment were $41.34 for the three months ended March 31, 2014, an increase of $0.84, or 2.1%, from $40.50 for the three months ended March 31, 2013. The increase in coal revenues per ton were due to an increase in the contracted sales prices for steam coal sales from our Castle Valley mine for the three months ended March 31, 2014 compared to 2013.

Other revenues for our Other category decreased by approximately $0.1 million for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013, primarily due to lower coal transportation revenues for third parties.

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

(In thousands, except per ton data and %)	Three months ended March 31, 2014		Three months ended March 31, 2013		Increase (Decrease) %*
Met coal tons sold	86.3		181.9		(52.6	)%
Steam coal tons sold	266.6		238.6		11.7	%
Total tons sold †	352.9		420.5		(16.1	)%
Met coal revenue	$	7,005	$	18,781	(62.7	)%
Steam coal revenue	$	18,714	$	18,778	(0.3	)%
Total coal revenue †	$	25,719	$	37,559	(31.5	)%
Met coal revenues per ton	$	81.17	$	103.23	(21.4	)%
Steam coal revenues per ton	$	70.21	$	78.70	(10.8	)%
Total coal revenues per ton †	$	72.89	$	89.32	(18.4	)%
Met coal tons produced	107.1		116.7		(8.2	)%
Steam coal tons produced	235.3		271.3		(13.3	)%
Total tons produced †	342.4		388.0		(11.8	)%

† Excludes data for the Rhino Eastern mining complex located in West Virginia for which we serve as manager.

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

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Costs and Expenses.  The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the three months ended March 31, 2014 and 2013:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	March 31, 2014		March 31, 2013		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	21.1	$	28.7	$	(7.6	)	(26.6	)%
Freight and handling costs	—		0.1		(0.1		)	n/a
Depreciation, depletion and amortization	5.4		6.3		(0.9		)	(13.8	)%
Selling, general and administrative	5.3		5.2		0.1			1.7	%
Cost of operations per ton*	$	59.70	$	68.21	$	(8.51	)	(12.5	)%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	14.4	$	13.9	$	0.5		3.3	%
Freight and handling costs	0.3		0.1		0.2			96.1	%
Depreciation, depletion and amortization	1.9		2.1		(0.2		)	(8.4	)%
Selling, general and administrative	—		0.1		(0.1		)	(47.2	)%
Cost of operations per ton*	$	55.00	$	40.01	$	14.99		37.5	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	7.7	$	7.6	$	0.1		2.3	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.4		1.3		0.1			5.0	%
Selling, general and administrative	0.1		—		0.1			175.9	%
Cost of operations per ton*	$	33.43	$	31.96	$	1.47		4.6	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	3.2	$	4.6	$	(1.4	)	(30.4	)%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	0.5		0.4		0.1			25.9	%
Selling, general and administrative	0.2		0.2		—			(7.5	)%
Cost of operations per ton**	n/a		n/a		n/a			n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	46.4	$	54.8	$	(8.4	)	(15.3	)%
Freight and handling costs	0.3		0.2		0.1			28.1	%
Depreciation, depletion and amortization	9.2		10.1		(0.9		)	(8.5	)%
Selling, general and administrative	5.6		5.5		0.1			1.3	%
Cost of operations per ton*	$	54.82	$	54.44	$	0.38		0.7	%

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

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

Cost of Operations.  Total cost of operations was $46.4 million for the three months ended March 31, 2014 as compared to $54.8 million for the three months ended March 31, 2013. Our cost of operations per ton was $54.82 for the three months ended March 31, 2014, an increase of $0.38, or 0.7%, from the three months ended March 31, 2013. Total cost of operations decreased primarily due to a decrease in tons produced in our Central Appalachia, which was in response to weak market conditions for coal from this complex. The increase in the cost of operations on a per ton basis was primarily due to an increase from our Northern Appalachia operations associated adverse mining conditions at our Hopedale operation, partially offset by a decrease in Central Appalachia due to production at lower cost operations.

Our cost of operations for the Central Appalachia segment decreased by $7.6 million, or 26.6%, to $21.1 million for the three months ended March 31, 2014 from $28.7 million for the three months ended March 31, 2013. The decrease in total cost of operations was primarily due to a decrease in tons produced, which was in response to weak market conditions. Our cost of operations per ton decreased to $59.70 per ton for the three months ended March 31, 2014 from $68.21 per ton for the three months ended March 31, 2013. The decrease in cost of operations per ton was primarily due to production at lower cost operations.

In our Northern Appalachia segment, our cost of operations increased by $0.5 million, or 3.3%, to $14.4 million for the three months ended March 31, 2014 from $13.9 million for the three months ended March 31, 2013. Our cost of operations per ton was $55.00 for the three months ended March 31, 2014, an increase of $14.99, or 37.5%, compared to $40.01 for the three months ended March 31, 2013. The increase in total cost of operations and cost of operations per ton was primarily due to adverse mining conditions at our Hopedale operation.

Our cost of operations for the Rhino Western segment increased slightly by $0.1 million, or 2.3%, to $7.7 million for the three months ended March 31, 2014 from $7.6 million for the three months ended March 31, 2013. Our cost of operations per ton increased to $33.43 per ton for the three months ended March 31, 2014 from $31.96 per ton for three months ended March 31, 2013. The increases in cost of operations and cost of operations per ton were primarily due to adverse mining conditions at our Castle Valley mine.

Cost of operations in our Other category decreased by $1.4 million for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013, primarily due to lower costs for outside professional services.

Freight and Handling.  Total freight and handling cost for the three months ended March 31, 2014 increased by $0.1 million, or 28.1%, to $0.3 million from $0.2 million for the three months ended March 31, 2013. This increase was primarily due to coal sold from our Hopedale complex that required transportation by truck to the customer.

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization (“DD&A”) expense for the three months ended March 31, 2014 was $9.2 million as compared to $10.1 million for the three months ended March 31, 2013.

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For the three months ended March 31, 2014, our depreciation cost decreased to $7.5 million from $8.1 million for the three months ended March 31, 2013. This decrease is primarily due to lower depreciation costs in our Central Appalachia segment.

For the three months ended March 31, 2014, our depletion cost was $1.2 million compared to $1.3 million for the three months ended March 31, 2013. This decrease is primarily due to fewer coal tons produced in our Central Appalachia segment.

For the three months ended March 31, 2014, our amortization cost decreased to $0.5 million from $0.7 million for the three months ended March 31, 2013. This decrease is primarily due to lower amortization costs of mine development in our Central Appalachia segment.

Selling, General and Administrative.  Selling, general and administrative (“SG&A”) expense for the three months ended March 31, 2014 was relatively flat at $5.6 million as compared to $5.5 million for the three months ended March 31, 2013.

Interest Expense.  Interest expense for the three months ended March 31, 2014 increased to $3.2 million as compared to $1.9 million for the three months ended March 31, 2013, primarily due to the write-off of approximately $1.1 million of a portion of our unamortized debt issuance costs. This write-off was due to an amendment of our credit facility that reduced the borrowing capacity from $300 million to $200 million.  See the discussion on our credit agreement in the Liquidity section that follows for more information on this amendment.

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Eastern Met Supplemental Data.  Operational and financial data for the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager (referred to as the “Eastern Met” segment) is presented below. Our consolidated revenue and costs do not include any portion of the revenue or costs of Rhino Eastern since we account for this operation under the equity method. We only record our proportionate share of net income of Rhino Eastern as a single item in our financial statements, but we believe the presentation of these items for Rhino Eastern provides additional insight into how this operation contributes to our overall performance.

(In thousands, except per ton data and %)	Three months ended March 31, 2014			Three months ended March 31, 2013			Increase (Decrease) %*
Eastern Met 100% Basis
Coal revenues	$	7,462		$	6,168		21.0	%
Total revenues	$	7,529		$	6,168		22.1	%
Coal revenues per ton*	$	98.17		$	121.30		(19.1	%)
Cost of operations	$	8,017		$	7,543		6.3	%
Cost of operations per ton*	$	105.48		$	148.34		(28.9	%)
Depreciation, depletion and amortization	$	500		$	475		5.3	%
Interest expense	$	15		$	0		n/a
Net income (loss)	$	(1,717	)	$	(2,397	)	28.4	%
Partnership’s portion of net income (loss)	$	(876	)	$	(1,223	)	28.4	%
Tons produced	79.5			36.7			116.8	%
Tons sold	76.0			50.9			49.5	%

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

An increase in tons produced and sold for the three months ended March 31, 2014 compared to 2013 resulted in increased revenue and a lower net loss for the three months ended March 31, 2014 compared to the same period in 2013.  Additionally, cost of operations improved year to year as we transitioned mining operations to the lower cost Eagle #3 mine. However, a significant decrease in the market price for the quality of met coal that Rhino Eastern produces continues to impact the financial results of Rhino Eastern.

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Net Income (Loss) from Continuing Operations.  The following table presents net income (loss) from continuing operations by reportable segment for the three months ended March 31, 2014 and 2013:

	Three months ended			Three months ended			Increase
Segment	March 31, 2014			March 31, 2013			(Decrease)
	(in millions)
Central Appalachia	$	(3.8	)	$	(2.2	)	$	(1.6	)
Northern Appalachia	1.1			4.6			(3.5		)
Rhino Western	(0.3		)	(0.1		)	(0.2		)
Eastern Met *	(0.9		)	(1.2		)	0.3
Other	(1.1		)	(1.4		)	0.3
Total	$	(5.0	)	$	(0.3	)	$	(4.7	)

*Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

For the three months ended March 31, 2014, total net loss from continuing operations was a loss of approximately $5.0 million compared to a loss of approximately $0.3 million for the three months ended March 31, 2013. We had a larger net loss from continuing operations year to year as decreases in costs and expenses were offset by decreases in coal revenues. Including our income from discontinued operations of approximately $130.5 million, our total net income for the three months ended March 31, 2014 was approximately $125.5 million. Our income from discontinued operations for the three months ended March 31, 2014 consisted primarily of the approximately $121.7 million gain from the sale of our Utica Shale oil and natural gas properties. Income from discontinued operations of approximately $0.1 million for the three months ended March 31, 2013 resulted in a total net loss of approximately $0.2 million as the Utica Shale oil and gas properties had limited production and sales during the first three months of 2013.

For our Central Appalachia segment, net loss from continuing operations was approximately $3.8 million for the three months ended March 31, 2014, a $1.6 million larger net loss as compared to the three months ended March 31, 2013, primarily due to ongoing weakness in the met and steam coal markets. Net income from continuing operations in our Northern Appalachia segment decreased by $3.5 million to $1.1 million for the three months ended March 31, 2014, from $4.6 million for the three months ended March 31, 2013. This decrease was primarily due to higher costs attributable to difficult mining conditions at our Hopedale complex as well as fewer tons sold at our Hopedale complex due to railroad transportation constraints. Net loss from continuing operations in our Rhino Western segment was a loss of $0.3 million for the three months ended March 31, 2014, compared to a net loss from continuing operations of $0.1 million for the three months ended March 31, 2013. This larger net loss was primarily the result of an increase in cost of operations at our Castle Valley operation due to an increase in mining equipment costs year to year. Our Eastern Met segment recorded a net loss from continuing operations of $0.9 million for the three months ended March 31, 2014 compared to a net loss

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from continuing operations of $1.2 million for the three months ended March 31, 2013. Results improved slightly at Rhino Eastern as cost of operations improved year to year as we transitioned to the lower cost Eagle 3 mine, but weak pricing in the met coal market continued to cause Rhino Eastern to generate a net loss from continuing operations for the three months ended March 31, 2014.  For the Other category, we had a net loss from continuing operations of $1.1 million for the three months ended March 31, 2014, which was an improvement as compared to a net loss from continuing operations of $1.4 million for the three months ended March 31, 2013. The improvement year to year was primarily due to lower costs for outside professional services in the three months ended March 31, 2014.

Adjusted EBITDA from Continuing Operations.  The following table presents Adjusted EBITDA from continuing operations by reportable segment for the three months ended March 31, 2014 and 2013:

	Three months ended			Three months ended			Increase
Segment	March 31, 2014			March 31, 2013			(Decrease)
	(in millions)
Central Appalachia	$	2.6		$	6.0		$	(3.4	)
Northern Appalachia	3.2			6.9			(3.7		)
Rhino Western	1.2			1.4			(0.2		)
Eastern Met *	(0.6		)	(1.0		)	0.4
Other	1.3			(0.3		)	1.6
Total	$	7.7		$	13.0		$	(5.3	)

*Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

Total Adjusted EBITDA from continuing operations for the three months ended March 31 2014 was $7.7 million, a decrease of $5.3 million from the three months ended March 31, 2013. Adjusted EBITDA from continuing operations decreased primarily as a result of a decrease in net income, as described previously. Total Adjusted EBITDA for the three months ended March 31, 2014 and 2013 was $138.2 million and $13.1 million, respectively, once the results from discontinued operations were included.  The increase in total Adjusted EBITDA year to year was primarily attributable to the approximately $121.7 million gain from the sale of our Utica Shale oil and natural gas properties. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, DD&A and interest expense are not presented separately for our Eastern Met segment. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA to net income on a segment basis.

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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			Eastern
Three months ended March 31, 2014	Appalachia			Appalachia		Western			Met *			Other			Total
	(in millions)
Net income from continuing operations	$	(3.8	)	$	1.1	$	(0.3	)	$	(0.9	)	$	(1.1	)	$	(5.0	)
Plus:
DD&A	5.4			1.9		1.4			—			0.5			9.2
Interest expense	1.0			0.2		0.1			—			1.9			3.2
EBITDA from continuing operations†	$	2.6		$	3.2	$	1.2		$	(0.9	)	$	1.3		$	7.4
Plus: Rhino Eastern DD&A-51%	—			—		—			0.3			—			0.3
Plus: Rhino Eastern interest expense-51%	—			—		—			—			—			—
Adjusted EBITDA from continuing operations†	2.6			3.2		1.2			(0.6		)	1.3			7.7
Net income from discontinued operations	—			—		—			—			—			130.5
Adjusted EBITDA †	$	2.6		$	3.2	$	1.2		$	(0.6	)	$	1.3		$	138.2

	Central			Northern		Rhino			Eastern
Three months ended March 31, 2013	Appalachia			Appalachia		Western			Met *			Other			Total
	(in millions)
Net income from continuing operations	$	(2.2	)	$	4.6	$	(0.1	)	$	(1.2	)	$	(1.4	)	$	(0.3	)
Plus:
DD&A	6.3			2.1		1.3			—			0.4			10.1
Interest expense	0.9			0.2		0.2			—			0.6			1.9
EBITDA from continuing operations† **	$	5.0		$	6.9	$	1.4		$	(1.2	)	$	(0.3	)	$	11.8
Plus: Rhino Eastern DD&A-51%	—			—		—			0.2			—			0.2
Plus: Rhino Eastern interest expense-51%	—			—		—			—			—			—
Plus: Non-cash write-off of mining equipment (1)	1.0			—		—			—			—			1.0
Adjusted EBITDA from continuing operations† **	6.0			6.9		1.4			(1.0		)	(0.3		)	13.0
Net income from discontinued operations	—			—		—			—			—			0.1
Adjusted EBITDA †	$	6.0		$	6.9	$	1.4		$	(1.0	)	$	(0.3	)	$	13.1

*Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.

**Totals may not foot due to rounding.

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

(1)During the first quarter of 2013, we incurred a non-cash expense of approximately $1.0 million due to the write-off of a continuous miner that was damaged at one of our underground mines in Central Appalachia. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.

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	Three months ended March 31,
	2014		2013
	(in millions)
Net cash provided by operating activities	$	11.9	$	10.6
Plus:
Increase in net operating assets	—		2.7
Gain on sale of assets	130.8		—
Amortization of deferred revenue	0.3		0.3
Amortization of actuarial gain	0.1		—
Interest expense	3.2		1.9
Equity in net income of unconsolidated affiliate	—		—
Less:
Decrease in net operating assets	5.3		—
Accretion on interest-free debt	—		0.1
Amortization of advance royalties	0.1		—
Amortization of debt issuance costs	1.4		0.3
Equity-based compensation	0.1		0.3
Loss on sale/disposal of assets	—		0.9
Loss on retirement of advance royalties	—		—
Accretion on asset retirement obligations	0.6		0.6
Equity in net loss of unconsolidated affiliates	0.9		1.4
EBITDA†	$	137.9	$	11.9
Plus: Rhino Eastern DD&A-51%	0.3		0.2
Plus: Rhino Eastern interest expense-51%	—		—
Plus: Non-cash write-off of mining equipment (1)	—		1.0
Adjusted EBITDA† **	138.2		13.1
Less: Net income from discontinued operations	130.5		0.1
Adjusted EBITDA from continuing operations †	$	7.7	$	13.0

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

(1)During the first quarter of 2013, we incurred a non-cash expense of approximately $1.0 million due to the write-off of a continuous miner that was damaged at one of our underground mines in Central Appalachia. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in developing and mining our reserves, as well as complying with applicable environmental and mine safety laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, and service our debt. Our sources of liquidity include

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cash generated by our operations, borrowings under our credit agreement and issuances of equity and debt securities.

The principal indicators of our liquidity are our cash on hand and availability under our credit agreement. As of March 31, 2014, our available liquidity was $172.9 million, including cash on hand of $1.1 million and $171.8 million available under our credit agreement.

Please read “—Capital Expenditures” for a further discussion of the impact on liquidity.

Cash Flows

Net cash provided by operating activities was $11.9 million for the three months ended March 31, 2014 as compared to $10.6 million for the three months ended March 31, 2013.  This increase in cash provided by operating activities was primarily the result of favorable changes in working capital accounts for the three months ended March 31, 2014 as compared to 2013.

Net cash provided by investing activities was $159.8 million for the three months ended March 31, 2014 as compared to net cash used in investing activities of $6.2 million for the three months ended March 31, 2013. The increase in cash provided by investing activities was primarily due to the proceeds received from the sale of our Utica Shale oil and natural gas assets during the three months ended March 31, 2014, partially offset by an increase in additions to property, plant and equipment that were primarily due to the ongoing development of our new Pennyrile mine in western Kentucky.

Net cash used in financing activities for the three months ended March 31, 2014 was $170.9 million, which was primarily attributable to repayments on debt during this period with the proceeds from the Utica Shale oil and natural gas property sale, along with distributions paid to unitholders. Net cash used in financing activities for the three months ended March 31, 2013 was $4.1 million, which were primarily attributable to distributions to our unitholders in that period, partially offset by borrowings under our credit agreement.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Maintenance capital expenditures are those capital expenditures required to maintain our long term operating capacity. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves to the extent such expenditures are made to maintain our long term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of reserves, 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 three months ended March 31, 2014 were approximately $1.4 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the three months ended

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March 31, 2014 were approximately $26.7 million, which were primarily related to the ongoing development of our new Riveredge mine on our Pennyrile property in western Kentucky. For the year ending December 31, 2014, we have budgeted $7 million to $10 million for maintenance capital expenditures and $35 million to $40 million for expansion capital expenditures.

We believe that we have sufficient liquid assets, cash flows from operations and borrowing capacity under our credit agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for the next twelve months. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity. From time to time, we may issue debt and equity securities.

Credit Agreement

On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of participating lenders. The maximum availability under the amended and restated credit facility was $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million was available for letters of credit. As described below, in March 2014 the amended and restated credit facility was amended and the borrowing capacity under the facility was reduced to $200.0 million, with the amount available for letters of credit unchanged.

Loans under the credit agreement bear interest at either (i) a base rate equaling the highest of (a) the Federal Funds Open Rate plus 0.50%; (b) the prime rate; or (c) daily LIBOR plus 1.00%, plus an applicable margin in each case or (ii) LIBOR plus an applicable margin, at our option. The applicable margin for the base rate option is 1.50% to 2.50%, and the applicable margin for the LIBOR option is 2.50% to 3.50%, each of which depends on our and our subsidiaries’ consolidated leverage ratio (“Consolidated Leverage Ratio”). The credit agreement also contains letter of credit fees equal to an applicable margin of 2.50% to 3.50% depending on the Consolidated Leverage Ratio, multiplied by the aggregate amount available to be drawn on the letters of credit, and a 0.15% fronting fee payable to the administrative agent. In addition, we incur a commitment fee on the unused portion of the credit agreement at a rate of 0.375% to 0.50% per annum, depending on the Consolidated Leverage Ratio. Borrowings on the line of credit are collateralized by all of our unsecured assets.

Our credit agreement requires us to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. As of and for the period ended March 31, 2014, we were in compliance with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.

As discussed earlier, we sold our Utica Shale oil and natural gas assets in March 2014 for approximately $184.0 million. We used the initial proceeds from this sale of approximately $179.0 million to reduce the outstanding debt on our amended and restated senior secured credit facility. At March 31, 2014, we had borrowed $4.2 million at a variable interest rate of LIBOR plus 3.00% (3.16% at March 31, 2014). In addition, we had outstanding letters of credit of approximately $20.3 million at a fixed interest rate of 3.00% at March 31, 2014. We had not

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used $171.8 million of the borrowing availability at March 31, 2014. During the three months ended March 31, 2014, we had average borrowings outstanding of approximately $150.4 million in relation to this credit agreement.

On April 19, 2013, we entered into an amendment of the amended and restated senior secured credit facility. The amendment provided for an increase in the maximum allowed investments in coal-related entities outside of our current partnership structure (i.e. joint ventures) under the amended and restated senior secured credit facility from $25 million to $40 million. The amendment also altered the maximum leverage ratio allowed under the amended and restated senior secured credit facility and also altered the pricing grid to include applicable interest rates for borrowings, letter of credit fees and commitment fees on unused borrowings based upon the new maximum leverage ratio. The amendment increased the maximum leverage ratio of the amended and restated senior secured credit facility to 3.75 from April 1, 2013 through March 31, 2015, then stepped the maximum leverage ratio down to its previous level of 3.0 by December 31, 2015. All other terms of the amended and restated senior secured credit facility were not affected by the amendment.

In March 2014, we entered into a second amendment of our amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. This second amendment permitted us to sell certain assets to Gulfport, as described earlier in the discussion of our oil and natural gas activities, which previously constituted a portion of the collateral under the amended and restated senior secured credit facility. This second amendment also reduces the borrowing capacity under the amended and restated senior secured credit facility to a maximum of $200 million and alters the maximum leverage ratio to 3.5 from January 1, 2014 through September 30, 2015. The maximum leverage ratio decreases to 3.25 from October 1, 2015 through December 31, 2015 and then decreases to 3.0 after December 31, 2015. In addition, the second amendment adjusts the maximum investments (other than directly by us) in hydrocarbons, hydrocarbon interests and assets and activities related to hydrocarbons, in each case, excluding coal, in an aggregate amount not to exceed $50 million. All other terms of the amended and restated senior secured credit facility were not affected by the second amendment.

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 credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding

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facility pursuant to which we are required to provide bank letters of credit in an amount of up to 25% of the aggregate bond liability. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

As of March 31, 2014, we had $20.3 million in letters of credit outstanding, of which $16.0 million served as collateral for surety bonds.

Critical Accounting Policies and Estimates

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

The accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are fully described in our Annual Report on Form 10-K for the year ended December 31, 2013. There have been no significant changes in these policies and estimates as of March 31, 2014.

Recent Accounting Pronouncements

None.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

We manage our commodity price risk for coal sales through the use of supply contracts. As of March 31, 2014, we had commitments under supply contracts to deliver annually scheduled base quantities of coal as follows:

Year	Tons (in thousands)	Number of customers
2014 Q2-Q4	2,368	20
2015	1,796	4
2016	1,100	2
2017	1,100	2

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

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

A hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income by $0.1 million for the three months ended March 31, 2014. A hypothetical increase of 10% in steel prices would have reduced net income by $0.2 million for the three months ended March 31, 2014. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.1 million for the three months ended March 31, 2014.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $0.2 million for the three months ended March 31, 2014.

Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures.  As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2014 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting.  There was no change in our internal control over financial reporting that occurred during the quarter ended March 31, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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, 2013, 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, 2013. 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.

There were no sales of unregistered equity securities during the period covered by this report.

Item 3.   Defaults upon Senior Securities.

None.

Item 4.   Mine Safety Disclosure

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the three months ended March 31, 2014 is included in Exhibit 95.1 to this report.

Item 5.   Other Information.

None.

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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	Second Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated as of October 26, 2010, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-34892) filed on November 1, 2010
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
10.1	Purchase and Sale Agreement with Gulfport Energy Corporation dated March 19, 2014, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on March 25, 2014
10.2	Second Amendment to Amended and Restated Credit Agreement, dated March 19, 2014 by and among Rhino Energy LLC, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets and Union Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners, Union Bank, N.A., as Syndication Agent, Raymond James Bank, FSB, Wells Fargo Bank, National Association and the Huntington National Bank, as Co-Documentation Agents and the guarantors and lenders party thereto, incorporated by reference to Exhibit 10.2 of the Current Report on Form 8-K (File No. 001-34892), filed on March 25, 2014
31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
32.1*	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
32.2*	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
95.1*	Mine Health and Safety Disclosure pursuant to §1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act for the three months ended March 31, 2014

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Exhibit Number	Description
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.

§ - Furnished with this Form 10-Q.  In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	RHINO RESOURCE PARTNERS LP
	By: Rhino GP LLC, its General Partner
Date: May 7, 2014	By:	/s/ Christopher I. Walton
		Christopher I. Walton
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: May 7, 2014	By:	/s/ Richard A. Boone
		Richard A. Boone
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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