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 June 30, 2013

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
(State or other jurisdiction of
incorporation or organization) 27-2377517
(IRS Employer
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 August 2, 2013, 15,374,896 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 June 30, 2013 and December 31, 2012	2
	Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2013 and 2012	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	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	61
Item 4.	Controls and Procedures	62
PART II—Other Information		62
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 3.	Defaults upon Senior Securities	63
Item 4.	Mine Safety Disclosure	63
Item 5.	Other Information	63
Item 6.	Exhibits	64
SIGNATURES		66

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, 2012, (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.

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PART I.—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands)

	June 30,			December 31,
	2013			2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	438		$	461
Accounts receivable, net of allowance for doubtful accounts ($0 as of June 30, 2013 and December 31, 2012)	24,693			33,560
Inventories	16,230			18,743
Advance royalties, current portion	74			187
Prepaid expenses and other	5,720			4,323
Total current assets	47,155			57,274
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	694,027			683,669
Less accumulated depreciation, depletion and amortization	(234,990		)	(219,709		)
Net property, plant and equipment	459,037			463,960
Advance royalties, net of current portion	5,377			4,506
Investment in unconsolidated affiliates	21,013			23,659
Intangible assets	1,187			1,228
Other non-current assets	8,985			8,831
TOTAL	$	542,754		$	559,458
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	18,706		$	18,030
Accrued expenses and other	19,764			22,178
Current portion of long-term debt	1,041			2,350
Current portion of asset retirement obligations	1,818			2,255
Current portion of postretirement benefits	227			227
Total current liabilities	41,556			45,040
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion	154,333			161,199
Asset retirement obligations, net of current portion	31,895			30,748
Other non-current liabilities	10,916			10,309
Postretirement benefits, net of current portion	6,726			6,520
Total non-current liabilities	203,870			208,776
Total liabilities	245,426			253,816
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners	284,933			292,791
General partner	11,037			11,420
Accumulated other comprehensive income	1,358			1,431
Total partners’ capital	297,328			305,642
TOTAL	$	542,754		$	559,458

See notes to unaudited condensed consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands, except per unit data)

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2013			2012			2013			2012
REVENUES:
Coal sales	$	56,963		$	72,177		$	124,377		$	141,780
Freight and handling revenues	640			1,794			1,262			3,314
Other revenues	9,225			16,027			15,934			26,787
Total revenues	66,828			89,998			141,573			171,881
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	51,655			60,203			106,490			117,290
Freight and handling costs	319			1,798			554			3,062
Depreciation, depletion and amortization	10,579			9,755			20,790			20,847
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	4,995			5,475			10,483			10,385
(Gain)/loss on sale/disposal of assets—net	(10,618		)	168			(9,692		)	(990		)
Total costs and expenses	56,930			77,399			128,625			150,594
INCOME FROM OPERATIONS	9,898			12,599			12,948			21,287
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense	(1,925		)	(1,962		)	(3,779		)	(3,784		)
Interest income and other	—			33			—			76
Equity in net income/(loss) of unconsolidated affiliates	(2,076		)	2,326			(3,449		)	4,391
Total interest and other income (expense)	(4,001		)	397			(7,228		)	683
INCOME BEFORE INCOME TAXES	5,897			12,996			5,720			21,970
INCOME TAXES	—			—			—			—
NET INCOME	5,897			12,996			5,720			21,970
Other comprehensive income:
Amortization of actuarial gain under ASC Topic 715	(36		)	(74		)	(72		)	(148		)
COMPREHENSIVE INCOME	$	5,861		$	12,922		$	5,648		$	21,822
General partner’s interest in net income	$	118		$	260		$	114		$	439
Common unitholders’ interest in net income	$	3,199		$	7,041		$	3,102		$	11,900
Subordinated unitholders’ interest in net income	$	2,580		$	5,695		$	2,504		$	9,631
Net income per limited partner unit, basic:
Common units	$	0.21		$	0.46		$	0.20		$	0.78
Subordinated units	$	0.21		$	0.46		$	0.20		$	0.78
Net income per limited partner unit, diluted:
Common units	$	0.21		$	0.46		$	0.20		$	0.78
Subordinated units	$	0.21		$	0.46		$	0.20		$	0.78
Distributions paid per limited partner unit (1)	$	0.445		$	0.48		$	0.89		$	0.96
Weighted average number of limited partner units outstanding, basic:
Common units	15,371			15,329			15,358			15,317
Subordinated units	12,397			12,397			12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units	15,379			15,331			15,363			15,325
Subordinated units	12,397			12,397			12,397			12,397

(1) No distributions were paid on the subordinated units for the three months ended June 30, 2013 and March 31, 2013.

See notes to unaudited condensed consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	5,720		$	21,970
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	20,790			20,847
Accretion on asset retirement obligations	1,178			870
Accretion on interest-free debt	57			109
Amortization of deferred revenue	(654		)	(572		)
Amortization of advance royalties	60			126
Amortization of debt issuance costs	611			537
Amortization of actuarial gain	(72		)	(148		)
Equity in net (income)/loss of unconsolidated affiliates	3,449			(4,391		)
Distribution from unconsolidated affiliate	—			2,958
Loss on retirement of advance royalties	32			—
(Gain) on sale/disposal of assets—net	(9,692		)	(990		)
Equity-based compensation	377			450
Changes in assets and liabilities:
Accounts receivable	6,316			2,650
Inventories	2,513			(8,172		)
Advance royalties	(849		)	(577		)
Prepaid expenses and other assets	(2,261		)	(176		)
Accounts payable	377			(7,337		)
Accrued expenses and other liabilities	1,373			5,698
Asset retirement obligations	(467		)	(754		)
Postretirement benefits	206			255
Net cash provided by operating activities	29,064			33,353
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(17,060		)	(42,387		)
Proceeds from sales of property, plant, and equipment	11,224			1,290
Changes in restricted cash	1,079			—
Principal payments received on notes receivable	—			8,160
Cash paid from issuance of notes receivable	—			(8,160		)
Investment in unconsolidated affiliates	(803		)	(114		)
Net cash used in investing activities	(5,560		)	(41,211		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	80,550			133,250
Repayments on line of credit	(86,960		)	(99,150		)
Proceeds from issuance of long-term debt	—			2,603
Repayments on long-term debt	(1,822		)	(1,233		)
Distributions to unitholders	(14,268		)	(27,202		)
General partner’s contributions	6			7
Net settlement of employee withholding taxes on unit awards vested	(53		)	(85		)
Payments on debt issuance costs	(980		)	—
Payment of offering costs	—			(7		)
Net cash (used in)/provided by financing activities	(23,527		)	8,183
NET INCREASE IN CASH AND CASH EQUIVALENTS	(23		)	325
CASH AND CASH EQUIVALENTS—Beginning of period	461			449
CASH AND CASH EQUIVALENTS—End of period	$	438		$	774

See notes to unaudited condensed consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2013 AND DECEMBER 31, 2012 AND FOR THE THREE AND SIX MONTHS ENDED

JUNE 30, 2013 AND 2012

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 June 30, 2013, condensed consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2013 and 2012 and the condensed consolidated statements of cash flows for the six months ended June 30, 2013 and 2012 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, 2012 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, 2012 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, 2012 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 and also have one underground mine located in Colorado that remained temporarily idled at June 30, 2013. 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 mineral rights that began to generate revenues in 2012.

5

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 and 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 June 30, 2013 and December 31, 2012, the Partnership has recorded its Rhino Eastern equity method investment of $18.9 million and $21.8 million, respectively, as a long-term asset. During the six months ended June 30, 2013, the Partnership contributed additional capital based upon its ownership share to the Rhino Eastern joint venture in the amount of $0.4 million.

On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. Normal operations have continued at the joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

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 2012 or the six months ended June 30, 2013. The Partnership has included its Timber Wolf investment in its Other category.

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

6

proportionate share of the operating profit/(loss) for the three and six months ended June 30, 2013, approximately $17,000 and ($132,000), respectively, for Muskie, which is still undergoing operational development. During the six months ended June 30, 2013, the Partnership contributed additional capital based upon its ownership share to the Muskie joint venture in the amount of $0.4 million. As of June 30, 2013 and December 31, 2012, the Partnership has recorded its Muskie equity method investment of $2.0 million and $1.7 million, respectively, as a long-term asset. The Partnership includes any operating activities of Muskie in its Other category.

Recently Issued Accounting Standards. In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-02, “Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”. This ASU requires preparers to report, in one place, information about reclassifications out of accumulated other comprehensive income (“AOCI”). The ASU also requires companies to report changes in AOCI balances. For significant items reclassified out of AOCI to net income in their entirety in the same reporting period, reporting (either on the face of the statement where net income is presented or in the notes) is required about the effect of the reclassifications on the respective line items in the statement where net income is presented. For items that are not reclassified to net income in their entirety in the same reporting period, a cross reference to other disclosures currently required under U.S. GAAP (e.g., pension amounts that are included in inventory) is required in the notes. The above information must be presented in one place (parenthetically on the face of the financial statements by income statement line item or in a note). Public companies must provide the information required by the ASU (e.g., changes in AOCI balances and reclassifications out of AOCI) in interim and annual periods. For public companies, the ASU is effective for fiscal years and interim periods within those years beginning after 15 December 2012, or the first quarter of 2013 for calendar-year companies. The Partnership has included the required disclosures of ASU 2013-02 in this Form 10Q and this ASU did not have a material effect on the Partnership.

3. BUSINESS COMBINATIONS AND OTHER ACQUISITIONS

Acquisition of Oil and Gas Mineral Rights

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

7

approximately 6,250 net acres. As of June 30, 2013, the Partnership had invested approximately $25.2 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 137,000 gross acres, or 6,850 net acres. In addition, per the joint operating agreement among the Partnership, Gulfport and an affiliate of Wexford Capital, the Partnership has funded its proportionate share of drilling costs to Gulfport for wells being drilled on the Partnership’s acreage. As of June 30, 2013 and December 31, 2012, the Partnership has funded approximately $9.3 million and $5.3 million, respectively, of drilling costs that are included in Coal properties and oil and natural gas properties in the unaudited condensed consolidated statements of financial position. Two wells began production in late 2012 and eleven additional wells were producing as of June 30, 2013. For the three and six months ended June 30, 2013, the Partnership recorded revenue from its Utica Shale investment of approximately $1.2 million and $1.5 million, respectively, in Other revenue in the unaudited condensed consolidated statements of operations and comprehensive income. For the three and six months ended June 30, 2012, the Partnership did not have any revenue from its Utica Shale investment.

On March 6, 2012, the Partnership completed a lease agreement with a third party for approximately 1,232 acres that the Partnership previously owned in the Utica Shale region in Harrison County, Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the third party to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay the Partnership the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for the approximately 1,232 acres. In addition, the lease agreement stipulates that the third party shall pay the Partnership a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

The Partnership analyzed the lease agreement and determined that the lease bonus payments represented a conveyance of these oil and gas rights, and should be recognized as a component of the Partnership’s unaudited consolidated condensed statements of operations and comprehensive income. This determination was based upon the fact that that the lease agreement did not require the Partnership to perform any future obligations to perform or participate in drilling activities and the lease agreement did not result in any pooling of assets that would be used to perform any future drilling activities. In addition, the entire amount of the lease bonus was recognized as Other revenues since the Partnership’s business activities have historically included the leasing of mineral resources, including coal leasing, which have been recorded as Other revenues. For the three and six months ended June 30, 2012, the Partnership recorded $6.9 million and $7.4 million, respectively, related to the initial lease bonus payments within Other revenues in the Partnership’s Northern Appalachia segment.

In April 2013, the Partnership closed on an agreement with a third party to sell the 20% royalty interest on its owned 1,232 acres in the Utica Shale for approximately $10.5 million. The sale of the royalty interest resulted in a gain of approximately $10.5 million since the Partnership had no cost basis associated with the royalty interest. This gain is included on the (Gain)/loss on

8

sale/disposal of assets—net line of the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

During the year ended December 31, 2011, the Partnership completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. The Partnership recorded an immaterial amount of royalty revenue from its Cana Woodford investment during the three and six months ended June 30, 2013 and 2012.

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 could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was recorded in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount are currently not probable.

During the third quarter of 2012, the Partnership paid $1.6 million of the $2.0 million that was accrued related to the acquisition since the conditions requiring payment had been met. The remaining accrued balance of $0.4 million is recorded in the Partnership’s unaudited condensed consolidated statements of financial position as of June 30, 2013 since the conditions remained probable and estimable.

The coal leases and property are estimated to contain approximately 32 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 initial construction of a new underground mining operation on this property with production targeted to begin in mid-2014.

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of June 30, 2013 and December 31, 2012 consisted of the following:

	June 30,		December 31,
	2013		2012
	(in thousands)
Other prepaid expenses	$	539	$	767
Prepaid insurance	2,929		1,895
Prepaid leases	127		121
Supply inventory	1,805		1,219
Deposits	320		321
Total Prepaid expenses and other	$	5,720	$	4,323

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5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of June 30, 2013 and December 31, 2012 are summarized by major classification as follows:

	Useful Lives	June 30, 2013			December 31, 2012
		(in thousands)
Land and land improvements		$	34,978		$	34,978
Mining and other equipment and related facilities	2 - 20 Years	299,342			297,615
Mine development costs	1 - 15 Years	68,534			67,045
Coal properties and oil and natural gas properties (1)	1 - 15 Years	280,375			278,088
Construction work in process		10,798			5,943
Total		694,027			683,669
Less accumulated depreciation, depletion and amortization		(234,990		)	(219,709		)
Net		$	459,037		$	463,960

(1) Oil and natural gas properties as of June 30, 2013 and December 31, 2012 were $42,674 and $37,720, respectively.

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 and six months ended June 30, 2013 and 2012 were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	7,901	$	7,700	$	16,037	$	16,464
Depletion expense for coal properties and oil and natural gas properties	2,012		1,375		3,391		2,921
Amortization expense for mine development costs	617		512		1,287		1,124
Amortization expense for intangible assets	20		20		41		41
Amortization expense for asset retirement costs	29		148		34		297
Total depreciation, depletion and amortization	$	10,579	$	9,755	$	20,790	$	20,847

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Sale of Mining Assets

On February 29, 2012, the Partnership sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.6 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, the Partnership recorded a gain of approximately $0.9 million, which was higher than the sales amount due to the extinguishment of the liabilities. This gain is included on the (Gain)/loss on sale/disposal of assets—net line of the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

Sale of Triad Operations

In August 2012, the Partnership sold the operations and tangible assets of its roof bolt manufacturing company, Triad Roof Support Systems, LLC (“Triad”), to a third party for $0.5 million of cash consideration. As part of the sale, the Partnership retained the rights to certain intellectual property and entered into an exclusive license and option to purchase agreement for this intellectual property with the same third party for potential additional cash consideration. The Partnership has not recorded any portion of this additional consideration since this amount is contingent upon the third party determining the viability of the related intellectual property to their specifications, which has since expired. In connection with the purchase of Triad in 2009, the Partnership recorded approximately $0.2 million of goodwill. Since the Partnership disposed of the entire operations and fixed assets of the Triad reporting unit, the goodwill was included in the carrying amount of the Triad reporting unit to determine the $0.2 million gain that was recorded on the sale of this reporting unit.

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.

The Partnership’s goodwill balance was reduced to zero as a result of the disposal of the Partnership’s Triad operations that were sold during the third quarter of 2012, as described in Note 5.

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Intangible assets as of June 30, 2013 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	186	$	542
Developed Technology	78		20		58
Trade Name	184		19		165
Customer List	470		48		422
Total	$	1,460	$	273	$	1,187

Intangible assets as of December 31, 2012 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	164	$	564
Developed Technology	78		18		60
Trade Name	184		14		170
Customer List	470		36		434
Total	$	1,460	$	232	$	1,228

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 and six months ended June 30, 2013 and 2012 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 June 30, 2013:

			Developed				Customer
	Patent		Technology		Trade Name		List		Total
	(in thousands)
2013 (from Jul 1 to Dec 31)	$	21	$	2	$	5	$	12	$	40
2014	43		5		9		23		80
2015	43		5		9		23		80
2016	43		5		9		23		80
2017	43		5		9		23		80

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7. OTHER NON-CURRENT ASSETS

Other non-current assets as of June 30, 2013 and December 31, 2012 consisted of the following:

	June 30,		December 31,
	2013		2012
	(in thousands)
Deposits and other	$	642	$	1,135
Debt issuance costs—net	4,220		3,851
Non-current receivable	3,829		3,829
Deferred expenses	294		16
Total	$	8,985	$	8,831

Debt issuance costs were approximately $9.0 million and $8.0 million as of June 30, 2013 and December 31, 2012, respectively. Accumulated amortization of debt issuance costs were approximately $4.8 million and approximately $4.2 million as of June 30, 2013 and December 31, 2012, respectively.

The non-current receivable balance of $3.8 million as of June 30, 2013 and December 31, 2012 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 $3.8 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 June 30, 2013 and December 31, 2012 consisted of the following:

	June 30,		December 31,
	2013		2012
	(in thousands)
Payroll, bonus and vacation expense	$	3,320	$	4,086
Non income taxes	3,409		3,318
Royalty expenses	1,873		2,536
Accrued interest	682		671
Health claims	3,032		1,479
Workers’ compensation & pneumoconiosis	1,784		1,784
Deferred revenues	3,512		2,788
Accrued insured litigation claims	233		2,783
Other	1,919		2,733
Total	$	19,764	$	22,178

The $0.2 million and $2.8 million accrued for insured litigation claims as of June 30, 2013 and December 31, 2012, respectively, consists of probable and estimable litigation claims that are the primary obligation of the Partnership. This amount 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 June 30, 2013 and December 31, 2012 consisted of the following:

	June 30,			December 31,
	2013			2012
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$	150,840		$	157,250
Note payable to H&L Construction Co., Inc.	1,185			1,560
Other notes payable	3,349			4,739
Total	155,374			163,549
Less current portion	(1,041		)	(2,350		)
Long-term debt	$	154,333		$	161,199

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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 is $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 is available for letters of credit. 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 June 30, 2013. The amended and restated senior secured credit facility expires in July 2016.

As part of executing the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $2.8 million to the lenders in July 2011, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position.

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 increases 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 steps 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. 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.

At June 30, 2013, the Operating Company had borrowed $150.0 million at a variable interest rate of LIBOR plus 3.00% (3.20% at June 30, 2013) and an additional $0.8 million at a variable interest rate of PRIME plus 2.00% (5.25% at June 30, 2013). In addition, the Operating Company had outstanding letters of credit of approximately $22.1 million at a fixed interest rate of 2.75% at June 30, 2013. Based upon a maximum borrowing capacity of 3.75 times a trailing

15

twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $115.3 million of the borrowing availability at June 30, 2013.

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 $11.2 million and approximately $11.3 million at June 30, 2013 and December 31, 2012, respectively.

10. ASSET RETIREMENT OBLIGATIONS

The changes in asset retirement obligations for the six months ended June 30, 2013 and the year ended December 31, 2012 are as follows:

	Six months ended June 30, 2013			Year ended December 31, 2012
	(in thousands)
Balance at beginning of period (including current portion)	$	33,003		$	34,113
Accretion expense	1,178			1,896
Adjustment resulting from addition of property	—			72
Adjustment resulting from disposal of property	—			(968		)
Adjustments to the liability from annual recosting and other	—			(201		)
Liabilities settled	(468		)	(1,909		)
Balance at end of period	33,713			33,003
Current portion of asset retirement obligation	1,818			2,255
Long-term portion of asset retirement obligation	$	31,895		$	30,748

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 and six months ended June 30, 2013 and 2012 are as follows:

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
	(in thousands)
Service costs	$	96		$	103		$	192		$	206
Interest cost	46			63			93			126
Amortization of (gain)	(36		)	(74		)	(72		)	(148		)
Total	$	106		$	92		$	213		$	184

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For the three and six months ended June 30, 2013 and 2012, the amortization of actuarial gain included in the table above is 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 and six months ended June 30, 2013 and 2012 was as follows:

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(in thousands)
401(k) plan expense	$	556	$	559	$	1,136	$	1,163

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.

As of June 30, 2013, the General Partner granted phantom units to certain employees and restricted units and unit awards to its directors. A portion of these grants were made in connection with the IPO completed during October 2010, as well as annual restricted unit awards to directors and phantom unit awards with tandem distribution equivalent rights granted in the first quarters of 2012 and 2013 to certain employees in connection with the prior year’s performance. A total of 30,818 phantom units were granted in the first quarter of 2013 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 similar to the phantom units awarded in connection with the Partnership’s IPO. The total fair value of the awards granted in the first quarter of 2013 was approximately $0.4 million at the grant date and the fair value of these awards was approximately $0.4 million as of June 30, 2013. 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 and six months ended June 30, 2013 related to these awards was immaterial.

With the vesting of the first portion of the employees’ IPO awards in early April 2011, the Compensation Committee of the board of directors of the General Partner elected to pay some of the awards in cash or a combination of cash and common units. This election was a change in policy since management had previously planned to settle all employee awards with units upon vesting as per the grant agreements. This policy change resulted in a modification of all employee awards from equity to liability classification as of March 31, 2011 and all new

17

awards granted thereafter. For the three and six months ended June 30, 2013 and 2012, the Partnership did not record any incremental compensation expense due to the modification of the employees’ IPO awards since the market price of the Partnership’s common units was below the IPO grant price.

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of June 30, 2013, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of approximately 1.8 million, 2.5 million, 1.6 million, 1.1 million and 1.1 million tons of coal to 18 customers in 2013, 8 customers in 2014, 4 customers in 2015, 2 customers in 2016, and 2 customers in 2017, respectively. 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 June 30, 2013, the Partnership had approximately 0.5 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2013 for approximately $1.6 million.

Purchased Coal Expenses—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts. In addition, the Partnership incurs expense from time to time related to coal purchased on the over-the-counter market (“OTC”). Purchased coal expense from coal purchase contracts and expense from OTC purchases for the three and six months ended June 30, 2013 and 2012 were as follows:

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(in thousands)
Purchased coal expense	$	905	$	5,049	$	1,877	$	10,162
OTC expense	$	666	$	—	$	666	$	—

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the three and six months ended June 30, 2013 and 2012 was as follows:

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(in thousands)
Lease expense	$	807	$	568	$	1,673	$	1,263
Royalty expense	$	3,143	$	2,801	$	6,051	$	7,087

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

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operations of the Rhino Eastern joint venture. During the six months ended June 30, 2013, the Partnership made capital contributions of approximately $0.4 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 $0.4 million during the six months ended June 30, 2013, each based upon its proportionate ownership interest.

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 June 30, 2013 and 2012:

Three months ended June 30, 2013	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	118	$	3,199	$	2,580
Denominator:
Weighted average units used to compute basic EPU	n/a		15,371		12,397
Effect of dilutive securities — LTIP awards	n/a		8		—
Weighted average units used to compute diluted EPU	n/a		15,379		12,397
Net income per limited partner unit, basic	n/a		$	0.21	$	0.21
Net income per limited partner unit, diluted	n/a		$	0.21	$	0.21

Six months ended June 30, 2013	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	114	$	3,102	$	2,504
Denominator:
Weighted average units used to compute basic EPU	n/a		15,358		12,397
Effect of dilutive securities — LTIP awards	n/a		5		—
Weighted average units used to compute diluted EPU	n/a		15,363		12,397
Net income per limited partner unit, basic	n/a		$	0.20	$	0.20
Net income per limited partner unit, diluted	n/a		$	0.20	$	0.20

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Three months ended June 30, 2012	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	260	$	7,041	$	5,695
Denominator:
Weighted average units used to compute basic EPU	n/a		15,329		12,397
Effect of dilutive securities — LTIP awards	n/a		2		—
Weighted average units used to compute diluted EPU	n/a		15,331		12,397
Net income per limited partner unit, basic	n/a		$	0.46	$	0.46
Net income per limited partner unit, diluted	n/a		$	0.46	$	0.46

Six months ended June 30, 2012	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	439	$	11,900	$	9,631
Denominator:
Weighted average units used to compute basic EPU	n/a		15,317		12,397
Effect of dilutive securities — LTIP awards	n/a		8		—
Weighted average units used to compute diluted EPU	n/a		15,325		12,397
Net income per limited partner unit, basic	n/a		$	0.78	$	0.78
Net income per limited partner unit, diluted	n/a		$	0.78	$	0.78

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 and six months ended June 30, 2013, approximately 13,000 LTIP granted phantom units were anti-dilutive. For the three months ended June 30, 2012, approximately 80,000 LTIP granted phantom units were anti-dilutive. There were no anti-dilutive units for the six months ended June 30, 2012.

15. MAJOR CUSTOMERS

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

	June 30,		Six months		Six months
	2013		ended		ended
	Receivable		June 30,		June 30,
	Balance		2013 Sales		2012 Sales
	(in thousands)
NRG Energy, Inc. (fka GenOn Energy, Inc.)	$	2,862	$	22,948	$	19,365
Indiana Harbor Coke Company, L.P	n/a		n/a		19,657
PPL Corporation	n/a		n/a		21,082
American Electric Power Company, Inc.	2,501		17,972		n/a

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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 June 30, 2013. 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 six months ended June 30, 2013 excludes approximately $3.9 million of property additions, which are recorded in accounts payable, and approximately $0.3 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 six months ended June 30, 2012 excludes approximately $3.2 million of property additions, which are recorded in accounts payable,  and approximately $0.3 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 six months ended June 30, 2012 also excludes $2.0 million related to the amount accrued at June 30, 2012 for the acquisition of the western Kentucky assets discussed in Note 3.

18. SEGMENT INFORMATION

The Partnership produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah and also has one underground mine located in Colorado that was temporarily idled. 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 and six months ended June 30, 2013, 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 underground mines in Colorado and Utah) and Eastern Met (comprised solely of the joint venture with Patriot). Additionally, the Partnership has an Other category that is comprised of the Partnership’s ancillary businesses and oil and natural gas investments. The Partnership has not provided disclosure of total expenditures by segment for long-lived assets, as the Partnership does not maintain discrete financial information concerning segment expenditures for long lived assets, and accordingly such information is not provided to the Partnership’s chief operating decision maker. The information provided in the following tables represents the primary measures used to assess segment performance by the Partnership’s chief operating decision maker.

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

21

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 June 30, 2013 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	$	34,164		$	20,294	$	9,423		$	7,649		$	(7,649	)	$	—		$	2,947		$	66,828
DD&A	6,156			1,990		1,318			481			(481		)	—			1,115			10,579
Interest expense	954			192		158			—			—			—			621			1,925
Net Income (loss)	$	(5,138	)	$	13,787	$	(266	)	$	(4,105	)	$	2,012		$	(2,093	)	$	(393	)	$	5,897

Reportable segment results of operations for the three months ended June 30, 2012 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	$	42,259		$	35,985	$	10,127	$	17,432	$	(17,432	)	$	—	$	1,627		$	89,998
DD&A	6,097			2,052		1,067		554		(554		)	—		539			9,755
Interest expense	1,118			208		182		58		(58		)	—		454			1,962
Net Income (loss)	$	(1,485	)	$	12,102	$	1,474	$	4,561	$	(2,235	)	$	2,326	$	(1,421	)	$	12,996

Reportable segment results of operations for the six months ended June 30, 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	$	76,105		$	42,161	$	19,021		$	13,818		$	(13,818	)	$	—		$	4,286		$	141,573
DD&A	12,422			4,042		2,668			957			(957		)	—			1,658			20,790
Interest expense	1,927			382		317			—			—			—			1,153			3,779
Net Income (loss)	$	(7,342	)	$	18,410	$	(369	)	$	(6,502	)	$	3,186		$	(3,316	)	$	(1,663	)	$	5,720

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Reportable segment results of operations for the six months ended June 30, 2012 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	$	84,179	$	64,359	$	20,146	$	32,837	$	(32,837	)	$	—	$	3,197		$	171,881
DD&A	13,636		3,965		2,107		1,122		(1,122		)	—		1,139			20,847
Interest expense	2,128		399		346		139		(139		)	—		911			3,784
Net Income (loss)	$	955	$	17,077	$	2,859	$	8,754	$	(4,363	)	$	4,391	$	(3,312	)	$	21,970

Additional summarized financial information for the Rhino Eastern equity method investment for the periods ended June 30, 2013 and 2012:

	Three months ended June 30,					Six months ended June 30,
	2013			2012		2013			2012
	(in thousands)
Total costs and expenses	$	11,754		$	12,813	$	20,320		$	23,944
(Loss)/income from operations	(4,105		)	4,619		(6,502		)	8,893

19.  SUBSEQUENT EVENTS

On July 22, 2013, 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 August 14, 2013 to all common unit holders of record as of the close of business on August 1, 2013. 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, 2012 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2012 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, 2012.

Overview

We are a diversified energy limited partnership formed in Delaware that is focused on coal, oil and natural gas and related energy infrastructure. 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 Utica Shale and Cana Woodford regions. We receive our proportionate share (5%) of revenue from any hydrocarbons produced and sold by the operator on our Utica Shale acreage and 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. In December 2012, we also invested in a joint venture that will provide 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 Utica Shale regions of eastern Ohio and the Cana Woodford region in western Oklahoma. As of December 31, 2012, we controlled an estimated 463.7

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million tons of proven and probable coal reserves, consisting of an estimated 442.8 million tons of steam coal and an estimated 20.9 million tons of metallurgical coal. In addition, as of December 31, 2012, we controlled an estimated 417.4 million tons of non-reserve coal deposits. As of December 31, 2012, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 43.1 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 17.9 million tons of non-reserve coal deposits. As of June 30, 2013, 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 two underground mines in West Virginia. In addition, we have one underground mine in Colorado that has been temporarily idled. 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 June 30, 2013 consisted of a 5% net interest in a portfolio of oil and natural gas leases in the Utica Shale that encompassed 137,000 total gross acres, or 6,850 net acres, as well as 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 Utica Shale and Cana Woodford regions. We believe that such assets will allow us to grow our cash available for distribution and enhance stability of our cash flow.

For the three and six months ended June 30, 2013, we generated revenues of approximately $66.8 million and approximately $141.6 million, respectively, and net income of approximately $5.9 million and approximately $5.7 million, respectively. Excluding results from the Rhino Eastern joint venture, for the three and six months ended June 30, 2013, we produced approximately 1.0 million tons and approximately 1.9 million tons of coal, respectively, and sold approximately 0.9 million tons and approximately 1.9 million tons of coal, respectively. For the three and six months ended June 30, 2013, approximately 88% of tons sold 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 and six months ended June 30, 2013.

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Recent Developments

Credit Facility

In April 2013, we entered into an 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. The amendment provided for an increase in the maximum allowed investments in coal-related entities outside of our current organization (i.e. joint ventures) under the amended and restated senior secured credit facility from $25 million to $40 million. The amendment also increased 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 steps 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.

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. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the Rhino Eastern joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

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 could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was initially recorded in in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. As of June 30, 2013, we have paid $1.6 million of the $2.0 million. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount are currently not probable.

The coal leases and property are estimated to contain approximately 32 million tons of proven and probable coal reserves that are contiguous to the Green River. The property is fully permitted and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could allow for exports to non-U.S. customers. Initial development of this property has commenced and initial production and sales from our new mine on this property, referred to as the Riveredge mine, is expected to occur in mid-2014.

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Oil and Gas Investments

We and an affiliate of Wexford Capital have participated with Gulfport Energy Corporation (“Gulfport”), a publicly traded company, to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale. As of June 30, 2013, we have completed the acquisition of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $25.2 million. Gulfport is actively drilling in the Utica Shale acreage and Gulfport has released results from test wells that had been drilled on our acreage, which we believe are very positive due to the amount of hydrocarbon liquids contained in these wells. Our 2013 projected expansion capital expenditures include an estimated $15 million to $20 million for our oil and natural gas investments, primarily for drilling costs related to our Utica Shale acreage.

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 June 30, 2013, our Utica Shale position consisted of our 5% net interest in a total portfolio of approximately 137,000 gross acres, or approximately 6,850 net acres. In addition, per the joint operating agreement among us, Gulfport and an affiliate of Wexford Capital, we have funded our proportionate share of drilling costs to Gulfport for wells being drilled on our acreage. As of June 30, 2013 and December 31, 2012, we have funded approximately $9.3 million and $5.3 million, respectively, of drilling costs that are included in Coal properties and oil and natural gas properties in our unaudited condensed consolidated statements of financial position. Two of the wells on our acreage began production in late 2012 and eleven additional wells began production during the six months ended June 30, 2013. We recognized approximately $1.2 million and approximately $1.5 million of revenue, respectively, on our Utica Shale investment during the three and six months ended June 30, 2013.

In March 2012, we completed an out-lease agreement with a third party for approximately 1,232 acres we own in the Utica Shale region of Harrison County Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the lessee to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay us the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232 acres. In addition, the lease agreement stipulated that the third party would pay us a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

In April 2013, we completed an agreement with a third party to sell the 20% royalty interest for approximately $10.5 million on the 1,232 acres in the Utica Shale. The sale of the royalty interest resulted in a gain of approximately $10.5 million since we had no cost basis associated with the royalty interest.

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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. We began to receive royalty revenues from these mineral rights in 2012.

Other Investments

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. As Muskie is still undergoing operational development, we recorded our proportionate portion of the operating profit/(loss) for the three and six months ended June 30, 2013 of approximately $17,000 and ($132,000), respectively. During the six months ended June 30, 2013, we contributed additional capital based upon our ownership share to the Muskie joint venture in the amount of $0.4 million.

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 and six months ended June 30, 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 first six months of 2013 and is completing the construction of one additional drill pad as of June 30, 2013, in addition to the three drill pads completed during 2012.

Sale of Triad Operations

In August 2012, we sold the operations and tangible assets of our roof bolt manufacturing company, Triad, to a third party for $0.5 million of cash consideration. As part of the sale, we retained the rights to certain intellectual property and entered into an exclusive license and option to purchase agreement for this intellectual property with the same third party for potential additional cash consideration. We have not recorded any portion of this additional consideration since this amount is contingent upon the third party determining the viability of the related intellectual property to their specifications, which has since expired.

Sale of Mining Assets

In February 2012, the Partnership sold certain non-core mining assets located in Pike County, Kentucky to a third party for approximately $0.6 million. The transaction also extinguished certain liabilities related to the assets sold. In relation to the sale of these assets and extinguishment of liabilities, we recorded a gain of approximately $0.9 million, which was higher than the sales amount due to the extinguishment of the liabilities.

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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 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 June 30, 2013, we had commitments under sales contracts to deliver annually scheduled base quantities of approximately 1.8 million, 2.5 million, 1.6 million, 1.1 million and 1.1 million tons of coal to 18 customers in 2013, 8 customers in 2014, 4 customers in 2015, 2 customers in 2016, and 2 customers in 2017, respectively. 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 includes our ancillary businesses and oil and natural gas investments. Our Central Appalachia segment consists of four mining complexes: Tug River, Rob Fork and Deane, which as of June 30, 2013, 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 June 30, 2013. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of June 30, 2013. Our Rhino Western segment includes our two underground mines in the Western Bituminous region that consist of our McClane Canyon mine in Colorado that has been temporarily idled since the end of 2010, and remained idle at June 30, 2013, and 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 June 30, 2013, this complex was comprised of two underground mines and a preparation plant and loadout facility (owned by our Rhino Eastern joint venture partner). Our Other category includes our ancillary businesses that consist of our limestone operations and various businesses that provide support services such as reclamation, maintenance and transportation, the cost of which is reflected in our cost of operations, as well as our oil and natural gas investments.

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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 and six months ended June 30, 2013 and 2012:

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
	(in millions)
Statement of Operations Data:
Total revenues	$	66.8		$	90.0		$	141.6		$	171.9
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	51.7			60.2			106.5			117.3
Freight and handling costs	0.3			1.8			0.6			3.1
Depreciation, depletion and amortization	10.6			9.8			20.8			20.8
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	4.9			5.5			10.5			10.4
(Gain)/loss on sale/disposal of assets-net	(10.6		)	0.1			(9.7		)	(1.0		)
Income from operations	9.9			12.6			12.9			21.3
Interest and other income (expense):
Interest expense	(1.9		)	(1.9		)	(3.8		)	(3.8		)
Interest income	—			—			—			0.1
Equity in net income (loss) of unconsolidated affiliates	(2.1		)	2.3			(3.4		)	4.4
Total interest and other income (expense)	(4.0		)	0.4			(7.2		)	0.7
Net income	$	5.9		$	13.0		$	5.7		$	22.0
Other Financial Data
Adjusted EBITDA	$	18.6		$	25.0		$	31.7		$	47.2

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Summary.  For the three months ended June 30, 2013, our total revenues decreased to $66.8 million from $90.0 million for the three months ended June 30, 2012. We sold 0.9 million tons of coal for the three months ended June 30, 2013, which is an 18.2% decrease compared to the tons of coal sold for the three months ended June 30, 2012. 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 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.

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Net income and Adjusted EBITDA decreased for the three months ended June 30, 2013 from the three months ended June 30, 2012. We generated net income of approximately $5.9 million for the three months ended June 30, 2013 compared to net income of approximately $13.0 million for the three months ended June 30, 2012 as reductions in costs were offset by lower revenues, including lower royalty revenue from our coal leasing business. For the three months ended June 30, 2013, our net income was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property. Net income for the three months ended June 30, 2013 was negatively impacted period to period due to a $2.1 million net loss from our Rhino Eastern joint venture compared to net income of $2.3 million for the three months ended June 30, 2012, 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. In addition, our net income for the three months ended June 30, 2012 was positively impacted by approximately $6.9 million due to lease bonus payments that we received on our Utica Shale property.

Adjusted EBITDA decreased to $18.6 million for the three months ended June 30, 2013 from $25.0 million for the three months ended June 30, 2012. Adjusted EBITDA decreased period to period primarily due to a decrease in net income as described above.

Tons Sold.  The following table presents tons of coal sold by reportable segment for the three months ended June 30, 2013 and 2012:

	Three months	Three months	Increase/
	ended	ended	(Decrease)
Segment	June 30, 2013	June 30, 2012	Tons		% *
	(in thousands, except %)
Central Appalachia	363.3	388.0	(24.7	)	(6.4	)%
Northern Appalachia	314.4	475.7	(161.3	)	(33.9	)%
Rhino Western	234.1	251.2	(17.1	)	(6.8	)%
Total *†	911.8	1,114.9	(203.1	)	(18.2	)%

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

†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 0.9 million tons of coal for the three months ended June 30, 2013 compared to approximately 1.1 million tons for the three months ended June 30, 2012. The decrease in total tons sold year-to-year was primarily due to lower sales from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened

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year-to-year. Tons of coal sold in our Central Appalachia segment decreased by approximately 6.4% to approximately 0.4 million tons for the three months ended June 30, 2013 compared to the three months ended June 30, 2012, primarily due to a decrease in steam coal tons sold in the three months ended June 30, 2013 compared to 2012. For our Northern Appalachia segment, tons of coal sold decreased by approximately 0.2 million tons, or 33.9%, to approximately 0.3 million tons for the three months ended June 30, 2013 from approximately 0.5 million tons for the three months ended June 30, 2012, primarily due to the decrease in sales from our Sands Hill complex mentioned earlier. Coal sales from our Rhino Western segment decreased slightly for the three months ended June 30, 2013 compared to 2012 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 June 30, 2013 and 2012:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2013		June 30, 2012		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	29.2	$	36.3	$	(7.1	)	(19.4	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	5.0		6.0		(1.0		)	(17.4	)%
Total revenues	$	34.2	$	42.3	$	(8.1	)	(19.2	)%
Coal revenues per ton*	$	80.42	$	93.49	$	(13.07	)	(14.0	)%
Northern Appalachia
Coal revenues	$	18.4	$	25.8	$	(7.4	)	(28.9	)%
Freight and handling revenues	0.6		1.8		(1.2		)	(64.3	)%
Other revenues	1.3		8.4		(7.1		)	(84.2	)%
Total revenues	$	20.3	$	36.0	$	(15.7	)	(43.6	)%
Coal revenues per ton*	$	58.28	$	54.20	$	4.08		7.5	%
Rhino Western
Coal revenues	$	9.4	$	10.1	$	(0.7	)	(7.0	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	9.4	$	10.1	$	(0.7	)	(6.9	)%
Coal revenues per ton*	$	40.24	$	40.29	$	(0.05	)	(0.1	)%
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	2.9		1.6		1.3			81.1	%
Total revenues	$	2.9	$	1.6	$	1.3		81.1	%
Coal revenues per ton*	n/a		n/a		n/a			n/a
Total
Coal revenues	$	57.0	$	72.2	$	(15.2	)	(21.1	)%
Freight and handling revenues	0.6		1.8		(1.2		)	(64.3	)%
Other revenues	9.2		16.0		(6.8		)	(42.4	)%
Total revenues	$	66.8	$	90.0	$	(23.2	)	(25.7	)%
Coal revenues per ton*	$	62.47	$	64.74	$	(2.27	)	(3.5	)%

*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 June 30, 2013 decreased by approximately $15.2 million, or 21.1%, to approximately $57.0 million from approximately $72.2 million for the three months ended June 30, 2012. The decrease in coal revenues was primarily due to fewer tons sold from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened year-to-year, as well as fewer steam coal tons sold and lower met coal prices in Central Appalachia. Coal revenues per ton were $62.47 for the three months ended June 30, 2013, a decrease of $2.27, or 3.5%, from $64.74 per ton for the three months ended June 30, 2012. 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 June 30, 2013 compared to 2012.

For our Central Appalachia segment, coal revenues decreased by approximately $7.1 million, or 19.4%, to approximately $29.2 million for the three months ended June 30, 2013 from approximately $36.3 million for the three months ended June 30, 2012, primarily due to fewer steam 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 $13.07, or 14.0%, to $80.42 per ton for the three months ended June 30, 2013 as compared to $93.49 for the three months ended June 30, 2012, primarily due to lower prices for met coal sold. Other revenues decreased for our Central Appalachia segment primarily due to lower coal royalty revenue from our coal leasing business as our lessees mined fewer tons and had lower selling prices for their coal for the three months ended June 30, 2013 as compared to 2012.

For our Northern Appalachia segment, coal revenues were approximately $18.4 million for the three months ended June 30, 2013, a decrease of approximately $7.4 million, or 28.9%, from approximately $25.8 million for the three months ended June 30, 2012. This decrease was primarily due to fewer tons sold from our Sands Hill complex in Northern Appalachia as mentioned earlier. Coal revenues per ton for our Northern Appalachia segment increased by $4.08, or 7.5%, to $58.28 per ton for the three months ended June 30, 2013 as compared to $54.20 per ton for the three months ended June 30, 2012. This increase was primarily due to fewer lower priced tons being sold from our Sands Hill complex. Other revenues decreased for our Northern Appalachia segment primarily due to a $6.9 million lease bonus received in the second quarter of 2012 as we leased our owned Utica Shale acreage to a third party in 2012 that is not present in the comparable period for 2013.

For our Rhino Western segment, coal revenues decreased by approximately $0.7 million, or 7.0%, to approximately $9.4 million for the three months ended June 30, 2013 from approximately $10.1 million for the three months ended June 30, 2012. Coal revenues per ton for our Rhino Western segment were $40.24 for the three months ended June 30, 2013, a decrease of $0.05, or 0.1%, from $40.29 for the three months ended June 30, 2012. The decrease in coal revenues per ton were due to lower contracted prices for coal produced at our Castle Valley mine.

Other revenues for our Other category increased by approximately $1.3 million for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012. The increase in other revenues was primarily due to $1.2 million of oil and gas revenue from our Utica Shale investment that was not present in the 2012 comparable period.

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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 June 30, 2013		Three months ended June 30, 2012		Increase (Decrease) %*
Met coal tons sold	129.8		109.0		19.1	%
Steam coal tons sold	233.5		279.0		(16.3	)%
Total tons sold †	363.3		388.0		(6.4	)%
Met coal revenue	$	11,537	$	14,651	(21.3	)%
Steam coal revenue	$	17,682	$	21,621	(18.2	)%
Total coal revenue †	$	29,219	$	36,272	(19.4	)%
Met coal revenues per ton	$	88.87	$	134.36	(33.9	)%
Steam coal revenues per ton	$	75.72	$	77.52	(2.3	)%
Total coal revenues per ton †	$	80.42	$	93.49	(14.0	)%
Met coal tons produced	173.0		99.0		74.7	%
Steam coal tons produced	262.9		232.4		13.1	%
Total tons produced †	435.9		331.4		31.5	%

† 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 June 30, 2013 and 2012:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2013		June 30, 2012		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	25.6	$	29.5	$	(3.9	)	(13.2	)%
Freight and handling costs	0.1		0.3		(0.2		)	(44.6	)%
Depreciation, depletion and amortization	6.2		6.1		0.1			1.0	%
Selling, general and administrative	4.7		5.2		(0.5		)	(8.4	)%
Cost of operations per ton*	$	70.56	$	76.10	$	(5.54	)	(7.3	)%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	13.9	$	19.3	$	(5.4	)	(28.0	)%
Freight and handling costs	0.2		1.5		(1.3		)	(88.7	)%
Depreciation, depletion and amortization	2.0		2.1		(0.1		)	(3.0	)%
Selling, general and administrative	—		0.1		(0.1		)	(35.8	)%
Cost of operations per ton*	$	44.25	$	40.63	$	3.62		8.9	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	7.7	$	6.9	$	0.8		11.3	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.3		1.1		0.2			23.5	%
Selling, general and administrative	—		—		—			(9.5	)%
Cost of operations per ton*	$	32.85	$	27.49	$	5.36		19.5	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	4.5	$	4.5	$	—		(0.6	)%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.1		0.5		0.6			107.0	%
Selling, general and administrative	0.2		0.2		—			(8.1	)%
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)	$	51.7	$	60.2	$	(8.5	)	(14.2	)%
Freight and handling costs	0.3		1.8		(1.5		)	(82.3	)%
Depreciation, depletion and amortization	10.6		9.8		0.8			8.4	%
Selling, general and administrative	4.9		5.5		(0.6		)	(8.8	)%
Cost of operations per ton*	$	56.65	$	54.00	$	2.65		4.9	%

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

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

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Cost of Operations.  Total cost of operations was $51.7 million for the three months ended June 30, 2013 as compared to $60.2 million for the three months ended June 30, 2012. Our cost of operations per ton was $56.65 for the three months ended June 30, 2013, an increase of $2.65, or 4.9%, from the three months ended June 30, 2012. Total cost of operations decreased primarily due to lower production at our Sands Hill complex in Northern 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 with reducing production volumes at Sands Hill along with higher roof support costs at our Hopedale operation.

Our cost of operations for the Central Appalachia segment decreased by $3.9 million, or 13.2%, to $25.6 million for the three months ended June 30, 2013 from $29.5 million for the three months ended June 30, 2012. The decrease in total cost of operations was due to decreased costs from purchased coal for the three months ended June 30, 2013 compared to 2012. Our cost of operations per ton decreased to $70.56 per ton for the three months ended June 30, 2013 from $76.10 per ton for three months ended June 30, 2012. The decrease in cost of operations per ton was primarily due to the fact that we idled a majority of the Central Appalachia operations in June of 2012 in order to reduce higher than normal inventory levels, which resulted in a higher cost per ton figure for that period.

In our Northern Appalachia segment, our cost of operations decreased by $5.4 million, or 28.0%, to $13.9 million for the three months ended June 30, 2013 from $19.3 million for the three months ended June 30, 2012. The decrease in total cost of operations was primarily due to lower production at our Sands Hill complex in Northern Appalachia, which was in response to weak market conditions for coal from this complex. Our cost of operations per ton was $44.25 for the three months ended June 30, 2013, an increase of $3.62, or 8.9%, compared to $40.63 for the three months ended June 30, 2012. The increase in cost of operations per ton was primarily due to reducing production volumes at Sands Hill along with higher roof support costs at our Hopedale operation.

Our cost of operations for the Rhino Western segment increased by $0.8 million, or 11.3%, to $7.7 million for the three months ended June 30, 2013 from $6.9 million for the three months ended June 30, 2012. Our cost of operations per ton increased to $32.85 per ton for the three months ended June 30, 2013 from $27.49 per ton for three months ended June 30, 2012. The increases in cost of operations and cost of operations per ton were primarily due to the sequence of mining at our Castle Valley mine where we performed more higher cost advance mining during the three months ended June 30, 2013 compared to more lower cost retreat mining that was performed in the three months ended June 30, 2012.

Cost of operations in our Other category was flat at $4.5 million for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012.

Freight and Handling.  Total freight and handling cost for the three months ended June 30, 2013 decreased by $1.5 million, or 82.3%, to $0.3 million from $1.8 million for the three

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months ended June 30, 2012. This decrease was primarily due to the decrease in tons of coal sold for the three months ended June 30, 2013 compared to 2012 from our Sands Hill complex, which requires transportation by truck to customers’ locations.

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization, or DD&A, expense for the three months ended June 30, 2013 was $10.6 million as compared to $9.8 million for the three months ended June 30, 2012.

For the three months ended June 30, 2013, our depreciation cost was $7.9 million as compared to $7.7 million for the three months ended June 30, 2012. This increase is primarily due to an increase in machinery and equipment depreciation from our Castle Valley operations.

For the three months ended June 30, 2013, our depletion cost was $2.0 million compared to $1.4 million for the three months ended June 30, 2012. This increase is primarily attributable to our proportionate share of the Utica Shale oil and gas depletion that was not present in the prior period.

For the three months ended June 30, 2013 and 2012, our amortization cost was flat at $0.7 million.

Selling, General and Administrative.  Selling, general and administrative, or SG&A, expense for the three months ended June 30, 2013 was $4.9 million as compared to $5.5 million for the three months ended June 30, 2012. This decrease in SG&A expense was primarily due to a decrease in expenditures for legal and accounting fees and other professional services.

Interest Expense.  Interest expense for the three months ended June 30, 2013 and 2012 was flat at $1.9 million as a reduction in the balance due under our credit facility for the three months ended June 30, 2013 compared to the same period in 2012 was offset by a slightly higher borrowing rate in the 2013 period compared to 2012.

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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 June 30, 2013			Three months ended June 30, 2012		Increase (Decrease) %*
Eastern Met 100% Basis
Coal revenues	$	7,633		$	17,420	(56.2	)%
Total revenues	$	7,649		$	17,432	(56.1	)%
Coal revenues per ton*	$	106.71		$	188.34	(43.3	)%
Cost of operations	$	10,509		$	11,098	(5.3	)%
Cost of operations per ton*	$	146.92		$	119.99	22.4	%
Depreciation, depletion and amortization	$	481		$	554	(13.1	)%
Interest expense	$	0		$	58	n/a
Net income (loss)	$	(4,105	)	$	4,561	(190.0	)%
Partnership’s portion of net income (loss)	$	(2,093	)	$	2,326	(190.0	)%
Tons produced	42.7			98.2		(56.6	)%
Tons sold	71.5			92.5		(22.7	)%

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

The decrease in tons produced and sold for the three months ended June 30, 2013 compared to 2012 was due to weakness in the met coal market, which resulted in a significant decrease in the market price for the quality of met coal that Rhino Eastern produces. The decrease in tons sold resulted in decreased revenue and net income for the three months ended June 30, 2013 compared to the same period in 2012. Net income was also negatively impacted and cost of operations per ton increased for the three months ended June 30, 2013 from an approximate $0.4 million write-down in coal inventory value due to the decrease in the market value of Rhino Eastern’s met coal.

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Net Income (Loss).  The following table presents net income (loss) by reportable segment for the three months ended June 30, 2013 and 2012:

	Three months ended			Three months ended			Increase
Segment	June 30, 2013			June 30, 2012			(Decrease)
	(in millions)
Central Appalachia	$	(5.1	)	$	(1.5	)	$	(3.6	)
Northern Appalachia	13.8			12.1			1.7
Rhino Western	(0.3		)	1.5			(1.8		)
Eastern Met *	(2.1		)	2.3			(4.4		)
Other	(0.4		)	(1.4		)	1.0
Total	$	5.9		$	13.0		$	(7.1	)

*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.

For the three months ended June 30, 2013, total net income decreased to approximately $5.9 million compared to approximately $13.0 million for the three months ended June 30, 2012 as decreases in costs and expenses were offset by decreases in coal revenues, including lower royalty revenue from our coal leasing business, as well as lower results from our Rhino Eastern joint venture. For the three months ended June 30, 2013, our net income was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property. Our net income for the three months ended June 30, 2012 was positively impacted by approximately $6.9 million due to lease bonus payments that we received on our Utica Shale property.

For our Central Appalachia segment, net loss increased to a loss of approximately $5.1 million for the three months ended June 30, 2013, an increase of $3.6 million as compared to the three months ended June 30, 2012, primarily due to ongoing weakness in the met and steam coal markets. Net income in our Northern Appalachia segment increased by $1.7 million to $13.8 million for the three months ended June 30, 2013, from $12.1 million for the three months ended June 30, 2012. This increase was primarily from the $10.5 million received from the sale of our 20% royalty interest on our Utica Shale property in the three months ended June 30, 2013 as compared to approximately $6.9 million of lease bonus payments that we received on our Utica Shale property in the three months ended June 30, 2012. The increase period to period due to the Utica Shale payments received was partially offset from a decrease in tons of coal sold from our Sands Hill complex due to weakness in the steam coal market. Net income in our Rhino Western segment decreased by $1.8 million to a net loss of approximately $0.3 million for the three months ended June 30, 2013, compared to net income of $1.5 million for the three months ended June 30, 2012. This decrease was primarily the result of an increase in cost of operations at our Castle Valley operation. Our Eastern Met segment recorded a net loss of $2.1 million for the three months ended June 30, 2013, a decrease of $4.4 million from net income of $2.3 million for the three months ended June 30, 2012, as weakness in the met coal market caused a decrease in tons sold.  For the Other category, we had a net loss of $0.4 million for the three months ended June 30, 2013, which was an improvement as compared to a net loss of $1.4 million for the three

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months ended June 30, 2012. The improvement was primarily due to positive results from our Utica Shale oil and natural gas investments in the three months ended June 30, 2013.

Adjusted EBITDA.  The following table presents Adjusted EBITDA by reportable segment for the three months ended June 30, 2013 and 2012:

	Three months ended			Three months ended			Increase
Segment	June 30, 2013			June 30, 2012			(Decrease)
	(in millions)
Central Appalachia	$	2.0		$	5.7		$	(3.7	)
Northern Appalachia	16.0			14.4			1.6
Rhino Western	1.2			2.7			(1.5		)
Eastern Met *	(1.9		)	2.6			(4.5		)
Other	1.3			(0.4		)	1.7
Total	$	18.6		$	25.0		$	(6.4	)

*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 for the three months ended June 30, 2013 was $18.6 million, a decrease of $6.4 million from the three months ended June 30, 2012. Adjusted EBITDA decreased primarily as a result of a decrease in net income, as described previously. 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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Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Summary.  For the six months ended June 30, 2013, our total revenues decreased to $141.6 million from $171.9 million for the six months ended June 30, 2012. We sold 1.9 million tons of coal for the six months ended June 30, 2013, which is a 12.2% decrease compared to the tons of coal sold for the six months ended June 30, 2012. This decrease in revenue and tons sold was the result of continued weak demand in the met and steam coal markets that were discussed earlier.

For the six months ended June 30, 2013, we decreased our coal inventories by approximately 18,000 tons as we decreased production.

Net income and Adjusted EBITDA decreased for the six months ended June 30, 2013 from the six months ended June 30, 2012. We generated net income of approximately $5.7 million for the six months ended June 30, 2013 compared to net income of approximately $22.0 million for the six months ended June 30, 2012 as reductions in costs were offset by lower revenues, including lower royalty revenue from our coal leasing business. For the six months ended June 30, 2013, our net income was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property, while net income for this period was negatively impacted by approximately $1.0 million due to the non-cash write-off of a continuous miner that was damaged at one of our Central Appalachia underground mines. Net income for the six months ended June 30, 2013 was also negatively impacted period to period due to a $3.3 million net loss from our Rhino Eastern joint venture compared to net income of $4.4 million for the six months ended June 30, 2012, 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. In addition, our net income for the six months ended June 30, 2012 was positively impacted by approximately $7.4 million from total lease bonus payments that we received on our Utica Shale property during this period.

Adjusted EBITDA decreased to $31.7 million for the six months ended June 30, 2013 from $47.2 million for the six months ended June 30, 2012. Adjusted EBITDA decreased period to period primarily due to a decrease in net income as described above.

Tons Sold.  The following table presents tons of coal sold by reportable segment for the six months ended June 30, 2013 and 2012:

	Six months	Six months	Increase/
	ended	ended	(Decrease)
Segment	June 30, 2013	June 30, 2012	Tons		% *
	(in millions, except %)
Central Appalachia	783.8	765.4	18.4		2.4	%
Northern Appalachia	663.2	923.6	(260.4	)	(28.2	)%
Rhino Western	471.0	494.9	(23.9	)	(4.8	)%
Total *†	1,918.0	2,183.9	(265.9	)	(12.2	)%

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

†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 1.9 million tons of coal for the six months ended June 30, 2013 compared to approximately 2.2 million tons for the six months ended June 30, 2012. The decrease in total tons sold year-to-year was primarily due to lower sales from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened year-to-year. Tons of coal sold in our Central Appalachia segment increased by approximately 2.4% to approximately 0.8 million tons for the six months ended June 30, 2013 compared to the six months ended June 30, 2012, primarily due to an increase in met coal tons sold as met coal sales in the spot market increased in the six months ended June 30, 2013 compared to 2012. For our Northern Appalachia segment, tons of coal sold decreased by approximately 28.2% to approximately 0.7 million tons for the six months ended June 30, 2013 from approximately 0.9 million tons for the six months ended June 30, 2012, primarily due to the decrease in sales from our Sands Hill complex mentioned earlier. Coal sales from our Rhino Western segment decreased slightly for the six months ended June 30, 2013 compared to 2012 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 six months ended June 30, 2013 and 2012:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2013		June 30, 2012		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	66.8	$	71.2	$	(4.4	)	(6.2	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	9.3		13.0		(3.7		)	(28.3	)%
Total revenues	$	76.1	$	84.2	$	(8.1	)	(9.6	)%
Coal revenues per ton*	$	85.19	$	92.99	$	(7.80	)	(8.4	)%
Northern Appalachia
Coal revenues	$	38.6	$	50.5	$	(11.9	)	(23.6	)%
Freight and handling revenues	1.3		3.3		(2.0		)	(61.9	)%
Other revenues	2.3		10.6		(8.3		)	(78.1	)%
Total revenues	$	42.2	$	64.4	$	(22.2	)	(34.5	)%
Coal revenues per ton*	$	58.18	$	54.66	$	3.52		6.5	%
Rhino Western
Coal revenues	$	19.0	$	20.1	$	(1.1	)	(5.5	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	19.0	$	20.1	$	(1.1	)	(5.6	)%
Coal revenues per ton*	$	40.37	$	40.67	$	(0.30	)	(0.7	)%
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	4.3		3.2		1.1			34.1	%
Total revenues	$	4.3	$	3.2	$	1.1		34.1	%
Coal revenues per ton*	n/a		n/a		n/a			n/a
Total
Coal revenues	$	124.4	$	141.8	$	(17.4	)	(12.3	)%
Freight and handling revenues	1.3		3.3		(2.0		)	(61.9	)%
Other revenues	15.9		26.8		(10.9		)	(40.5	)%
Total revenues	$	141.6	$	171.9	$	(30.3	)	(17.6	)%
Coal revenues per ton*	$	64.85	$	64.92	$	(0.07	)	(0.1	)%

*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 six months ended June 30, 2013 decreased by approximately $17.4 million, or 12.3%, to approximately $124.4 million from approximately $141.8 million for the six months ended June 30, 2012. The decrease in coal revenues was primarily due to fewer tons sold from our Sands Hill complex in Northern Appalachia as market conditions for coal from this operation weakened year-to-year. Coal revenues per ton were $64.85 for the six months ended June 30, 2013, a decrease of $0.07, or 0.1%, from $64.92 per ton for the six months ended June 30, 2012. This slight decrease in coal revenues per ton was primarily the result of lower prices for metallurgical coal sold from our Central Appalachia segment, partially offset by fewer lower priced tons being sold from our Sands Hill complex in Northern Appalachia.

For our Central Appalachia segment, coal revenues decreased by approximately $4.4 million, or 6.2%, to approximately $66.8 million for the six months ended June 30, 2013 from approximately $71.2 million for the six months ended June 30, 2012, primarily due to a decrease in steam coal tons sold, partially offset by an increase in met coal tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $7.80, or 8.4%, to $85.19 per ton for the six months ended June 30, 2013 as compared to $92.99 for the six months ended June 30, 2012, primarily due to lower prices for met coal sold. Other revenues decreased for our Central Appalachia segment primarily due to lower coal royalty revenue from our coal leasing business as our lessees mined fewer tons and had lower selling prices for their coal for the six months ended June 30, 2013 as compared to 2012.

For our Northern Appalachia segment, coal revenues were approximately $38.6 million for the six months ended June 30, 2013, a decrease of approximately $11.9 million, or 23.6%, from approximately $50.5 million for the six months ended June 30, 2012. This decrease was primarily due to fewer tons sold from our Sands Hill complex in Northern Appalachia as mentioned earlier. Coal revenues per ton for our Northern Appalachia segment increased by $3.52, or 6.5%, to $58.18 per ton for the six months ended June 30, 2013 as compared to $54.66 per ton for the six months ended June 30, 2012. This increase was primarily due to fewer lower priced tons being sold from our Sands Hill complex. Other revenues decreased for our Northern Appalachia segment primarily due to $7.4 million in lease bonus payments received in the six months ended June 30, 2012 as we leased our owned Utica Shale acreage to a third party in 2012 that is not present in the comparable period for 2013.

For our Rhino Western segment, coal revenues decreased by approximately $1.1 million, or 5.5%, to approximately $19.0 million for the six months ended June 30, 2013 from approximately $20.1 million for the six months ended June 30, 2012, due to slightly fewer tons sold. Coal revenues per ton for our Rhino Western segment were $40.37 for the six months ended June 30, 2013, a decrease of $0.30, or 0.7%, from $40.67 for the six months ended June 30, 2012. The decrease in coal revenues per ton were due to lower contracted prices for coal produced at our Castle Valley mine.

Other revenues for our Other category increased by approximately $1.1 million for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012. The increase in other revenues was primarily due to $1.5 million of oil and gas revenue from our Utica Shale investment that was not present in the 2012 comparable period.

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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 %)	Six months ended June 30, 2013		Six months ended June 30, 2012		Increase (Decrease) %*
Met coal tons sold	311.7		204.2		52.7	%
Steam coal tons sold	472.1		561.2		(15.9	)%
Total tons sold †	783.8		765.4		2.4	%
Met coal revenue	$	30,318	$	28,284	7.2	%
Steam coal revenue	$	36,459	$	42,887	(15.0	)%
Total coal revenue †	$	66,777	$	71,171	(6.2	)%
Met coal revenues per ton	$	97.25	$	138.50	(29.8	)%
Steam coal revenues per ton	$	77.23	$	76.43	1.1	%
Total coal revenues per ton †	$	85.19	$	92.99	(8.4	)%
Met coal tons produced	289.7		283.3		2.3	%
Steam coal tons produced	534.2		615.0		(13.1	)%
Total tons produced †	823.9		898.3		(8.3	)%

† 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 six months ended June 30, 2013 and 2012:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2013		June 30, 2012		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	54.3	$	54.8	$	(0.5	)	(1.0	)%
Freight and handling costs	0.2		0.3		(0.1		)	(23.7	)%
Depreciation, depletion and amortization	12.4		13.6		(1.2		)	(8.9	)%
Selling, general and administrative	9.9		9.7		0.2			2.1	%
Cost of operations per ton*	$	69.30	$	71.69	$	(2.39	)	(3.3	)%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	27.9	$	38.5	$	(10.6	)	(27.6	)%
Freight and handling costs	0.4		2.8		(2.4		)	(88.2	)%
Depreciation, depletion and amortization	4.0		4.0		—			1.9	%
Selling, general and administrative	0.1		0.1		—			(31.5	)%
Cost of operations per ton*	$	42.02	$	41.68	$	0.34		0.8	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	15.3	$	13.8	$	1.5		10.9	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	2.7		2.1		0.6			26.6	%
Selling, general and administrative	—		—		—			(14.0	)%
Cost of operations per ton*	$	32.40	$	27.82	$	4.58		16.5	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	9.0	$	10.2	$	(1.2	)	(11.0	)%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.7		1.1		0.6			45.6	%
Selling, general and administrative	0.5		0.6		(0.1		)	(10.4	)%
Cost of operations per ton**	n/a		n/a		n/a			n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	106.5	$	117.3	$	(10.8	)	(9.2	)%
Freight and handling costs	0.6		3.1		(2.5		)	(81.9	)%
Depreciation, depletion and amortization	20.8		20.8		—			(0.3	)%
Selling, general and administrative	10.5		10.4		0.1			0.9	%
Cost of operations per ton*	$	55.52	$	53.71	$	1.81		3.4	%

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

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

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Cost of Operations.  Total cost of operations was $106.5 million for the six months ended June 30, 2013 as compared to $117.3 million for the six months ended June 30, 2012. Our cost of operations per ton was $55.52 for the six months ended June 30, 2013, an increase of $1.81, or 3.4%, from the six months ended June 30, 2012. Total cost of operations decreased primarily due to lower production at our Sands Hill complex in Northern 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 the sequence of mining at our Castle Valley mine in our Rhino Western segment where we performed more higher cost advance mining during the six months ended June 30, 2013 compared to more lower cost retreat mining that was performed in the six months ended June 30, 2012.

Our cost of operations for the Central Appalachia segment decreased by $0.5 million, or 1.0%, to $54.3 million for the six months ended June 30, 2013 from $54.8 million for the six months ended June 30, 2012. Our cost of operations per ton decreased to $69.30 per ton for the six months ended June 30, 2013 from $71.69 per ton for six months ended June 30, 2012. The decrease in cost of operations per ton was primarily due to the fact that we idled a majority of the Central Appalachia operations in June of 2012 in order to reduce higher than normal inventory levels, which resulted in a higher cost per ton figure for that period.

In our Northern Appalachia segment, our cost of operations decreased by $10.6 million, or 27.6%, to $27.9 million for the six months ended June 30, 2013 from $38.5 million for the six months ended June 30, 2012. The decrease in cost of operations was primarily due to lower production at our Sands Hill complex in Northern Appalachia, which was in response to weak market conditions for coal from this complex. Our cost of operations per ton was $42.02 for the six months ended June 30, 2013, an increase of $0.34, or 0.8%, compared to $41.68 for the six months ended June 30, 2012. The slight increase in cost of operations per ton was primarily due to reducing production volumes at Sands Hill along with higher roof support costs at our Hopedale operation.

Our cost of operations for the Rhino Western segment increased by $1.5 million, or 10.9%, to $15.3 million for the six months ended June 30, 2013 from $13.8 million for the six months ended June 30, 2012. Our cost of operations per ton increased to $32.40 per ton for the six months ended June 30, 2013 from $27.82 per ton for six months ended June 30, 2012. The increases in cost of operations and cost of operations per ton were primarily due to the sequence of mining at our Castle Valley mine where we performed more higher cost advance mining during the six months ended June 30, 2013 compared to more lower cost retreat mining that was performed in the six months ended June 30, 2012.

Cost of operations in our Other category decreased by $1.2 million for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012. This decrease was primarily due to zero cost incurred from our roof bolt manufacturing operation during the six months ended June 30, 2013 since this operation was sold in September 2012.

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Freight and Handling.  Total freight and handling cost for the six months ended June 30, 2013 decreased by $2.5 million, or 81.9%, to $0.6 million from $3.1 million for the six months ended June 30, 2012. This decrease was primarily due to the decrease in tons of coal sold for the six months ended June 30, 2013 compared to 2012 from our Sands Hill complex, which requires transportation by truck to customers’ locations.

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization, or DD&A, expense for the six months ended June 30, 2013 and 2012 was flat at $20.8 million.

For the six months ended June 30, 2013, our depreciation cost was $16.0 million as compared to $16.5 million for the six months ended June 30, 2012. This decrease is primarily due to a decrease in machinery and equipment depreciation from our Central Appalachia operations.

For the six months ended June 30, 2013, our depletion cost was $3.4 million compared to $2.9 million for the six months ended June 30, 2012. This increase is primarily attributable to our proportionate share of the Utica Shale oil and gas depletion that was not present in the prior period, partially offset by a decrease in depletion cost from fewer tons produced for the six months ended June 30, 2013 compared to 2012 due to weakness in the met and steam coal markets.

For the six months ended June 30, 2013, our amortization cost was flat at $1.4 million as compared to the six months ended June 30, 2012.

Selling, General and Administrative.  Selling, general and administrative, or SG&A, expense for the six months ended June 30, 2013 was $10.5 million as compared to $10.4 million for the six months ended June 30, 2012. This slight increase in SG&A expense was primarily due to an increase in expenditures for legal and accounting fees and other professional services.

Interest Expense.  Interest expense for the six months ended June 30, 2013 was flat at $3.8 million as compared to the six months ended June 30, 2012, as the average balance due under our credit facility was relatively flat period to period.

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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 %)	Six months ended  June 30, 2013			Six months ended  June 30, 2012		Increase (Decrease) %*
Eastern Met 100% Basis
Coal revenues	$	13,802		$	32,810	(57.9	)%
Total revenues	$	13,818		$	32,837	(57.9	)%
Coal revenues per ton*	$	112.77		$	191.69	(41.2	)%
Cost of operations	$	18,053		$	20,556	(12.2	)%
Cost of operations per ton*	$	147.51		$	120.09	22.8	%
Depreciation, depletion and amortization	$	957		$	1,122	(14.8	)%
Interest expense	$	0		$	139	n/a
Net income (loss)	$	(6,502	)	$	8,754	(174.3	)%
Partnership’s portion of net income (loss)	$	(3,316	)	$	4,391	(174.3	)%
Tons produced	79.3			204.7		(61.2	)%
Tons sold	122.4			171.2		(28.5	)%

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

The decrease in tons produced and sold for the six months ended June 30, 2013 compared to 2012 was due to weakness in the met coal market, which resulted in a significant decrease in the market price for the quality of met coal that Rhino Eastern produces. The decrease in tons sold resulted in decreased revenue and net income for the six months ended June 30, 2013 compared to the same period in 2012. Net income was also negatively impacted and cost of operations per ton increased for the six months ended June 30, 2013 from approximately $1.3 million in total write-downs in coal inventory value due to the decrease in the market value of Rhino Eastern’s met coal.

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Net Income (Loss).  The following table presents net income (loss) by reportable segment for the six months ended June 30, 2013 and 2012:

	Six months Ended			Six months Ended			Increase
Segment	June 30, 2013			June 30, 2012			(Decrease)
	(in millions)
Central Appalachia	$	(7.3	)	$	1.0		$	(8.3	)
Northern Appalachia	18.4			17.1			1.3
Rhino Western	(0.4		)	2.8			(3.2		)
Eastern Met *	(3.3		)	4.4			(7.7		)
Other	(1.7		)	(3.3		)	1.6
Total	$	5.7		$	22.0		$	(16.3	)

*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.

For the six months ended June 30, 2013, total net income decreased to approximately $5.7 million compared to approximately $22.0 million for the six months ended June 30, 2012 as decreases in costs and expenses were offset by decreases in coal revenues, including lower royalty revenue from our coal leasing business, as well as lower results from our Rhino Eastern joint venture. For the six months ended June 30, 2013, our net income was positively impacted by $10.5 million from the sale of our 20% royalty interest on our Utica Shale property. Our net income for the six months ended June 30, 2012 was positively impacted by approximately $7.4 million in total lease bonus payments that we received on our Utica Shale property.

For our Central Appalachia segment, we generated a net loss of approximately $7.3 million for the six months ended June 30, 2013, a decrease of $8.3 million compared to $1.0 million of net income for the six months ended June 30, 2012.  The year to year decrease was primarily due to a decrease in tons sold, which decreased revenue, and an approximate $1.0 million charge incurred for the write-off of a continuous miner that was destroyed at one of our underground Central Appalachia mines. Net income in our Northern Appalachia segment increased by $1.3 million to $18.4 million for the six months ended June 30, 2013, from $17.1 million for the six months ended June 30, 2012. This increase was primarily from the $10.5 million received from the sale of our 20% royalty interest on our Utica Shale property in the six months ended June 30, 2013 as compared to approximately $7.4 million of lease bonus payments that we received on our Utica Shale property in the six months ended June 30, 2012. The increase period to period due to the Utica Shale payments received was partially offset from a decrease in tons of coal sold from our Sands Hill complex due to weakness in the steam coal market. Net income in our Rhino Western segment decreased by $3.2 million to a loss of approximately $0.4 million for the six months ended June 30, 2013, compared to net income of $2.8 million for the six months ended June 30, 2012. This decrease was primarily the result of an increase in cost of operations at our Castle Valley operation. Our Eastern Met segment recorded a net loss of $3.3 million for the six months ended June 30, 2013, a decrease of $7.7 million from net income of $4.4 million for the six months ended June 30, 2012, as weakness in the met coal

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market caused a decrease in the number of tons sold and lower prices for tons sold.  For the Other category, we had a net loss of $1.7 million for the six months ended June 30, 2013, which was an improvement as compared to a net loss of $3.3 million for the six months ended June 30, 2012. The improvement was primarily due to positive results from our Utica Shale oil and natural gas investments in the six months ended June 30, 2013.

Adjusted EBITDA.  The following table presents Adjusted EBITDA by reportable segment for the six months ended June 30, 2013 and 2012:

	Six months Ended			Six months Ended			Increase
Segment	June 30, 2013			June 30, 2012			(Decrease)
	(in millions)
Central Appalachia	$	7.9		$	16.7		$	(8.8	)
Northern Appalachia	22.8			21.4			1.4
Rhino Western	2.6			5.3			(2.7		)
Eastern Met *	(2.8		)	5.1			(7.9		)
Other	1.2			(1.3		)	2.5
Total	$	31.7		$	47.2		$	(15.5	)

*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 for the six months ended June 30, 2013 was $31.7 million, a decrease of $15.5 million from the six months ended June 30, 2012. Adjusted EBITDA decreased primarily as a result of a decrease in net income, as described previously. 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 June 30, 2013	Appalachia			Appalachia		Western			Met *			Other			Total
	(in millions)
Net income	$	(5.1	)	$	13.8	$	(0.3	)	$	(2.1	)	$	(0.4	)	$	5.9
Plus:
DD&A	6.2			2.0		1.3			—			1.1			10.6
Interest expense	0.9			0.2		0.2			—			0.6			1.9
EBITDA†	$	2.0		$	16.0	$	1.2		$	(2.1	)	$	1.3		$	18.4
Plus: Rhino Eastern DD&A-51%	—			—		—			0.2			—			0.2
Plus: Rhino Eastern interest expense-51%	—			—		—			—			—			—
Adjusted EBITDA†	$	2.0		$	16.0	$	1.2		$	(1.9	)	$	1.3		$	18.6

	Central			Northern		Rhino		Eastern
Three months ended June 30, 2012	Appalachia			Appalachia		Western		Met *		Other			Total
	(in millions)
Net income	$	(1.5	)	$	12.1	$	1.5	$	2.3	$	(1.4	)	$	13.0
Plus:
DD&A	6.1			2.1		1.1		—		0.5			9.8
Interest expense	1.1			0.2		0.1		—		0.5			1.9
EBITDA†	$	5.7		$	14.4	$	2.7	$	2.3	$	(0.4	)	$	24.7
Plus: Rhino Eastern DD&A-51%	—			—		—		0.3		—			0.3
Plus: Rhino Eastern interest expense-51%	—			—		—		—		—			—
Adjusted EBITDA†	$	5.7		$	14.4	$	2.7	$	2.6	$	(0.4	)	$	25.0

	Central			Northern		Rhino			Eastern
Six months ended June 30, 2013	Appalachia			Appalachia		Western			Met *			Other			Total
	(in millions)
Net income	$	(7.3	)	$	18.4	$	(0.4	)	$	(3.3	)	$	(1.7	)	$	5.7
Plus:
DD&A	12.4			4.0		2.7			—			1.7			20.8
Interest expense	1.8			0.4		0.3			—			1.2			3.8
EBITDA†	$	6.9		$	22.8	$	2.6		$	(3.3	)	$	1.2		$	30.3
Plus: Rhino Eastern DD&A-51%	—			—		—			0.5			—			0.5
Plus: Rhino Eastern interest expense-51%	—			—		—			—			—			—
Plus: Non-cash write-off of mining equipment (1)	1.0			—		—			—			—			1.0
Adjusted EBITDA† **	$	7.9		$	22.8	$	2.6		$	(2.8	)	$	1.2		$	31.7

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	Central		Northern		Rhino		Eastern
Six months ended June 30, 2012	Appalachia		Appalachia		Western		Met *		Other			Total**
	(in millions)
Net income	$	1.0	$	17.1	$	2.8	$	4.4	$	(3.3	)	$	22.0
Plus:
DD&A	13.6		4.0		2.1		—		1.1			20.8
Interest expense	2.1		0.3		0.4		—		0.9			3.8
EBITDA†	$	16.7	$	21.4	$	5.3	$	4.4	$	(1.3	)	$	46.5
Plus: Rhino Eastern DD&A-51%	—		—		—		0.6		—			0.6
Plus: Rhino Eastern interest expense-51%	—		—		—		0.1		—			0.1
Adjusted EBITDA†	$	16.7	$	21.4	$	5.3	$	5.1	$	(1.3	)	$	47.2

*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 June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(in millions)
Net cash provided by operating activities	$	18.5	$	16.3	$	29.1	$	33.4
Plus:
Increase in net operating assets	—		7.9		—		8.4
Gain on sale of assets	10.6		—		9.7		1.0
Amortization of deferred revenue	0.4		0.3		0.6		0.6
Amortization of actuarial gain	—		0.1		0.1		0.1
Interest expense	1.9		1.9		3.8		3.8
Equity in net income of unconsolidated affiliate	—		2.3		—		4.4
Less:
Decrease in net operating assets	9.8		—		7.2		—
Accretion on interest-free debt	—		—		0.1		0.1
Amortization of advance royalties	—		—		0.1		0.1
Amortization of debt issuance costs	0.4		0.3		0.6		0.6
Equity-based compensation	0.1		0.2		0.4		0.5
Loss on sale/disposal of assets	—		0.2		—		—
Loss on retirement of advance royalties	—		—		—		—
Accretion on asset retirement obligations	0.6		0.4		1.2		0.9
Distributions from unconsolidated affiliate	—		3.0		—		3.0
Equity in net loss of unconsolidated affiliates	2.1		—		3.4		—
EBITDA†	$	18.4	$	24.7	$	30.3	$	46.5
Plus: Rhino Eastern DD&A-51%	0.2		0.3		0.5		0.6
Plus: Rhino Eastern interest expense-51%	—		—		—		0.1
Plus: Non-cash write-off of mining equipment (1)	—		—		1.0		—
Adjusted EBITDA† **	$	18.6	$	25.0	$	31.7	$	47.2

†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.

**Totals may not foot due to rounding.

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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 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 June 30, 2013, our available liquidity was $115.7 million, including cash on hand of $0.4 million and $115.3 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 $29.1 million for the six months ended June 30, 2013 as compared to $33.4 million for the six months ended June 30, 2012.  This decrease in cash provided by operating activities was primarily the result of lower net income, which resulted from decreased tons sold and revenue as well as unfavorable results from our Rhino Eastern joint venture. The unfavorable change in net income was partially offset by a favorable change in working capital accounts for the six months ended June 30, 2013 as compared to 2012, including a favorable period to period change in inventories. For the six months ended June 30, 2013, we had a favorable change in inventories as we decreased production and sold excess coal inventory tons, which compared to an unfavorable change in inventories for the six months ended June 30, 2012 as we built inventory levels as demand weakened in the met and steam coal markets.

Net cash used in investing activities was $5.6 million for the six months ended June 30, 2013 as compared to $41.2 million for the six months ended June 30, 2012. The decrease in cash used in investing activities was primarily due to the decreased amounts expended for the purchase and construction of mining equipment. For the six months ended June 30, 2012, our primary expenditures were related to the new preparation plant in our Tug River mining complex, which resulted in increased expenditures when compared to the six months ended June 30, 2013. In addition, the $10.5 million received from the sale of our 20% royalty interest on our Utica Shale property in the six months ended June 30, 2013 resulted in lower net cash used in investing activities when compared to 2012.

Net cash used in financing activities for the six months ended June 30, 2013 was $23.5 million, which was primarily attributable to distributions paid to unitholders and repayments on debt during the six months ended June 30, 2013. Net cash used in financing activities for the six months ended June 30, 2013 also included an approximate $1.0 million use of cash for the amendment to our credit facility. Net cash provided by financing activities for the six months ended June 30, 2012 was $8.2 million, which were primarily attributable to borrowings under our credit agreement, partially offset by our distributions to unitholders in that period.

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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 six months ended June 30, 2013 were approximately $3.7 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the six months ended June 30, 2013 were approximately $13.4 million, which were primarily related to additional investment in our oil and natural gas properties in the Utica Shale region, as well as the initial development of our new Riveredge mine in western Kentucky. For the year ending December 31, 2013, we have budgeted $10 million to $15 million for maintenance capital expenditures and $31 million to $39 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 is $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 is available for letters of credit.

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 2.25%, and the applicable margin for the LIBOR option is 2.50% to 3.25%, each of which depends on our and our

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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 3.25% 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 June 30, 2013, we were in compliance with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.

At June 30, 2013, we had borrowed $150.0 million at a variable interest rate of LIBOR plus 3.00% (3.20% at June 30, 2013) and an additional $0.8 million at a variable interest rate of PRIME plus 2.00% (5.25% at June 30, 2013). In addition, we had outstanding letters of credit of approximately $22.1 million at a fixed interest rate of 2.75% at June 30, 2013. We had not used $115.3 million of the borrowing availability at June 30, 2013. During the three months ended June 30, 2013, we had average borrowings outstanding of approximately $151.9 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 increases the maximum leverage ratio of the amended and restated senior secured credit facility to 3.75 from April 1, 2013 through June 30, 2015, then steps 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.

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

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

As of June 30, 2013, we had $22.1 million in letters of credit outstanding, of which $17.2 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, 2012. There have been no significant changes in these policies and estimates as of June 30, 2013.

Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-02, “Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”. This ASU requires preparers to report, in one place, information about reclassifications out of accumulated other comprehensive income (“AOCI”). The ASU also requires companies to report changes in AOCI balances. For significant items reclassified out of AOCI to net income in their entirety in the same reporting period, reporting (either on the face of the statement where net income is presented or in the notes) is required about the effect of the reclassifications on the respective line items in the statement where net income is presented. For items that are not reclassified to net income in their entirety in the same reporting period, a cross reference to other disclosures currently required under US GAAP (e.g., pension amounts that are included in inventory) is required in the notes. The above information must be presented in one place (parenthetically on the face of the financial statements by income statement line item or in a note). Public companies must provide the information required by the ASU (e.g., changes in AOCI balances and reclassifications out of AOCI) in interim and annual periods. For public companies, the ASU is effective for fiscal years and interim periods within those years beginning after 15 December 2012, or the first quarter of 2013 for calendar-year companies. The Partnership has included the required disclosures of ASU 2013-02 in this Form 10Q and this ASU did not have a material effect on the Partnership.

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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 June 30, 2013, we had commitments under supply contracts to deliver annually scheduled base quantities of approximately 1.8 million, 2.5 million, 1.6 million, 1.1 million and 1.1 million tons of coal to 18 customers in 2013, 8 customers in 2014, 4 customers in 2015, 2 customers in 2016, and 2 customers in 2017, respectively. 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 June 30, 2013 and would have reduced net income by $0.2 million for the six months ended June 30, 2013. A hypothetical increase of 10% in steel prices would have reduced net income by $0.3 million for the three months ended June 30, 2013 and would have reduced net income by $0.6 million for the six months ended June 30, 2013. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.1 million for the three months ended June 30, 2013 and would have reduced net income by $0.2 million for the six months ended June 30, 2013.

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 $0.4 million for the three months ended June 30, 2013 and would have changed our interest expense by $0.8 million for the six months ended June 30, 2013.

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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 June 30, 2013 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 June 30, 2013, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—Other Information

Item 1.  Legal Proceedings.

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

Item 1A.  Risk Factors.

In addition to the other information set forth in this Report, you should carefully consider the risks under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012, 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, 2012. 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.

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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 June 30, 2013 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	Amended and Restated Employment Agreement of David G. Zatezalo dated January 21, 2013, incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K (File No. 001-34892) filed on March 8, 2013
10.2	First Amendment to Amended and Restated Credit Agreement, dated April 18, 2013 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 10.1 of the Current Report on Form 8-K (File No. 001-34892) filed on April 19, 2013
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 June 30, 2013

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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: August 7, 2013	By:	/s/ David G. Zatezalo
		David G. Zatezalo
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: August 7, 2013	By:	/s/ Richard A. Boone
		Richard A. Boone
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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