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, 2012

OR

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

For the transition period from                     to                    

Commission file number 001-34892

RHINO RESOURCE PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	27-2377517
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
424 Lewis Hargett Circle, Suite 250 Lexington, KY	40503
(Address of principal executive offices)	(Zip Code)

(859) 389-6500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x Yes   No o

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	Smaller reporting company o
(Do not check if a smaller reporting company)

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 3, 2012, 15,331,902 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, 2012 and December 31, 2011	2
	Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 4.	Controls and Procedures	62
PART II—Other Information		63
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	63
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; 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, 2011, (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,
	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	774		$	449
Accounts receivable, net of allowance for doubtful accounts ($0 as of June 30, 2012 and December 31, 2011)	34,592			37,242
Inventories	23,801			15,629
Advance royalties, current portion	738			1,428
Prepaid expenses and other	5,079			4,327
Total current assets	64,984			59,075
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	669,255			637,563
Less accumulated depreciation, depletion and amortization	(201,251		)	(187,447		)
Net property, plant and equipment	468,004			450,116
Advance royalties, net of current portion	3,065			1,924
Investment in unconsolidated affiliates	20,284			18,736
Goodwill	202			202
Intangible assets	1,267			1,308
Other non-current assets	6,325			7,433
TOTAL	$	564,131		$	538,794
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	15,808		$	23,145
Accrued expenses and other	20,608			19,691
Current portion of long-term debt	3,290			1,334
Current portion of asset retirement obligations	4,106			3,192
Current portion of postretirement benefits	157			157
Total current liabilities	43,969			47,519
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion	175,388			141,764
Asset retirement obligations, net of current portion	29,852			30,921
Other non-current liabilities	7,123			6,000
Postretirement benefits, net of current portion	5,747			5,492
Total non-current liabilities	218,110			184,177
Total liabilities	262,079			231,696
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners	288,300			293,100
General partner	11,553			11,650
Accumulated other comprehensive income	2,199			2,348
Total partners’ capital	302,052			307,098
TOTAL	$	564,131		$	538,794

See notes to unaudited condensed consolidated financial statements.

2

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands)

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
REVENUES:
Coal sales	$	72,177		$	83,819		$	141,780		$	162,379
Freight and handling revenues	1,794			1,439			3,314			2,570
Other revenues	16,027			4,619			26,787			7,683
Total revenues	89,998			89,877			171,881			172,632
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	60,203			67,432			117,290			128,473
Freight and handling costs	1,798			1,126			3,062			1,939
Depreciation, depletion and amortization	9,755			8,212			20,847			17,356
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	5,475			3,646			10,385			8,997
(Gain)/loss on sale of assets—net	168			(45		)	(990		)	(134		)
Total costs and expenses	77,399			80,371			150,594			156,631
INCOME FROM OPERATIONS	12,599			9,506			21,287			16,001
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense	(1,962		)	(1,366		)	(3,784		)	(2,424		)
Interest income and other	33			36			76			35
Equity in net income of unconsolidated affiliate	2,326			1,201			4,391			1,901
Total interest and other income (expense)	397			(129		)	683			(488		)
INCOME BEFORE INCOME TAXES	12,996			9,377			21,970			15,513
INCOME TAXES	—			—			—			—
NET INCOME	12,996			9,377			21,970			15,513
Other comprehensive income:
Amortization of actuarial gain under ASC Topic 715	(74		)	—			(148		)	—
COMPREHENSIVE INCOME	$	12,922		$	9,377		$	21,822		$	15,513
General partner’s interest in net income	$	260		$	188		$	439		$	310
Common unitholders’ interest in net income	$	7,041		$	4,598		$	11,900		$	7,604
Subordinated unitholders’ interest in net income	$	5,695		$	4,591		$	9,631		$	7,599
Net income per limited partner unit, basic:
Common units	$	0.46		$	0.37		$	0.78		$	0.61
Subordinated units	$	0.46		$	0.37		$	0.78		$	0.61
Net income per limited partner unit, diluted:
Common units	$	0.46		$	0.37		$	0.78		$	0.61
Subordinated units	$	0.46		$	0.37		$	0.78		$	0.61
Distributions paid per limited partner unit	$	0.48		$	0.455		$	0.96		$	0.8758
Weighted average number of limited partner units outstanding, basic:
Common units	15,329			12,416			15,317			12,405
Subordinated units	12,397			12,397			12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units	15,331			12,434			15,325			12,429
Subordinated units	12,397			12,397			12,397			12,397

See notes to unaudited condensed consolidated financial statements.

3

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Six Months			Six Months
	Ended June 30,			Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	21,970		$	15,513
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	20,847			17,356
Accretion on asset retirement obligations	870			979
Accretion on interest-free debt	109			104
Amortization of deferred revenue	(572		)	—
Amortization of advance royalties	126			756
Amortization of debt issuance costs	537			510
Amortization of actuarial gain	(148		)	—
Equity in net (income) of unconsolidated affiliate	(4,391		)	(1,901		)
Distribution from unconsolidated affiliate	2,958			—
Loss on retirement of advance royalties	—			79
(Gain) on sale of assets—net	(990		)	(134		)
Equity-based compensation	450			474
Changes in assets and liabilities:
Accounts receivable	2,650			1,042
Inventories	(8,172		)	(2,795		)
Advance royalties	(577		)	(671		)
Prepaid expenses and other assets	(176		)	263
Accounts payable	(7,337		)	1,712
Accrued expenses and other liabilities	5,698			1,610
Asset retirement obligations	(754		)	(1,217		)
Postretirement benefits	255			357
Net cash provided by operating activities	33,353			34,037
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(42,387		)	(35,305		)
Proceeds from sales of property, plant, and equipment	1,290			486
Principal payments received on notes receivable	8,160			1,720
Cash paid from issuance of notes receivable	(8,160		)	(2,230		)
Acquisition of coal companies and other properties	—			(119,299		)
Return of capital from unconsolidated affiliate	—			1,311
Investment in unconsolidated affiliate	(114		)	—
Net cash used in investing activities	(41,211		)	(153,317		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	133,250			217,000
Repayments on line of credit	(99,150		)	(71,963		)
Proceeds from issuance of long-term debt	2,603			1,379
Repayments on long-term debt	(1,233		)	(1,577		)
Net settlement of employee withholding taxes on unit awards vested	(85		)	(164		)
Debt issuance costs	—			(1,000		)
Distributions to unitholders	(27,202		)	(22,181		)
General partner’s contributions	7			6
Payment of offering costs	(7		)	(18		)
Net cash provided by financing activities	8,183			121,482
NET INCREASE IN CASH AND CASH EQUIVALENTS	325			2,202
CASH AND CASH EQUIVALENTS—Beginning of period	449			76
CASH AND CASH EQUIVALENTS—End of period	$	774		$	2,278

See notes to unaudited condensed consolidated financial statements.

4

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2012 AND DECEMBER 31, 2011 AND FOR THE THREE AND SIX MONTHS ENDED
JUNE 30, 2012 AND 2011

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 (the “Partnership”) and its subsidiaries. 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, 2012, condensed consolidated statements of operations for the three and six month periods ended June 30, 2012 and 2011 and the condensed consolidated statements of cash flows for the six months ended June 30, 2012 and 2011 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, 2011 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, 2011 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, 2011 filed with the SEC.

Organization—The Partnership is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor” or the “Operating Company”), an entity engaged primarily in the mining and sale of coal. The Partnership had no operations during the period from April 19, 2010 (date of inception) to October 5, 2010 (the consummation of the 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, 2012. The majority of the Operating Company’s 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 the Operating Company’s coal operations, the Partnership has invested in oil and gas mineral rights that began to generate royalty revenues in early 2012.

5

Follow-on Offering

On July 18, 2011, the Partnership completed a public offering of 2,875,000 common units, representing limited partner interests in the Partnership, at a price of $24.50 per common unit. Of the common units issued, 375,000 units were issued in connection with the exercise of the underwriters’ option to purchase additional units. Net proceeds from the offering were approximately $66.4 million, after deducting underwriting discounts and offering expenses of approximately $4.1 million. The Partnership used the net proceeds from this offering, and a related capital contribution by the Partnership’s general partner (the “General Partner”) of approximately $1.4 million, to repay approximately $67.8 million of outstanding indebtedness under the Partnership’s credit facility.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Investment in Joint Venture.  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 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, 2012 and December 31, 2011, the Partnership has recorded its Rhino Eastern equity method investment of $20.2 million and $18.7 million, respectively, as a long-term asset. During the six months ended June 30, 2012, the Partnership provided loans based upon its ownership share to the Rhino Eastern joint venture in the amount of $8.2 million, which were fully repaid as of June 30, 2012.

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

6

operating activities during the six months ended June 30, 2012 and the Partnership will initially include any operating activities of Timber Wolf in its Other category.

Recently Issued Accounting Standards. In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”. This ASU changes certain fair value measurement principles and clarifies the application of existing fair value measurement guidance. Amendments included in this ASU clarify the intent about the application of existing fair value measurement including the application of the highest and best use and valuation premise concepts. The amendments in this ASU specify that the concepts of highest and best use and valuation premise in a fair value measurement are relevant only when measuring the fair value of nonfinancial assets and are not relevant when measuring the fair value of financial assets or of liabilities. This ASU also requires additional fair value disclosures including a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position, but for which the fair value is required to be disclosed. The ASU is effective for interim and annual periods beginning after December 15, 2011 and are to be applied prospectively. While this ASU does not have an impact on the Partnership’s financial results, additional disclosures are required in the notes to the Partnership’s financial statements.

In September 2011, the FASB published ASU No. 2011-08, “Intangibles—Goodwill and Other (Topic 350) Testing Goodwill for Impairment”. Under the amendments in this ASU, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step goodwill impairment test is unnecessary. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step goodwill impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit. If the carrying amount of a reporting unit exceeds its fair value, then the entity is required to perform the second step of the goodwill impairment test to measure the amount of the impairment loss, if any. Under the amendments in this ASU, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. The ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted. The Partnership does not believe this new accounting guidance will have a material effect on its financial results.

In June 2011, the FASB published ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income”. Under the amendments in this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity

7

is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In a single continuous statement, the entity is required to present the components of net income and total net income, the components of other comprehensive income and a total for other comprehensive income, along with the total of comprehensive income in that statement. In the two-statement approach, an entity is required to present components of net income and total net income in the statement of net income. The statement of other comprehensive income should immediately follow the statement of net income and include the components of other comprehensive income and a total for other comprehensive income, along with a total for comprehensive income. Regardless of whether an entity chooses to present comprehensive income in a single continuous statement or in two separate but consecutive statements, the entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. The amendments in this ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments do not change the option for an entity to present components of other comprehensive income either net of related tax effects or before related tax effects, with one amount shown for the aggregate income tax expense or benefit related to the total of other comprehensive income items. In both cases, the tax effect for each component must be disclosed in the notes to the financial statements or presented in the statement in which other comprehensive income is presented. The amendments do not affect how earnings per share is calculated or presented. For public entities, the amendments of this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

Subsequently, in December 2011, the FASB issued ASU No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05”. In order to defer only those changes in Update 2011-05 that relate to the presentation of reclassification adjustments, the paragraphs in this ASU supersede certain pending paragraphs in ASU 2011-05. The amendments are being made to allow the FASB time to re-deliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, entities should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Public entities should apply these requirements for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Partnership has consistently presented comprehensive income in a single continuous statement with net income, so the provisions of ASU 2011-05 and the related deferral included in ASU 2011-12 did not have a material effect on the Partnership.

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3. BUSINESS COMBINATIONS AND OTHER ACQUISITIONS

Acquisition of The Elk Horn Coal Company, LLC

In June 2011, the Partnership completed the acquisition of 100% of the ownership interests in The Elk Horn Coal Company, LLC (“Elk Horn”) for approximately $119.7 million in cash consideration, or approximately $119.6 million net of cash acquired (referred to as the “Elk Horn Acquisition”). Elk Horn is primarily a coal leasing company that owns or controls coal reserves and non-reserve coal deposits and surface acreage in eastern Kentucky. The Elk Horn acquisition was initially funded with borrowings under the Partnership’s credit facility. The Partnership completed a public offering of the Partnership’s common units in July 2011 that provided proceeds the Partnership used to repay existing indebtedness on its credit facility that was incurred from the Elk Horn acquisition. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date:

	(in thousands)
Cash	$	58
Accounts receivable	2,619
Prepaid expenses and other	94
Property, plant and equipment	7,056
Mine development costs	3,000
Coal properties	112,057
Intangible assets	654
Other non-current assets	1,112
Accounts payable	(79		)
Deferred revenues	(2,499		)
Accrued expenses and other	(1,691		)
Asset retirement obligations	(2,707		)
Net assets acquired	119,674
Total consideration	$	119,674

Although the responsibility of valuation remains with the Partnership’s management, the determination of the fair values of the various assets and liabilities acquired were based in part upon studies conducted by third party professionals with experience in the appropriate subject matter. The studies related to the value of the property, plant and equipment, coal properties, intangible assets acquired and asset retirement obligations. The table above reflects the allocation of the purchase price to the fair value of the assets acquired and liabilities assumed in the Elk Horn acquisition, which resulted in no recognition of goodwill or gain on the acquisition. The Partnership’s unaudited condensed consolidated statements of operations and comprehensive income do not include revenue, costs or net income from Elk Horn prior to June 10, 2011, the effective date of the acquisition.

The following table presents selected unaudited pro forma financial information for the three and six months ended June 30, 2011, as if the acquisition had occurred on January 1, 2011. The pro forma information was prepared using Elk Horn’s historical financial data and also reflects adjustments based upon assumptions by the Partnership’s management to give effect for

9

certain pro forma items that are directly attributable to the acquisition. These pro forma adjustment items include increased depletion expense related to the step-up in basis for the mineral assets acquired and increased interest expense from borrowings incurred to fund the acquisition. The pro forma adjustments for interest expense and earnings per unit reflect the net amount of the additional borrowings incurred by the Partnership in June 2011 to initially fund the acquisition that were partially offset by proceeds from common units issued in a public offering completed in July 2011. Supplemental pro forma revenue, net earnings and earnings per unit disclosures are as follows.

	Three months ended			Six months ended
	June 30, 2011			June 30, 2011
	(in thousands)
Revenues:
As reported	$	89,877		$	172,632
Pro forma adjustments	3,419			9,477
Pro forma revenues	$	93,296		$	182,109
Net Income:
As reported	$	9,377		$	15,513
Pro forma adjustments	641			3,101
Pro forma net income	$	10,018		$	18,614
Net income per limited partner unit, diluted:
As reported	$	0.37		$	0.61
Pro forma adjustments	$	(0.02	)	$	0.05
Pro forma net income per limited partner unit	$	0.35		$	0.66

Acquisition of Oil and Gas Mineral Rights

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

The Partnership and an affiliate of Wexford Capital have participated with Gulfport Energy, a publicly traded company, to acquire interests in a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately 9.5% of the common stock of Gulfport Energy as of March 13, 2012. 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 for a total purchase price of approximately $19.9 million. Gulfport Energy is actively drilling in the Utica acreage.

On March 6, 2012, the Partnership completed a lease agreement with a third party for an estimated 1,500 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

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$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. The Partnership is working to resolve title issues on approximately 250 remaining acres to be included in the lease. 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. 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 by Elk Horn, which have been recorded as Other revenues. These leasing activities are expected to continue. 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.

Acquisition of Coal Property

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, the Partnership recorded $2.0 million as of June 30, 2012 related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. This additional $2.0 million is recorded in Property, plant and equipment and Accrued expenses and other in the Partnership’s unaudited condensed consolidated statements of financial position as of June 30, 2012. 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 30 million tons of non-reserve coal deposits that are contiguous to the Green River. The property is undeveloped, but fully permitted, and provides the Partnership with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers.

In August 2011, the Partnership purchased non-reserve coal deposits at its Sands Hill operation for approximately $2.5 million, which is estimated to include approximately 2.5 million tons of non-reserve coal deposits.

In June 2011, the Partnership acquired approximately 32,600 acres and associated surface rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million. These development stage properties are unpermitted and contain no infrastructure. The Partnership has explored the property and confirmed approximately 8.6 million tons of proven and probable underground metallurgical coal reserves as of December 31, 2011. The Partnership plans to eventually commence production on this property.

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4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of June 30, 2012 and December 31, 2011 consisted of the following:

	June 30,		December 31,
	2012		2011
	(in thousands)
Other prepaid expenses	$	499	$	577
Prepaid insurance	2,747		1,526
Prepaid leases	116		103
Supply inventory	1,398		1,951
Deposits	319		170
Total Prepaid expenses and other	$	5,079	$	4,327

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of June 30, 2012 and December 31, 2011 are summarized by major classification as follows:

	Useful Lives	June 30, 2012			December 31, 2011
		(in thousands)
Land and land improvements		$	34,978		$	33,298
Mining and other equipment and related facilities	2 - 20 Years	259,319			244,819
Mine development costs	1 - 15 Years	63,977			65,824
Coal properties	1 - 15 Years	269,194			266,319
Construction work in process		41,787			27,303
Total		669,255			637,563
Less accumulated depreciation, depletion and amortization		(201,251		)	(187,447		)
Net		$	468,004		$	450,116

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal 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, 2012 and 2011 were as follows:

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	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	7,700	$	6,545		$	16,464	$	13,281
Depletion expense for coal properties	1,375		978			2,921		1,849
Amortization expense for mine development costs	512		801			1,124		1,549
Amortization expense for intangible assets	20		12			41		23
Amortization expense/(credit) for asset retirement costs	148		(124		)	297		654
Total depreciation, depletion and amortization	$	9,755	$	8,212		$	20,847	$	17,356

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

6. GOODWILL AND INTANGIBLE ASSETS

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.

Goodwill as included in the Other category as of June 30, 2012 and December 31, 2011 consisted of the following:

	June 30,		December 31,
	2012		2011
	(in thousands)
Goodwill from the acquisition of Triad	$	202	$	202

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Intangible assets as of June 30, 2012 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	143	$	585
Developed Technology	78		15		63
Trade Name	184		10		174
Customer List	470		25		445
Total	$	1,460	$	193	$	1,267

Intangible assets as of December 31, 2011 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	121	$	607
Developed Technology	78		13		65
Trade Name	184		5		179
Customer List	470		13		457
Total	$	1,460	$	152	$	1,308

The Partnership considers the patent and developed technology intangible assets to have a useful life of seventeen years.

In connection with the Elk Horn acquisition, the Partnership recognized an intangible asset for the trade name valued at $184,000 and a customer list intangible asset valued at $470,000 during 2011. The trade name and customer list intangible assets recognized in the Elk Horn acquisition do not have any residual value and do not have any renewal or extension terms. The Partnership considers the trade name and customer list intangible assets to have a useful life of twenty years. All of the  intangible assets are amortized over their useful life on a straight line basis.

Amortization expense the three and six months ended June 30, 2012 and 2011 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, 2012:

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			Developed				Customer
	Patent		Technology		Trade Name		List		Total
	(in thousands)
2012 (from Jul 1 to Dec 31)	$	21	$	2	$	5	$	12	$	40
2013	43		5		9		23		80
2014	43		5		9		23		80
2015	43		5		9		23		80
2016	43		5		9		23		80

7. OTHER NON-CURRENT ASSETS

Other non-current assets as of June 30, 2012 and December 31, 2011 consisted of the following:

	June 30,		December 31,
	2012		2011
	(in thousands)
Deposits and other	$	1,916	$	2,481
Debt issuance costs—net	4,388		4,925
Deferred expenses	21		27
Total	$	6,325	$	7,433

Debt issuance costs were approximately $8.0 million as of June 30, 2012 and December 31, 2011. Accumulated amortization of debt issuance costs were approximately $3.6 million and approximately $3.1 million as of June 30, 2012 and December 31, 2011, respectively.

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8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of June 30, 2012 and December 31, 2011 consisted of the following:

	June 30,		December 31,
	2012		2011
	(in thousands)
Payroll, bonus and vacation expense	$	2,924	$	4,128
Non income taxes	3,922		3,950
Royalty expenses	2,815		2,489
Accrued interest	659		797
Health claims	1,778		1,386
Workers’ compensation & pneumoconiosis	1,690		1,690
Deferred revenues	2,358		1,967
Other	4,462		3,284
Total	$	20,608	$	19,691

9. DEBT

Debt as of June 30, 2012 and December 31, 2011 consisted of the following:

	June 30,			December 31,
	2012			2011
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$	171,100		$	137,000
Note payable to H&L Construction Co., Inc.	1,927			2,284
Other notes payable	5,651			3,814
Total	178,678			143,098
Less current portion	(3,290		)	(1,334		)
Long-term debt	$	175,388		$	141,764

Senior Secured Credit Facility with PNC Bank, N.A.—The original maximum availability under the credit facility by and among the Operating Company, the guarantors (including the Partnership) and lenders which are parties thereto, and PNC Bank, N.A. as administrative agent was $200.0 million. On June 8, 2011, with the consent of the lenders, the Operating Company exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn acquisition. As part of exercising this option to increase the available amount under the credit agreement, the

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Operating Company paid a fee of $1.0 million to the lenders, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position.

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 twelve months ended June 30, 2012. 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, 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, 2012, the Operating Company had borrowed $170.0 million at a variable interest rate of LIBOR plus 2.75% (3.00% at June 30, 2012) and an additional $1.1 million at a variable interest rate of PRIME plus 2.00% (5.00% at June 30, 2012). In addition, the Operating Company had outstanding letters of credit of approximately $26.8 million at a fixed interest rate of 2.75% at June 30, 2012. Based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $74.9 million of the borrowing availability at June 30, 2012.

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 $11.4 million and approximately $11.6 million at June 30, 2012 and December 31, 2011, respectively.

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10. ASSET RETIREMENT OBLIGATIONS

The changes in asset retirement obligations for the three months ended June 30, 2012 and the year ended December 31, 2011 are as follows:

	Six months ended June 30, 2012			Year ended December 31, 2011
	(in thousands)
Balance at beginning of period (including current portion)	$	34,113		$	35,691
Accretion expense	870			1,956
Adjustment resulting from addition of property	—			2,707
Adjustment resulting from disposal of property	(271		)	(3,588		)
Adjustments to the liability from annual recosting and other	—			(617		)
Liabilities settled	(754		)	(2,036		)
Balance at end of period	33,958			34,113
Current portion of asset retirement obligation	4,106			3,192
Long-term portion of asset retirement obligation	$	29,852		$	30,921

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. The Partnership has no other postretirement plans.

Net periodic benefit cost for the three and six months ended June 30, 2012 and 2011 are as follows:

	Three months ended June 30,					Six months ended June 30,
	2012			2011		2012			2011
	(in thousands)
Service costs	$	103		$	116	$	206		$	233
Interest cost	63			74		126			148
Amortization of (gain)	(74		)	—		(148		)	—
Total	$	92		$	190	$	184		$	381

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, 2012 and 2011 was as follows:

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(in thousands)
401(k) plan expense	$	559	$	548	$	1,163	$	1,068

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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, 2012, 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 granted in the first quarter of 2012 to certain employees in connection with fiscal year 2011 performance. A total of 20,664 phantom units were granted in the first quarter of 2012 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 2012 was approximately $0.4 million at the grant date and the fair value of these awards was approximately $0.3 million as of June 30, 2012. The expense related to these awards will be recognized ratably over the three year vesting period, plus any mark-to-market expense or income, and the amount of expense recognized in the three and six months ended June 30, 2012 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 awards granted thereafter. For the three and six months ended June 30, 2011, the Partnership recorded approximately $0.1 million and $0.2 million, respectively, in incremental compensation expense due to the modification of these awards. For the three and six months ended June 30, 2012, the Partnership did not record any incremental compensation expense due to the modification of these 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, 2012, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of approximately 2.3 million, 3.5 million, 2.4 million, 0.6 million and 0.3 million tons of coal to 19 customers in 2012, 9 customers in 2013, 6 customer in 2014, 3 customer in 2015, and 1 customer

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in 2016, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

The Partnership received a notice from one of its major customers in early April 2012 announcing it would be delaying some of its contracted steam coal shipments from the Partnership’s Central Appalachia and Northern Appalachia operations for an undefined period of time due to an over-supply of coal at its locations. While this customer purchased limited contracted tons in the second quarter of 2012 that impacted the Partnership’s tons of coal sold and coal revenues, this customer purchased regularly scheduled contracted tons during the months of June and July. While some uncertainty remains as to the impact on the Partnership and its results of operations of future decisions by this major customer regarding its contracted shipments, the Partnership continues to work with this customer to schedule its contracted shipments for the remainder of 2012.

Purchase Commitments—As of June 30, 2012, the Partnership had approximately 2.0 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2012 for approximately $7.0 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 months ended June 30, 2012 and 2011 were as follows:

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(in thousands)
Purchased coal expense	$	5,049	$	1,562	$	10,162	$	4,885
OTC expense	$	—	$	—	$	—	$	14

As of June 30, 2012, the Partnership had an outstanding commitment to purchase approximately 0.2 million tons of coal from a third party for the remainder of 2012 for approximately $13.8 million.

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, 2012 and 2011 was as follows:

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(in thousands)
Lease expense	$	568	$	642	$	1,263	$	1,317
Royalty expense	$	2,801	$	3,915	$	7,087	$	7,752

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Joint Ventures—Pursuant to the Rhino Eastern joint venture agreement with Patriot, the Partnership is required to contribute additional capital to assist in funding the development and operations of the Rhino Eastern joint venture. During the three and six months ended June 30, 2012 and 2011, the Partnership did not make any capital contributions 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 six months ended June 30, 2012 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, 2012 and 2011:

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 months ended June 30, 2012, approximately 80,000 LTIP granted phantom units were anti-dilutive. There were no other anti-dilutive units for any other periods presented.

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Three months ended June 30, 2011	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	188	$	4,598	$	4,591
Denominator:
Weighted average units used to compute basic EPU	n/a		12,416		12,397
Effect of dilutive securities — LTIP awards	n/a		18		—
Weighted average units used to compute diluted EPU	n/a		12,434		12,397
Net income per limited partner unit, basic	n/a		$	0.37	$	0.37
Net income per limited partner unit, diluted	n/a		$	0.37	$	0.37

Six months ended June 30, 2011	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	310	$	7,604	$	7,599
Denominator:
Weighted average units used to compute basic EPU	n/a		12,405		12,397
Effect of dilutive securities — LTIP awards	n/a		24		—
Weighted average units used to compute diluted EPU	n/a		12,429		12,397
Net income per limited partner unit, basic	n/a		$	0.61	$	0.61
Net income per limited partner unit, diluted	n/a		$	0.61	$	0.61

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
	2012		ended		ended
	Receivable		June 30,		June 30,
	Balance		2012 Sales		2011 Sales
	(in thousands)
GenOn Energy, Inc.	$	3,488	$	19,365	$	26,484
Indiana Harbor Coke Company, L.P	4,642		19,657		18,602
PPL Corporation	3,454		21,082		n/a
American Electric Power Company, Inc.	n/a		n/a		24,586

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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, 2012. 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, 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 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. In addition, with the acquisition of Elk Horn, the Partnership also leases coal reserves to third parties in exchange for royalty revenues. For the three and six months ended June 30, 2012, 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 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 investments in oil and gas mineral rights. 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 Partnership accounts for the Rhino Eastern joint venture under the equity method. Under the equity method of accounting, the Partnership has only presented limited information (net income). The Partnership considers this operation to comprise a separate operating segment and has presented additional operating detail, with corresponding eliminations and adjustments to reflect its percentage of ownership.

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Reportable segment results of operations for the three months ended June 30, 2012 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	$	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 three months ended June 30, 2011 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	$	54,838	$	28,704	$	4,691		$	12,478	$	(12,478	)	$	—	$	1,644		$	89,877
DD&A	4,757		2,030		670			781		(781		)	—		755			8,212
Interest expense	532		448		112			16		(16		)	—		274			1,366
Net Income (loss)	$	4,359	$	5,429	$	(709	)	$	2,355	$	(1,154	)	$	1,201	$	(903	)	$	9,377

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			Segments
	(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

Reportable segment results of operations for the six months ended June 30, 2011 are as follows:

								Eastern Met
										Equity			Equity
	Central		Northern		Rhino			Complete		Method			Method					Total
	Appalachia		Appalachia		Western			Basis		Eliminations			Presentation		Other			Segments
	(in thousands)
Total revenues	$	104,649	$	57,738	$	7,022		$	22,770	$	(22,770	)	$	—	$	3,223		$	172,632
DD&A	10,397		4,186		1,260			1,574		(1,574		)	—		1,513			$	17,356
Interest expense	949		754		159			17		(17		)	—		562			$	2,424
Net Income (loss)	$	6,432	$	11,722	$	(1,901	)	$	3,727	$	(1,826	)	$	1,901	$	(2,641	)	$	15,513

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Additional summarized financial information for the Rhino Eastern equity method investment for the periods ended June 30, 2012 and 2011:

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(in thousands)
Total costs and expenses	$	12,813	$	10,107	$	23,944	$	19,026
Income from operations	4,619		2,371		8,893		3,744

19.  SUBSEQUENT EVENTS

On July 23, 2012, 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, 2012 to all common unit holders of record as of the close of business on August 2, 2012.

The Partnership has a 51% equity interest in the Rhino Eastern joint venture, with Patriot owning the remaining membership interest. On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture is uncertain at this point, normal operations have continued at the joint venture and the Partnership is hopeful that the joint venture will continue normal operations and that the bankruptcy filing will not have a material negative effect on Rhino Eastern.

The Partnership and an affiliate of Wexford Capital participated with Gulfport Energy to acquire interests in a portfolio of oil and gas leases in the Utica Shale, which consisted of a 10.8% interest in approximately 80,000 acres. In August 2012, the board of directors of the Partnership’s general partner approved an exchange of the Partnership’s initial 10.8% position for a pro rata interest in 125,000 acres under lease by Gulfport Energy and an affiliate of Wexford Capital. The Partnership expects to ultimately have approximately a 5% net interest in the 125,000 acres, or approximately 6,250 net acres.

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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, 2011 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2011 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, 2011.

Overview

We are a growth oriented Delaware limited partnership formed to control and operate coal properties and invest in other natural resource assets. 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. In addition to our coal operations, we have invested in oil and gas mineral rights that began to generate royalty revenues in early 2012.

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2011, we controlled an estimated 437.0 million tons of proven and probable coal reserves, consisting of an estimated 415.6 million tons of steam coal and an estimated 21.4 million tons of metallurgical coal. In addition, as of December 31, 2011, we controlled an estimated 417.1 million tons of non-reserve coal deposits. As of December 31, 2011, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 43.4 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.

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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 expand our operations through strategic acquisitions, including the acquisition of stable, cash generating natural resource assets. We believe that such assets would allow us to grow our cash available for distribution and enhance stability of our cash flow.

During June 2012, we idled a majority of our operations at our Central Appalachia locations in eastern Kentucky and West Virginia to decrease our inventory. The idling of these operations was taken in response to inventory levels that had grown as we experienced continuing weakness in the coal markers that saw customers delaying a portion of their contracted shipments. We resumed operations at a majority of our Central Appalachia locations on July 9, 2012. Our operations at our two surface mines and one underground mine in Ohio as well as our underground mine in Utah continued to operate during the second quarter of 2012. In addition, our joint venture continued to operate its two underground mines in West Virginia in the second quarter. 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.

For the three and six months ended June 30, 2012, we generated revenues of approximately $90.0 million and approximately $171.9 million, respectively, and net income of approximately $13.0 million and approximately $22.0 million, respectively. Excluding results from the joint venture, for the three and six months ended June 30, 2012, we produced approximately 1.0 million tons and approximately 2.3 million tons of coal, respectively, and sold approximately 1.1 million tons and approximately 2.2 million tons of coal, respectively. For the three and six months ended June 30, 2012, approximately 96% and 91% of tons sold, respectively, were sold pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.1 million tons and 0.2 million tons, respectively, of premium mid-vol metallurgical coal for the three and six months ended June 30, 2012.

Recent Developments

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 impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture is uncertain at this point, normal operations have continued at the joint venture and we are hopeful that the joint venture will continue normal operations and that the bankruptcy filing will not have a material negative effect on Rhino Eastern.

Joint Venture and Other Investments

In March of 2012, we made an initial investment of approximately $0.1 million in a new joint venture, 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 six months ended June 30, 2012.

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In addition, during the second quarter of 2012 we formed a services company to provide drill pad construction services in the Utica Shale for drilling operators. This services company nearly completed the construction of its first drill pad as of June 30, 2012.

Coal Acquisitions

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, we recorded $2.0 million as of June 30, 2012 related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. This additional $2.0 million is recorded in Property, plant and equipment and Accrued expenses and other in our unaudited condensed consolidated statements of financial position as of June 30, 2012. 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 30 million tons of non-reserve coal deposits that are contiguous to the Green River. The property is undeveloped, but fully permitted, and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers.

In August 2011, we purchased non-reserve coal deposits at our Sands Hill operation for approximately $2.5 million, which is estimated to include approximately 2.5 million tons.

In June 2011, we acquired approximately 32,600 acres and associated surface rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million. These development stage properties are not permitted and contain no infrastructure. We plan to fully explore these properties and intend to prove up additional mineable underground metallurgical coal reserves for future mining.

Acquisition of The Elk Horn Coal Company, LLC

In June 2011, we completed the acquisition of 100% of the ownership interests in Elk Horn for approximately $119.7 million in cash consideration. Elk Horn is primarily a coal leasing company located in eastern Kentucky that is expected to provide us with royalty revenues in future periods. The Elk Horn acquisition was funded with borrowings available under our credit facility, which were subsequently repaid with proceeds from an offering of our common units.

Oil and Gas Investments

During the year ended 2011, we 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. We began to receive royalty revenues from these mineral rights in early 2012.

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We and an affiliate of Wexford Capital have participated with Gulfport Energy, a publicly traded company, to acquire interests in a portfolio of oil and gas leases in the Utica Shale. As of March 13, 2012, an affiliate of Wexford Capital owned approximately 9.5% of the common stock of Gulfport Energy. During the year ended December 31, 2011, we completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $19.9 million. Gulfport Energy is actively drilling in the Utica acreage. Our initial position in the Utica Shale consisted of a 10.8% interest in approximately 80,000 acres. In August 2012, the board of directors of our general partner approved an exchange of our initial 10.8% position for a pro rata interest in 125,000 acres under lease by Gulfport Energy and an affiliate of Wexford Capital. We expect to ultimately have approximately a 5% net interest in the 125,000 acres, or approximately 6,250 net acres.

In March 2012, we completed an out-lease agreement with a third party for an estimated 1,500 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. We are working to resolve title issues on approximately 250 remaining acres to be included in the lease. In addition, the lease agreement stipulates that the third party shall 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.

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.

In August 2011, we sold and assigned certain non-core mining assets and related liabilities located in the Phelps, Kentucky area of our Tug River mining complex for approximately $20 million. The mining assets included leasehold interests and permits to surface and mineral interests that included steam coal reserves and non-reserve coal deposits. Additionally, the sales agreement includes the potential for additional payments of approximately $8.75 million dependent upon the future issuance of certain permits and the commencement of mining activities by the purchaser. These contingent payments are being accounted for as gain contingencies and will be recognized in the future when and if the contingencies are resolved. The transaction also transferred certain liabilities related to the assets sold that we believe will positively impact future cash flows. Since we had limited mining operations on the assets that were sold, we believe the sale of these assets will not have a negative impact on our future financial results. In relation to the sale of these assets and transfer of liabilities, we recorded a gain of approximately $2.4 million.

Follow-on Offering

On July 18, 2011, we completed a public offering of 2,875,000 common units, representing limited partner interests in us, at a price of $24.50 per common unit. Of the common units issued, 375,000 units were issued in connection with the exercise of the underwriters’ option to purchase additional units. Net proceeds from the offering were approximately

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$66.4 million, after deducting underwriting discounts and offering expenses of approximately $4.1 million. We used the net proceeds from this offering, and a related capital contribution by our general partner of approximately $1.4 million, to repay approximately $67.8 million of outstanding indebtedness under our credit facility.

Credit Facility

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 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.

The original maximum availability under our credit facility with PNC Bank, N.A. as administrative agent, was $200.0 million. On June 8, 2011, with the consent of the lenders, we exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn acquisition.

Proposed Carbon Emission Rules

On March 27, 2012, the Environmental Protection Agency (“EPA”) proposed New Source Performance Standards (“NSPS”) for carbon dioxide emissions from new and modified electric power.  The proposed NSPS, if promulgated along the lines proposed, would pose significant challenges for the construction of new coal-fired power plants and could result in a decrease in U.S. demand for steam coal.

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.

Most often our coal is sold through supply contracts and we anticipate that we will continue to do so. As of June 30, 2012, we had commitments under sales contracts to deliver annually scheduled base quantities of approximately 2.3 million, approximately 3.5 million, approximately 2.4 million, approximately 0.6 million and approximately 0.3 million tons of coal to 19 customers in 2012, 9 customers in 2013, 6 customers in 2014, 3 customers in 2015 and 1 customer in 2016, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

We received a notice from one of our major customers in early April 2012 announcing it would be delaying some of its contracted steam coal shipments from our Central Appalachia and Northern Appalachia operations for an undefined period of time due to an over-supply of coal at

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its locations. While this customer purchased limited contracted tons in the second quarter of 2012 that impacted our tons of coal sold and coal revenues, this customer purchased regularly scheduled contracted tons during the months of June and July. While some uncertainty remains as to the impact on us and our results of operations of future decisions by this major customer regarding its contracted shipments, we continue to work with this customer to schedule its contracted shipments for the remainder of 2012.

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. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which are located in eastern Kentucky and southern West Virginia. Additionally, our Central Appalachia segment includes the Elk Horn 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, 2012. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of June 30, 2012. 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, 2012, and our Castle Valley mining complex in Utah that began production in January 2011. 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, 2012, this complex was comprised of two underground mines and a preparation plant and loadout facility (owned by our joint venture partner). Our Other category includes our ancillary businesses that consist of a roof bolt manufacturing operation, 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, and our investments in oil and gas mineral rights.

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-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

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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.

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, 2012 and 2011:

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
	(in millions)
Statement of Operations Data:
Total revenues	$	90.0		$	89.9		$	171.9		$	172.6
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	60.2			67.4			117.3			128.5
Freight and handling costs	1.8			1.1			3.1			1.9
Depreciation, depletion and amortization	9.8			8.2			20.8			17.4
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	5.5			3.7			10.4			8.9
(Gain) loss on sale of assets	0.1			—			(1.0		)	(0.1		)
Income from operations	12.6			9.5			21.3			16.0
Interest and other income (expense):
Interest expense	(1.9		)	(1.4		)	(3.8		)	(2.4		)
Interest income	—			0.1			0.1			—
Equity in net income (loss) of unconsolidated affiliate	2.3			1.2			4.4			1.9
Total interest and other income (expense)	0.4			(0.1		)	0.7			(0.5		)
Net income	$	13.0		$	9.4		$	22.0		$	15.5
Other Financial Data
Adjusted EBITDA	$	25.0		$	19.4		$	47.2		$	36.1

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Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

Summary.  For the three months ended June 30, 2012, our total revenues increased to $90.0 million from $89.9 million for the three months ended June 30, 2011. We sold 1.1 million tons of coal for the three months ended June 30, 2012, which is a 7.3% decrease compared to the tons of coal sold for the three months ended June 30, 2011. This decrease in tons sold was the result of weak demand in the met and steam coal markets as well as delays in customer contracted shipments, which resulted in lower coal revenues for the three months ended June 30, 2012 compared to the same period in 2011. We believe the weak demand in the steam coal markets was primarily driven by an unseasonably mild winter along with an over-supply of low priced natural gas, both of which resulted in an increase of coal inventory supplies at electric utilities and fewer tons of steam coal being utilized in electricity generation. Despite lower coal revenues, our total revenues were approximately flat period to period as we received $6.9 million as a lease bonus payment in the three months ended June 30, 2012 related to acreage we own in the Utica Shale region of eastern Ohio, which was recorded in Other revenues.

Net income and Adjusted EBITDA increased for the three months ended June 30, 2012 from the three months ended June 30, 2011.  Net income was approximately $13.0 million for the three months ended June 30, 2012 compared to approximately $9.4 million for the three months ended June 30, 2011. Net income was positively impacted by the $6.9 million lease bonus payment received in the three months ended June 30, 2012 related to our Utica acreage, which had relatively immaterial costs associated with the transaction. Net income was also positively impacted period to period due to $2.3 million of income from our Rhino Eastern joint venture for the three months ended June 30, 2012 compared to income of $1.2 million for the three months ended June 30, 2011, which represents our proportionate share of income from the joint venture in which we have a 51% membership interest and for which we serve as manager.

Adjusted EBITDA increased to $25.0 million for the three months ended June 30, 2012 from $19.4 million for the three months ended June 30, 2011. Adjusted EBITDA increased period to period due to an increase in net income, which was positively impacted by the lease bonus payment of $6.9 million. Adjusted EBITDA was also positively impacted period to period due to the net income impact from our Rhino Eastern joint venture discussed above.

Tons Sold.  The following table presents tons of coal sold by reportable segment for the three months ended June 30, 2012 and 2011:

	Three months	Three months	Increase/
	ended	ended	(Decrease)
Segment	June 30, 2012	June 30, 2011	Tons		% *
	(in thousands, except %)
Central Appalachia	388.0	593.0	(205.0	)	(34.6	)%
Northern Appalachia	475.7	498.9	(23.2	)	(4.7	)%
Rhino Western	251.2	110.7	140.5		126.9	%
Total *†	1,114.9	1,202.6	(87.7	)	(7.3	)%

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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 1,115,000 tons of coal for the three months ended June 30, 2012 compared to approximately 1,203,000 tons for the three months ended June 30, 2011. The decrease in total tons sold year-to-year was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia, along with delays in customer contracted shipments, partially offset by increased sales at our Castle Valley operation in Utah. Tons of coal sold in our Central Appalachia segment decreased by approximately 205,000 tons, or 34.6%, to approximately 388,000 tons for the three months ended June 30, 2012 from approximately 593,000 tons for the three months ended June 30, 2011. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the met and steam coal markets, along with delays in customer contracted shipments. For our Northern Appalachia segment, tons of coal sold decreased by approximately 23,000 tons, or 4.7%, to approximately 476,000 tons for the three months ended June 30, 2012 from approximately 499,000 tons for the three months ended June 30, 2011. The decrease in total tons sold year-to-year in Northern Appalachia was primarily due to delays in customer contracted shipments. Coal sales from our Rhino Western segment increased by approximately 141,000 tons, or 126.9%, for the three months ended June 30, 2012 compared to approximately 111,000 tons for the three months ended June 30, 2011 as our Castle Valley location was still being prepared for full operation in the 2011 period compared to operating at a greater capacity in the 2012 period.

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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, 2012 and 2011:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2012		June 30, 2011		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	36.3	$	53.1	$	(16.8	)	(31.7	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	6.0		1.7		4.3			249.6	%
Total revenues	$	42.3	$	54.8	$	(12.5	)	(22.9	)%
Coal revenues per ton*	$	93.49	$	89.59	$	3.90		4.4	%
Northern Appalachia
Coal revenues	$	25.8	$	26.0	$	(0.2	)	(0.9	)%
Freight and handling revenues	1.8		1.5		0.3			24.7	%
Other revenues	8.4		1.3		7.1			569.0	%
Total revenues	$	36.0	$	28.8	$	7.2		25.4	%
Coal revenues per ton*	$	54.20	$	52.13	$	2.07		4.0	%
Rhino Western
Coal revenues	$	10.1	$	4.7	$	5.4		116.0	%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	10.1	$	4.7	$	5.4		115.9	%
Coal revenues per ton*	$	40.29	$	42.32	$	(2.03	)	(4.8	)%
Other
Coal revenues	n/a		n/a		n/a			n/a
Freight and handling revenues	n/a		n/a		n/a			n/a
Other revenues	1.6		1.6		—			(1.0	)%
Total revenues	$	1.6	$	1.6	$	—		(1.0	)%
Coal revenues per ton**	n/a		n/a		n/a			n/a
Total
Coal revenues	$	72.2	$	83.8	$	(11.6	)	(13.9	)%
Freight and handling revenues	1.8		1.5		0.3			24.7	%
Other revenues	16.0		4.6		11.4			247.0	%
Total revenues	$	90.0	$	89.9	$	0.1		0.1	%
Coal revenues per ton*	$	64.74	$	69.70	$	(4.96	)	(7.1	)%

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

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** The Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for this category.

Our coal revenues for the three months ended June 30, 2012 decreased by approximately $11.6 million, or 13.9%, to approximately $72.2 million from approximately $83.8 million for the three months ended June 30, 2011. The decrease in coal revenues was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia, along with delays in customer contracted shipments. Coal revenues per ton were $64.74 for the three months ended June 30, 2012, a decrease of $4.96, or 7.1%, from $69.70 per ton for the three months ended June 30, 2011. This decrease in coal revenues per ton was primarily the result of a higher mix of lower priced coal from our Rhino Western operations.

For our Central Appalachia segment, coal revenues decreased by approximately $16.8 million, or 31.7%, to approximately $36.3 million for the three months ended June 30, 2012 from approximately $53.1 million for the three months ended June 30, 2011 primarily due to weakness in the met and steam coal markets, along with delays in customer contracted shipments, which resulted in fewer tons sold. Coal revenues per ton for our Central Appalachia segment increased by $3.90, or 4.4%, to $93.49 per ton for the three months ended June 30, 2012 as compared to $89.59 for the three months ended June 30, 2011, due to higher contracted prices, primarily related to metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to coal royalty revenue from Elk Horn.

For our Northern Appalachia segment, coal revenues were approximately $25.8 million for the three months ended June 30, 2012, a decrease of approximately $0.2 million, or 0.9%, from approximately $26.0 million for the three months ended June 30, 2011. This decrease was due to delays in customer shipments due to weakness in the steam coal market, which resulted in fewer tons sold. Coal revenues per ton for our Northern Appalachia segment increased by $2.07, or 4.0%, to $54.20 per ton for the three months ended June 30, 2012 as compared to $52.13 per ton for the three months ended June 30, 2011. This increase was primarily due to higher contracted prices for steam coal. Other revenues increased for our Northern Appalachia segment primarily due to the $6.9 million lease bonus received for acreage owned in the Utica Shale region.

For our Rhino Western segment, coal revenues increased by approximately $5.4 million, or 116.0%, to approximately $10.1 million for the three months ended June 30, 2012 from approximately $4.7 million for the three months ended June 30, 2011. The increase in revenue was due to an increase in tons sold for coal produced at our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $40.29 for the three months ended June 30, 2012, a decrease of $2.03, or 4.8%, from $42.32 for the three months ended June 30, 2011. The decrease in coal revenues per ton was due to a decrease in selling prices to our Castle Valley customers.

Other revenues for our Other category were flat period to period at $1.6 million.

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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 metallurgical coal (“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, 2012		Three months ended June 30, 2011		Increase (Decrease) %*
Met coal tons sold	109.0		194.7		(44.0	)%
Steam coal tons sold	279.0		398.3		(30.0	)%
Total tons sold †	388.0		593.0		(34.6	)%
Met coal revenue	$	14,651	$	23,419	(37.4	)%
Steam coal revenue	$	21,621	$	29,706	(27.2	)%
Total coal revenue †	$	36,272	$	53,125	(31.7	)%
Met coal revenues per ton	$	134.36	$	120.27	11.7	%
Steam coal revenues per ton	$	77.52	$	74.60	3.9	%
Total coal revenues per ton †	$	93.49	$	89.59	4.4	%
Met coal tons produced	99.0		161.8		(38.8	)%
Steam coal tons produced	232.4		380.4		(38.9	)%
Total tons produced †	331.4		542.2		(38.9	)%

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

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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, 2012 and 2011:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2012		June 30, 2011		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	29.5	$	41.0	$	(11.5	)	(28.0	)%
Freight and handling costs	0.3		—		0.3			n/a
Depreciation, depletion and amortization	6.1		4.7		1.4			28.2	%
Selling, general and administrative	5.2		3.3		1.9			58.8	%
Cost of operations per ton*	$	76.10	$	69.19	$	6.91		10.0	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	19.3	$	18.1	$	1.2		7.1	%
Freight and handling costs	1.5		1.1		0.4			36.3	%
Depreciation, depletion and amortization	2.1		2.0		0.1			1.1	%
Selling, general and administrative	0.1		0.1		—			(13.5	)%
Cost of operations per ton*	$	40.63	$	36.18	$	4.45		12.3	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	6.9	$	4.0	$	2.9		72.4	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.1		0.7		0.4			59.2	%
Selling, general and administrative	—		—		—			10.0	%
Cost of operations per ton*	$	27.49	$	36.18	$	(8.69	)	(24.0	)%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	4.5	$	4.3	$	0.2		2.3	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	0.5		0.8		(0.3		)	(28.7	)%
Selling, general and administrative	0.2		0.3		(0.1		)	(24.4	)%
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)	$	60.2	$	67.4	$	(7.2	)	(10.7	)%
Freight and handling costs	1.8		1.1		0.7			59.6	%
Depreciation, depletion and amortization	9.8		8.2		1.6			18.8	%
Selling, general and administrative	5.5		3.7		1.8			50.2	%
Cost of operations per ton*	$	54.00	$	56.07	$	(2.07	)	(3.7	)%

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

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

Cost of Operations.  Total cost of operations was $60.2 million for the three months ended June 30, 2012 as compared to $67.4 million for the three months ended June 30, 2011. The decrease in cost of operations was primarily due to decreased production due to weakness in the met and steam coal markets, including the temporary idling of a majority of our Central Appalachia operations during the month of June. Our cost of operations per ton was $54.00 for the three months ended June 30, 2012, a decrease of $2.07, or 3.7%, from the three months ended June 30, 2011. The decrease in the cost of operations on a per ton basis was primarily due to a higher mix of lower cost tons from our Castle Valley mine.

Our cost of operations for the Central Appalachia segment decreased by $11.5 million, or 28.0%, to $29.5 million for the three months ended June 30, 2012 from $41.0 million for the three months ended June 30, 2011. Our cost of operations per ton increased to $76.10 per ton for the three months ended June 30, 2012 from $69.19 per ton for three months ended June 30, 2011. The decrease in total cost of operations was primarily due to decreased production in response to weakness in the met and steam coal markets, including the temporary idling of a majority of our Central Appalachia operations during the month of June. Cost of operations per ton increased since a portion of our costs are fixed in nature and these fixed costs were spread over a smaller number of tons sold in the three months ended June 30, 2012.

In our Northern Appalachia segment, our cost of operations increased by $1.2 million, or 7.1%, to $19.3 million for the three months ended June 30, 2012 from $18.1 million for the three months ended June 30, 2011. Our cost of operations per ton was $40.63 for the three months ended June 30, 2012, an increase of $4.45, or 12.3%, compared to $36.18 for the three months ended June 30, 2011. The increases in cost of operations and cost of operations per ton were primarily due to geology issues of mining thinner coal seams at our Hopedale mine and an equipment issue that resulted in the need to replace a mining shovel at one of our Sands Hill surface mines.

Our cost of operations for the Rhino Western segment increased by $2.9 million, or 72.4%, to $6.9 million for the three months ended June 30, 2012 from $4.0 million for the three months ended June 30, 2011. Our cost of operations per ton decreased to $27.49 per ton for the three months ended June 30, 2012 from $36.18 per ton for three months ended June 30, 2011. The increase in cost of operations was primarily due to increased production at our Castle Valley mine. Cost of operations per ton decreased primarily due to our Castle Valley mine being at full production in the second quarter of 2012 compared to costs incurred in the second quarter of 2011 associated with preparing our Castle Valley mine to begin production that had a smaller amount of tons sold.

Cost of operations in our Other category increased slightly by $0.2 million for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. This increase was primarily due to an increase in amounts spent for professional fees and outside services.

Freight and Handling.  Total freight and handling cost for the three months ended June 30, 2012 increased by $0.7 million, or 59.6%, to $1.8 million from $1.1 million for the three

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months ended June 30, 2011. This increase was primarily due to an increase in the tons of limestone sold for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011, along with increased coal freight and handling costs in Central Appalachia due to a new customer contract that required coal to be trucked to the customer’s location.

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization, or DD&A, expense for the three months ended June 30, 2012 was $9.8 million as compared to $8.2 million for the three months ended June 30, 2011.

For the three months ended June 30, 2012, our depreciation cost was $7.7 million as compared to $6.5 million for the three months ended June 30, 2011. This increase is primarily due to an increase in machinery and equipment, including a new high-wall miner purchased in Central Appalachia.

For the three months ended June 30, 2012, our depletion cost was $1.4 million compared to $1.0 million for the three months ended June 30, 2011. This increase is primarily attributable to depletion expense incurred at our Elk Horn operations that were not present in the 2011 comparable period since Elk Horn was acquired in June 2011.

Our amortization cost was primarily flat at $0.7 million period to period.

Selling, General and Administrative.  Selling, general and administrative, or SG&A, expense for the three months ended June 30, 2012 was $5.5 million as compared to $3.7 million for the three months ended June 30, 2011. This increase in SG&A expense was primarily due to an increase in expenditures for legal fees and other professional fees.

Interest Expense.  Interest expense for the three months ended June 30, 2012 was $1.9 million as compared to $1.4 million for the three months ended June 30, 2011, an increase of $0.5 million, or 43.7%. This increase was primarily the result of an increase in the borrowings under our credit facility.

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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,  2012		Three months  ended June 30,  2011		Increase  (Decrease)  %*
Eastern Met 100% Basis
Coal revenues	$	17,420	$	12,466	39.7	%
Total revenues	$	17,432	$	12,478	39.7	%
Coal revenues per ton*	$	188.34	$	198.96	(5.3	)%
Cost of operations	$	11,098	$	8,786	26.3	%
Cost of operations per ton*	$	119.99	$	140.22	(14.4	)%
Depreciation, depletion and amortization	$	554	$	781	(29.1	)%
Interest expense	$	58	$	16	263.4	%
Net income (loss)	$	4,561	$	2,355	93.7	%
Partnership’s portion of net income (loss)	$	2,326	$	1,201	93.7	%
Tons produced	98.2		60.9		61.1	%
Tons sold	92.5		62.7		47.6	%

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

Rhino Eastern’s Eagle #2 mine began production in the third quarter of 2011, which resulted in an increase in tons produced and sold for the three months ended June 30, 2012 compared to 2011. The increase in tons sold resulted in increased revenue and net income for the three months ended June 30, 2012 compared to the same period in 2011.

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Net Income (Loss).  The following table presents net income (loss) by reportable segment for the three months ended June 30, 2012 and 2011:

	Three months ended			Three months ended			Increase
Segment	June 30, 2012			June 30, 2011			(Decrease)
	(in millions)
Central Appalachia	$	(1.5	)	$	4.4		$	(5.9	)
Northern Appalachia	12.1			5.4			6.7
Rhino Western	1.5			(0.7		)	2.2
Eastern Met *	2.3			1.2			1.1
Other	(1.4		)	(0.9		)	(0.5		)
Total	$	13.0		$	9.4		$	3.6

*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, 2012, total net income increased to approximately $13.0 million compared to approximately $9.4 million the three months ended June 30, 2011. Net income was positively impacted by $6.9 million received as a lease bonus payment in the three months ended June 30, 2012 related to acreage we own in the Utica Shale region of eastern Ohio, which was recorded in Other revenue and had relatively immaterial costs associated with the transaction. For our Central Appalachia segment, net income decreased to a loss of $1.5 million for the three months ended June 30, 2012, a decrease of $5.9 million as compared to the three months ended June 30, 2011, primarily due weakness in the steam and met coal markets that resulted in fewer tons sold. Net income in our Northern Appalachia segment increased by $6.7 million to $12.1 million for the three months ended June 30, 2012, from $5.4 million for the three months ended June 30, 2011. This increase was primarily the result of the $6.9 million lease bonus payment. Net income in our Rhino Western segment increased by $2.2 million to income of $1.5 million for the three months ended June 30, 2012, compared to a loss of $0.7 million for the three months ended June 30, 2011. This increase was primarily the result of increased tons sold at our Castle Valley operation. Our Eastern Met segment recorded net income of $2.3 million for the three months ended June 30, 2012, an increase of $1.1 million from net income of $1.2 million for the three months ended June 30, 2011.  For the Other category, we had a net loss of $1.4 million for the three months ended June 30, 2012 compared to a net loss of $0.9 million for the three months ended June 30, 2011.

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Adjusted EBITDA.  The following table presents Adjusted EBITDA by reportable segment for the three months ended June 30, 2012 and 2011:

	Three months ended			Three months ended		Increase
Segment	June 30, 2012			June 30, 2011		(Decrease)
	(in millions)
Central Appalachia	$	5.7		$	9.7	$	(4.0	)
Northern Appalachia	14.4			7.9		6.5
Rhino Western	2.7			0.1		2.6
Eastern Met *	2.6			1.6		1.0
Other	(0.4		)	0.1		(0.5		)
Total	$	25.0		$	19.4	$	5.6

*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, 2012 was $25.0 million, an increase of $5.6 million from the three months ended June 30, 2011. Adjusted EBITDA increased as a result of an increase in net income, which was positively impacted by the lease bonus payment of $6.9 million. 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.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Summary.  For the six months ended June 30, 2012, our total revenues decreased to $171.9 million from $172.6 million for the six months ended June 30, 2011. We sold 2.2 million tons of coal for the six months ended June 30, 2012, which is a 6.0% decrease compared to the tons of coal sold for the six months ended June 30, 2011. This decrease in tons sold was the result of weak demand in the met and steam coal markets as well as delays in customer contracted shipments, which resulted in lower coal revenues for the six months ended June 30, 2012 compared to the same period in 2011. We believe the weak demand in the steam coal markets was primarily driven by an unseasonably mild winter along with an over-supply of low priced natural gas, both of which resulted in an increase of coal inventory supplies at electric utilities and fewer tons of steam coal being utilized in electricity generation. Despite lower coal revenues, our total revenues were approximately flat period to period partially due to $7.4 million in total lease bonus payments received in the six months ended June 30, 2012 for our Utica Shale acreage, which was recorded in Other revenues.

For the six months ended June 30, 2012, we increased our coal inventories by approximately 0.1 million tons. Our coal inventory increased in the six months ended June 30,

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2012 due to weak demand in the steam and met coal markets as well as delays in customer contracted shipments.

Net income and Adjusted EBITDA increased for the six months ended June 30, 2012 from the six months ended June 30, 2011.  Net income was approximately $22.0 million for the six months ended June 30, 2012 compared to approximately $15.5 million for the six months ended June 30, 2011. Net income was positively impacted by the $7.4 million lease bonus payments received in the six months ended June 30, 2012 related to our Utica Shale acreage, which had relatively immaterial costs associated with the transaction. Net income was also positively impacted period to period due to $4.4 million of income from our Rhino Eastern joint venture for the six months ended June 30, 2012 compared to income of $1.9 million for the six months ended June 30, 2011, which represents our proportionate share of income from the joint venture in which we have a 51% membership interest and for which we serve as manager.

Adjusted EBITDA increased to $47.2 million for the six months ended June 30, 2012 from $36.1 million for the six months ended June 30, 2011. Adjusted EBITDA increased period to period due to an increase in net income, which was positively impacted by the lease bonus payments of $7.4 million. Adjusted EBITDA was also positively impacted period to period due to the net income impact from our Rhino Eastern joint venture discussed above.

Tons Sold.  The following table presents tons of coal sold by reportable segment for the six months ended June 30, 2012 and 2011:

	Six months	Six months	Increase/
	ended	ended	(Decrease)
Segment	June 30, 2012	June 30, 2011	Tons		% *
	(in thousands, except %)
Central Appalachia	765.4	1,150.0	(384.6	)	(33.4	)%
Northern Appalachia	923.6	1,002.5	(78.9	)	(7.9	)%
Rhino Western	494.9	169.6	325.3		191.7	%
Total *†	2,183.9	2,322.1	(138.2	)	(6.0	)%

*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 2,184,000 tons of coal for the six months ended June 30, 2012 compared to approximately 2,322,000 tons for the six months ended June 30, 2011. The decrease in total tons sold year-to-year was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia, along with delays in customer contracted shipments, partially offset by increased sales at our Castle Valley operation in Utah. Tons of coal sold in our Central Appalachia segment decreased by approximately 385,000 tons, or 33.4%, to approximately 765,000 tons for the six months ended June 30, 2012 from approximately 1,150,000 tons for the

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six months ended June 30, 2011. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the met and steam coal markets, along with delays in customer contracted shipments. For our Northern Appalachia segment, tons of coal sold decreased by approximately 79,000 tons, or 7.9%, to approximately 924,000 tons for the six months ended June 30, 2012 from approximately 1,002,000 tons for the six months ended June 30, 2011. The decrease in total tons sold year-to-year in Northern Appalachia was primarily due to delays in customer contracted shipments. Coal sales from our Rhino Western segment increased by approximately 325,000 tons, or 191.7%, for the six months ended June 30, 2012 compared to approximately 170,000 tons for the six months ended June 30, 2011 as this operation was still being prepared for full operation in the 2011 period compared to operating at a greater capacity in the 2012 period.

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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, 2012 and 2011:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2012		June 30, 2011		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	71.2	$	102.6	$	(31.4	)	(30.6	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	13.0		2.1		10.9			521.2	%
Total revenues	$	84.2	$	104.7	$	(20.5	)	(19.6	)%
Coal revenues per ton*	$	92.99	$	89.18	$	3.81		4.3	%
Northern Appalachia
Coal revenues	$	50.5	$	52.8	$	(2.3	)	(4.4	)%
Freight and handling revenues	3.3		2.6		0.7			28.9	%
Other revenues	10.6		2.3		8.3			348.3	%
Total revenues	$	64.4	$	57.7	$	6.7		11.5	%
Coal revenues per ton*	$	54.66	$	52.68	$	1.98		3.7	%
Rhino Western
Coal revenues	$	20.1	$	7.0	$	13.1		187.0	%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	20.1	$	7.0	$	13.1		186.9	%
Coal revenues per ton*	$	40.67	$	41.34	$	(0.67	)	(1.6	)%
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	3.2		3.2		—			(0.8	)%
Total revenues	$	3.2	$	3.2	$	—		(0.8	)%
Coal revenues per ton**	n/a		n/a		n/a			n/a
Total
Coal revenues	$	141.8	$	162.4	$	(20.6	)	(12.7	)%
Freight and handling revenues	3.3		2.6		0.7			28.9	%
Other revenues	26.8		7.6		19.2			248.7	%
Total revenues	$	171.9	$	172.6	$	(0.7	)	(0.4	)%
Coal revenues per ton*	$	64.92	$	69.93	$	(5.01	)	(7.2	)%

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

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** The Other category includes results for our ancillary businesses. The activities performed by these ancillary businesses do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for this category.

Our coal revenues for the six months ended June 30, 2012 decreased by approximately $20.6 million, or 12.7%, to approximately $141.8 million from approximately $162.4 million for the six months ended June 30, 2011. The decrease in coal revenues was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia, along with delays in customer contracted shipments. Coal revenues per ton were $64.92 for the six months ended June 30, 2012, a decrease of $5.01, or 7.2%, from $69.93 per ton for the six months ended June 30, 2011. This decrease in coal revenues per ton was primarily the result of a higher mix of lower priced coal from our Rhino Western operations.

For our Central Appalachia segment, coal revenues decreased by approximately $31.4 million, or 30.6%, to approximately $71.2 million for the six months ended June 30, 2012 from approximately $102.6 million for the six months ended June 30, 2011 primarily due to weakness in the met and steam coal markets, along with delays in customer contracted shipments, which resulted in fewer tons sold. Coal revenues per ton for our Central Appalachia segment increased by $3.81, or 4.3%, to $92.99 per ton for the six months ended June 30, 2012 as compared to $89.18 for the six months ended June 30, 2011, due to higher contracted prices, primarily related to metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to coal royalty revenue from Elk Horn.

For our Northern Appalachia segment, coal revenues were approximately $50.5 million for the six months ended June 30, 2012, a decrease of approximately $2.3 million, or 4.4%, from approximately $52.8 million for the six months ended June 30, 2011. This decrease was due to delays in customer shipments due to weakness in the steam coal market, which resulted in fewer tons sold. Coal revenues per ton for our Northern Appalachia segment increased by $1.98, or 3.7%, to $54.66 per ton for the six months ended June 30, 2012 as compared to $52.68 per ton for the six months ended June 30, 2011. This increase was primarily due to higher contracted prices for steam coal. Other revenues increased for our Northern Appalachia segment primarily due to the $7.4 million lease bonus received for acreage owned in the Utica Shale region.

For our Rhino Western segment, coal revenues increased by approximately $13.1 million, or 187.0%, to approximately $20.1 million for the six months ended June 30, 2012 from approximately $7.0 million for the six months ended June 30, 2011. The increase in revenue was due to an increase in tons sold for coal produced at our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $40.67 for the six months ended June 30, 2012, a decrease of $0.67, or 1.6%, from $41.34 for the six months ended June 30, 2011. The decrease in coal revenues per ton was due to lower selling prices to customers for coal produced at our Castle Valley mine.

Other revenues for our Other category were flat period to period at $3.2 million.

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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 metallurgical coal (“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, 2012		Six months  ended June  30, 2011		Increase  (Decrease) %*
Met coal tons sold	204.2		369.6		(44.7	)%
Steam coal tons sold	561.2		780.4		(28.1	)%
Total tons sold †	765.4		1,150.0		(33.4	)%
Met coal revenue	$	28,284	$	44,165	(36.0	)%
Steam coal revenue	$	42,887	$	58,390	(26.6	)%
Total coal revenue †	$	71,171	$	102,555	(30.6	)%
Met coal revenues per ton	$	138.50	$	119.50	15.9	%
Steam coal revenues per ton	$	76.43	$	74.82	2.1	%
Total coal revenues per ton †	$	92.99	$	89.18	4.3	%
Met coal tons produced	283.3		360.5		(21.4	)%
Steam coal tons produced	615.0		766.5		(19.8	)%
Total tons produced †	898.3		1,127.0		(20.3	)%

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

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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, 2012 and 2011:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2012		June 30, 2011		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	54.8	$	76.5	$	(21.7	)	(28.3	)%
Freight and handling costs	0.3		—		0.3			n/a
Depreciation, depletion and amortization	13.6		10.4		3.2			31.2	%
Selling, general and administrative	9.7		8.2		1.5			18.7	%
Cost of operations per ton*	$	71.69	$	66.58	$	5.11		7.7	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	38.5	$	35.7	$	2.8		8.0	%
Freight and handling costs	2.8		1.9		0.9			42.5	%
Depreciation, depletion and amortization	4.0		4.2		(0.2		)	(5.3	)%
Selling, general and administrative	0.1		0.1		—			(0.7	)%
Cost of operations per ton*	$	41.68	$	35.57	$	6.11		17.2	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	13.8	$	6.5	$	7.3		113.1	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	2.1		1.3		0.8			67.3	%
Selling, general and administrative	—		—		—			5.8	%
Cost of operations per ton*	$	27.82	$	38.08	$	(10.26	)	(27.0	)%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	10.2	$	9.8	$	0.4		3.9	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.1		1.5		(0.4		)	(24.7	)%
Selling, general and administrative	0.6		0.6		—			(20.7	)%
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)	$	117.3	$	128.5	$	(11.2	)	(8.7	)%
Freight and handling costs	3.1		1.9		1.2			57.9	%
Depreciation, depletion and amortization	20.8		17.4		3.4			20.1	%
Selling, general and administrative	10.4		8.9		1.5			15.4	%
Cost of operations per ton*	$	53.71	$	55.33	$	(1.62	)	(2.9	)%

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

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

Cost of Operations.  Total cost of operations was $117.3 million for the six months ended June 30, 2012 as compared to $128.5 million for the six months ended June 30, 2011. The decrease in the cost of operations was primarily due to decreased production due to weakness in the met and steam coal markets, including the idling of a majority of our Central Appalachia operations in June. Our cost of operations per ton was $53.71 for the six months ended June 30, 2012, a decrease of $1.62, or 2.9%, from the six months ended June 30, 2011. The decrease in the cost of operations on a per ton basis was primarily due to a higher mix of lower cost tons from our Castle Valley mine.

Our cost of operations for the Central Appalachia segment decreased by $21.7 million, or 28.3%, to $54.8 million for the six months ended June 30, 2012 from $76.5 million for the six months ended June 30, 2011. Our cost of operations per ton increased to $71.69 per ton for the six months ended June 30, 2012 from $66.58 per ton for six months ended June 30, 2011. The decrease in total cost of operations was primarily due to decreased production in response to weakness in the met and steam coal markets, including the temporary idling of a majority of our Central Appalachia operations during the month of June. Cost of operations per ton increased since a portion of our costs are fixed in nature and these fixed costs were spread over a smaller number of tons sold in the six months ended June 30, 2012.

In our Northern Appalachia segment, our cost of operations increased by $2.8 million, or 8.0%, to $38.5 million for the six months ended June 30, 2012 from $35.7 million for the six months ended June 30, 2011. Our cost of operations per ton was $41.68 for the six months ended June 30, 2012, an increase of $6.11, or 17.2%, compared to $35.57 for the six months ended June 30, 2011. The increases in cost of operations and cost of operations per ton were primarily due to geology issues of mining thinner coal seams at our Hopedale mine and an equipment issue that resulted in the need to replace a mining shovel at one of our Sands Hill surface mines.

Our cost of operations for the Rhino Western segment increased by $7.3 million, or 113.1%, to $13.8 million for the six months ended June 30, 2012 from $6.5 million for the six months ended June 30, 2011. Our cost of operations per ton decreased to $27.82 per ton for the six months ended June 30, 2012 from $38.08 per ton for six months ended June 30, 2011. The increase in cost of operations was primarily due to increased production at our Castle Valley mine. Cost of operations per ton decreased primarily due to our Castle Valley mine being at full production in 2012 compared to costs incurred in the first six months of 2011 associated with preparing our Castle Valley mine to begin production that had a small amount of tons sold.

Cost of operations in our Other category increased slightly by $0.4 million for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. This increase was primarily due to an increase in amounts spent for professional fees and outside services.

Freight and Handling.  Total freight and handling cost for the six months ended June 30, 2012 increased by $1.2 million, or 57.9%, to $3.1 million from $1.9 million for the six months ended June 30, 2011. This increase was primarily due to an increase in the tons of limestone sold for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011,

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along with increased coal freight and handling costs in Central Appalachia due to a new customer contract that required coal to be trucked to the customer’s location.

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization, or DD&A, expense for the six months ended June 30, 2012 was $20.8 million as compared to $17.4 million for the six months ended June 30, 2011.

For the six months ended June 30, 2012, our depreciation cost was $16.5 million as compared to $13.3 million for the six months ended June 30, 2011. This increase is primarily due to an increase in machinery and equipment, including a new high-wall miner purchased in Central Appalachia.

For the six months ended June 30, 2012, our depletion cost was $2.9 million compared to $1.9 million for the six months ended June 30, 2011. This increase is primarily attributable to depletion expense incurred at our Elk Horn operations that were not present in the 2011 comparable period since Elk Horn was acquired in June 2011.

For the six months ended June 30, 2012, our amortization cost was $1.4 million as compared to $2.2 million for the six months ended June 30, 2011. This decrease is primarily attributable to changes in asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative.  Selling, general and administrative, or SG&A, expense for the six months ended June 30, 2012 was $10.4 million as compared to $8.9 million for the six months ended June 30, 2011. This increase in SG&A expense was primarily due to an increase in expenditures for legal fees and other professional fees.

Interest Expense.  Interest expense for the six months ended June 30, 2012 was $3.8 million as compared to $2.4 million for the six months ended June 30, 2011, an increase of $1.4 million, or 56.1%. This increase was primarily the result of an increase in the borrowings under our credit facility.

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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, 2012		Six months ended June 30, 2011		Increase (Decrease) %*
Eastern Met 100% Basis
Coal revenues	$	32,810	$	22,741	44.3	%
Total revenues	$	32,837	$	22,770	44.2	%
Coal revenues per ton*	$	191.69	$	193.72	(1.0	)%
Cost of operations	$	20,556	$	16,181	27.0	%
Cost of operations per ton*	$	120.09	$	137.83	(12.9	)%
Depreciation, depletion and amortization	$	1,122	$	1,574	(28.7	)%
Interest expense	$	139	$	17	711.3	%
Net income (loss)	$	8,754	$	3,727	134.9	%
Partnership’s portion of net income (loss)	$	4,391	$	1,901	131.0	%
Tons produced	204.7		117.3		74.5	%
Tons sold	171.2		117.4		45.8	%

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

Rhino Eastern’s Eagle #2 mine began production in the third quarter of 2011, which resulted in an increase in tons produced and sold for the six months ended June 30, 2012 compared to 2011. The increase in tons sold resulted in increased revenue and net income for the six months ended June 30, 2012 compared to the same period in 2011.

Net Income (Loss).  The following table presents net income (loss) by reportable segment for the six months ended June 30, 2012 and 2011:

	Six months Ended			Six months Ended			Increase
Segment	June 30, 2012			June 30, 2011			(Decrease)
	(in millions)
Central Appalachia	$	1.0		$	6.4		$	(5.4	)
Northern Appalachia	17.1			11.7			5.4
Rhino Western	2.8			(1.9		)	4.7
Eastern Met *	4.4			1.9			2.5
Other	(3.3		)	(2.6		)	(0.7		)
Total	$	22.0		$	15.5		$	6.5

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*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, 2012, total net income increased to approximately $22.0 million compared to approximately $15.5 million the six months ended June 30, 2011. Net income was positively impacted by $7.4 million received as a lease bonus payment in the six months ended June 30, 2012 related to acreage we own in the Utica Shale region of eastern Ohio, which was recorded in Other revenue and had relatively immaterial costs associated with the transaction. For our Central Appalachia segment, net income decreased to $1.0 million for the six months ended June 30, 2012, a decrease of $5.4 million as compared to the six months ended June 30, 2011, primarily due weakness in the steam and met coal markets that resulted in fewer tons sold. Net income in our Northern Appalachia segment increased by $5.4 million to $17.1 million for the six months ended June 30, 2012, from $11.7 million for the six months ended June 30, 2011. This increase was primarily the result of the $7.4 million lease bonus payment partially offset by a decrease in tons of coal sold due to delays in customer shipments of contracted steam coal. Net income in our Rhino Western segment increased by $4.7 million to income of $2.8 million for the six months ended June 30, 2012, compared to a loss of $1.9 million for the six months ended June 30, 2011. This increase was primarily the result of increased tons sold at our Castle Valley operation. Our Eastern Met segment recorded net income of $4.4 million for the six months ended June 30, 2012, an increase of $2.5 million from net income of $1.9 million for the six months ended June 30, 2011.  For the Other category, we had a net loss of $3.3 million for the six months ended June 30, 2012, as compared to a net loss of $2.6 million for the six months ended June 30, 2011.

Adjusted EBITDA.  The following table presents Adjusted EBITDA by reportable segment for the six months ended June 30, 2012 and 2011:

	Six months Ended			Six months Ended			Increase
Segment	June 30, 2012			June 30, 2011			(Decrease)
	(in millions)
Central Appalachia	$	16.7		$	17.8		$	(1.1	)
Northern Appalachia	21.4			16.7			4.7
Rhino Western	5.3			(0.5		)	5.8
Eastern Met *	5.1			2.7			2.4
Other	(1.3		)	(0.6		)	(0.7		)
Total	$	47.2		$	36.1		$	11.1

*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.

Total Adjusted EBITDA for the six months ended June 30, 2012 was $47.2 million, an increase of $11.1 million from the six months ended June 30, 2011. Adjusted EBITDA increased as a result of an increase in net income, which was positively impacted by the lease bonus payment of $7.4 million. 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,

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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.

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, 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
Three months ended June 30, 2011	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	4.4	$	5.4	$	(0.7	)	$	1.2	$	(0.9	)	$	9.4
Plus:
DD&A	4.7		2.0		0.7			—		0.8			8.2
Interest expense	0.6		0.5		0.1			—		0.2			1.4
EBITDA†	$	9.7	$	7.9	$	0.1		$	1.2	$	0.1		$	19.0
Plus: Rhino Eastern DD&A-51%	—		—		—			0.4		—			0.4
Plus: Rhino Eastern interest expense-51%	—		—		—			—		—			—
Adjusted EBITDA†	$	9.7	$	7.9	$	0.1		$	1.6	$	0.1		$	19.4

	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

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	Central		Northern		Rhino			Eastern
Six months ended June 30, 2011	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	6.4	$	11.7	$	(1.9	)	$	1.9	$	(2.6	)	$	15.5
Plus:
DD&A	10.4		4.2		1.3			—		1.5			17.4
Interest expense	1.0		0.8		0.1			—		0.5			2.4
EBITDA†	$	17.8	$	16.7	$	(0.5	)	$	1.9	$	(0.6	)	$	35.3
Plus: Rhino Eastern DD&A-51%	—		—		—			0.8		—			0.8
Plus: Rhino Eastern interest expense-51%	—		—		—			—		—			—
Adjusted EBITDA†	$	17.8	$	16.7	$	(0.5	)	$	2.7	$	(0.6	)	$	36.1

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

**Totals may not foot due to rounding.

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

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(in millions)
Net cash provided by operating activities	$	16.3	$	28.0	$	33.4	$	34.0
Plus:
Increase in net operating assets	7.9		—		8.4		—
Gain on sale of assets	—		—		1.0		0.1
Amortization of deferred revenue	0.3		—		0.6		—
Amortization of actuarial gain	0.1		—		0.1		—
Interest expense	1.9		1.4		3.8		2.4
Equity in net income of unconsolidated affiliate	2.3		1.2		4.4		1.9
Less:
Decrease in net operating assets	—		10.5		—		0.2
Accretion on interest-free debt	—		0.1		0.1		0.1
Amortization of advance royalties	—		0.2		0.1		0.7
Amortization of debt issuance costs	0.3		0.2		0.6		0.5
Equity-based compensation	0.2		0.1		0.5		0.5
Loss on sale of assets	0.2		—		—		—
Loss on retirement of advance royalties	—		—		—		0.1
Accretion on asset retirement obligations	0.4		0.5		0.9		1.0
Distributions from unconsolidated affiliate	3.0		—		3.0		—
Equity in net loss of unconsolidated affiliate	—		—		—		—
EBITDA†	$	24.7	$	19.0	$	46.5	$	35.3
Plus: Rhino Eastern DD&A-51%	0.3		0.4		0.6		0.8
Plus: Rhino Eastern interest expense-51%	—		—		0.1		—
Adjusted EBITDA†	$	25.0	$	19.4	$	47.2	$	36.1

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

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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. Our maximum borrowing capacity under our credit agreement is three times a trailing twelve-month EBITDA calculation, as defined in the credit agreement. As of June 30, 2012, our available liquidity was $75.7 million, including cash on hand of $0.8 million and $74.9 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 $33.4 million for the six months ended June 30, 2012 as compared to $34.0 million for the six months ended June 30, 2011. Net cash provided by operating activities for the six months ended June 30, 2012 was positively impacted by the $7.4 million lease bonus received for our Utica acreage. This benefit was offset by an unfavorable change in inventories that resulted from an increase in coal inventories in the six months ended June 30, 2012 due to weakness in the coal markets.

Net cash used in investing activities was $41.2 million for the six months ended June 30, 2012 as compared to $153.3 million for the six months ended June 30, 2011. Net cash used in investing activities for the six months ended June 30, 2011 included $119.3 million paid for the Elk Horn acquisition completed in June 2011. Net cash used in investing activities for the six months ended June 30, 2012 included increased amounts expended for the purchase of mining equipment and other asset acquisitions compared to the same period in 2011, primarily related to the new preparation plant in our Tug River mining complex.

Net cash provided by financing activities for the six months ended June 30, 2012 was $8.2 million, which was primarily attributable to borrowings under our credit agreement, partially offset by our distributions to unitholders in the six months ended June 30, 2012.  Net cash provided by financing activities for the six months ended June 30, 2011 was $121.5 million, which were primarily attributable to borrowings under our credit agreement that were used to initially fund the Elk Horn acquisition, partially offset by our distributions to unitholders in 2011.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Maintenance capital expenditures

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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, 2012 were approximately $14.6 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the six months ended June 30, 2012 were approximately $27.8 million, which were primarily related to the new preparation plant in our Tug River mining complex. For the year ending December 31, 2012, we have budgeted $15.0 million to $18.0 million for maintenance 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

The original maximum availability under our credit facility with PNC Bank, N.A. as administrative agent, was $200.0 million. On June 8, 2011, with the consent of the lenders, we exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn acquisition.

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 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

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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 twelve months ended June 30, 2012, we were in compliance with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.

At June 30, 2012, we had borrowed $170.0 million at a variable interest rate of LIBOR plus 2.75% (3.00% at June 30, 2012) and an additional $1.1 million at a variable interest rate of PRIME plus 2.00% (5.00% at June 30, 2012). In addition, we had outstanding letters of credit of approximately $26.8 million at a fixed interest rate of 2.75% at June 30, 2012. Based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), we had not used $74.9 million of the borrowing availability at June 30, 2012. During the three months ended June 30, 2012, we had average borrowings outstanding of approximately $169.5 million in relation to this credit agreement.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Federal and state laws require us to secure certain long-term obligations related to mine closure and reclamation costs. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of our credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding 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, 2012, we had $26.8 million in letters of credit outstanding, of which $21.8 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.

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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, 2011. There have been no significant changes in these policies and estimates as of June 30, 2012.

Recent Accounting Pronouncements

In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”. This ASU changes certain fair value measurement principles and clarifies the application of existing fair value measurement guidance. Amendments included in this ASU clarify the intent about the application of existing fair value measurement including the application of the highest and best use and valuation premise concepts. The amendments in this ASU specify that the concepts of highest and best use and valuation premise in a fair value measurement are relevant only when measuring the fair value of nonfinancial assets and are not relevant when measuring the fair value of financial assets or of liabilities. This ASU also requires additional fair value disclosures including a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position, but for which the fair value is required to be disclosed. The ASU is effective for interim and annual periods beginning after December 15, 2011 and are to be applied prospectively. While this ASU does not have an impact on our financial results, we will have additional disclosures in the notes to our financial statements.

In September 2011, the FASB published ASU No. 2011-08, “Intangibles—Goodwill and Other (Topic 350) Testing Goodwill for Impairment”. Under the amendments in this ASU, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step goodwill impairment test is unnecessary. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step goodwill impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit. If the carrying amount of a reporting unit exceeds its fair value, then the entity is required to perform the second step of the goodwill impairment test to measure the amount of the impairment loss, if any. Under the amendments in this ASU, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. The ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 and early adoption is permitted.

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We do not believe this new accounting guidance will have a material effect on our financial results.

In June 2011, the FASB published ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income”. Under the amendments in this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In a single continuous statement, the entity is required to present the components of net income and total net income, the components of other comprehensive income and a total for other comprehensive income, along with the total of comprehensive income in that statement. In the two-statement approach, an entity is required to present components of net income and total net income in the statement of net income. The statement of other comprehensive income should immediately follow the statement of net income and include the components of other comprehensive income and a total for other comprehensive income, along with a total for comprehensive income. Regardless of whether an entity chooses to present comprehensive income in a single continuous statement or in two separate but consecutive statements, the entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. The amendments in this ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments do not change the option for an entity to present components of other comprehensive income either net of related tax effects or before related tax effects, with one amount shown for the aggregate income tax expense or benefit related to the total of other comprehensive income items. In both cases, the tax effect for each component must be disclosed in the notes to the financial statements or presented in the statement in which other comprehensive income is presented. The amendments do not affect how earnings per share is calculated or presented. For public entities, the amendments of this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

Subsequently, in December 2011, the FASB issued ASU No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05”. In order to defer only those changes in Update 2011-05 that relate to the presentation of reclassification adjustments, the paragraphs in this ASU supersede certain pending paragraphs in ASU 2011-05. The amendments are being made to allow the FASB time to re-deliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, entities should continue to report reclassifications out of

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accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Public entities should apply these requirements for fiscal years, and interim periods within those years, beginning after December 15, 2011. We have consistently presented comprehensive income in a single continuous statement with net income, so the provisions of ASU 2011-05 and the related deferral included in ASU 2011-12 did not have a material effect on us.

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 and the use of forward contracts.

Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward purchases to manage the exposure related to this volatility. 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, 2012 and would have reduced net income by $0.3 million for the six months ended June 30, 2012. A hypothetical increase of 10% in steel prices would have reduced net income by $0.3 million for the three months ended June 30, 2012 and would have reduced net income by $0.7 million for the six months ended June 30, 2012. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.2 million for the three months ended June 30, 2012 and would have reduced net income by $0.3 million for the six months ended June 30, 2012.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. During the past year, we have been operating in a period of declining interest rates, and we have managed to take advantage of the trend to reduce our interest expense. 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, 2012 and would have changed our interest expense by $0.8 million for the six months ended June 30, 2012.

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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, 2012 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, 2012, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

In addition to the other information set forth in this Report, you should carefully consider the risks under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011, 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, 2011. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

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

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

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosure

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the three months ended June 30, 2012 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 Christopher I. Walton dated April 2, 2012
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, 2012
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

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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 9, 2012	By:	/s/ David G. Zatezalo
		David G. Zatezalo
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: August 9, 2012	By:	/s/ Richard A. Boone
		Richard A. Boone
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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