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, 2011

OR

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

For the transition period from                  to                

Commission file number 001-34892

RHINO RESOURCE PARTNERS LP
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 27-2377517
(IRS Employer
Identification No.)

424 Lewis Hargett Circle, Suite 250 Lexington, KY
(Address of principal executive offices) 40503
(Zip Code)

(859) 389-6500
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x  Yes  o  No

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

Large accelerated filer o	Accelerated filer  o
Non-accelerated filer x	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 11, 2011, 15,294,153 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, 2011 and December 31, 2010	2
	Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2011 and 2010	3
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantatative and Qualitative Disclosures About Market Risk	56
Item 4.	Controls and Procedures	57
PART II—Other Information		58
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60
Item 3.	Defaults upon Senior Securities	60
Item 4.	[Removed and Reserved]	60
Item 5.	Other Information	60
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 appropriate under the circumstances. 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, 2010, (3) our reports and registration statements filed from time to time with the Securities and Exchange Commission and (4) other announcements we make from time to time. In addition, we may be subject to unforeseen risks that may have a materially adverse effect on us.  Accordingly no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements.

The forward-looking statements speak only as of the date made, and, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

PART I.—FINANCIAL INFORMATION

Item 1.    Financial Statements (Unaudited)

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(In thousands)

	June 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,278		$	76
Accounts receivable, net of allowance for doubtful accounts ($19 as of June 30, 2011 and December 31, 2010)	28,775			27,351
Inventories	18,430			15,635
Advance royalties, current portion	1,061			1,918
Prepaid expenses and other	5,987			5,376
Total current assets	56,531			50,356
PROPERTY, PLANT AND EQUIPMENT:
At cost, incl. coal properties, mine development and construction costs	596,640			442,112
Less accumulated depreciation, depletion and amortization	(175,843		)	(159,535		)
Net property, plant and equipment	420,797			282,577
Advance royalties, net of current portion	3,629			2,935
Investment in unconsolidated affiliate	19,339			18,749
Goodwill	202			202
Intangible assets	695			719
Other non-current assets	4,451			3,107
TOTAL	$	505,644		$	358,645
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	17,416		$	15,493
Accrued expenses and other	18,564			12,969
Current portion of long-term debt	2,930			2,908
Current portion of asset retirement obligations	5,359			4,350
Current portion of postretirement benefits	160			160
Total current liabilities	44,429			35,880
NON-CURRENT LIABILITIES:
Long-term debt	178,541			33,620
Asset retirement obligations	30,605			31,341
Other non-current liabilities	4,101			3,706
Postretirement benefits	6,839			6,481
Total non-current liabilities	220,086			75,148
Total liabilities	264,515			111,028
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners	230,221			236,582
General partner	10,283			10,410
Accumulated other comprehensive income	625			625
Total partners’ capital	241,129			247,617
TOTAL	$	505,644		$	358,645

 See notes to unaudited condensed consolidated financial statements.

2

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(In thousands, except per unit amounts)

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2011			2010			2011			2010
REVENUES:
Coal sales	$	83,819		$	74,094		$	162,379		$	136,736
Freight and handling revenues	1,439			1,005			2,570			1,947
Other revenues	4,619			3,329			7,683			6,348
Total revenues	89,877			78,428			172,632			145,031
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	67,432			57,840			128,473			104,192
Freight and handling costs	1,126			771			1,939			1,444
Depreciation, depletion and amortization	8,212			8,038			17,356			15,803
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	3,646			3,927			8,997			7,604
(Gain) loss on sale of assets—net	(45		)	(46		)	(134		)	(47		)
Total costs and expenses	80,371			70,530			156,631			128,996
INCOME FROM OPERATIONS	9,506			7,898			16,001			16,035
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense and other	(1,366		)	(1,310		)	(2,424		)	(2,781		)
Interest income and other	36			10			35			18
Equity in net income of unconsolidated affiliate	1,201			544			1,901			414
Total interest and other income (expense)	(129		)	(756		)	(488		)	(2,349		)
INCOME BEFORE INCOME TAXES	9,377			7,142			15,513			13,686
INCOME TAXES	—			—			—			—
NET INCOME & COMPREHENSIVE INCOME	$	9,377		$	7,142		$	15,513		$	13,686
General partner’s interest in net income	$	188					$	310
Common unitholders’ interest in net income	$	4,598					$	7,604
Subordinated unitholders’ interest in net income	$	4,591					$	7,599
Net income per limited partner unit, basic:
Common units	$	0.37					$	0.61
Subordinated units	$	0.37					$	0.61
Net income per limited partner unit, diluted:
Common units	$	0.37					$	0.61
Subordinated units	$	0.37					$	0.61
Distributions paid per limited partner unit	$	0.455					$	0.8758
Weighted average number of limited partner units outstanding, basic:
Common units	12,416						12,405
Subordinated units	12,397						12,397
Weighted average number of limited partner units outstanding, diluted:
Common units	12,434						12,429
Subordinated units	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 Ended			Six Months Ended
	June 30, 2011			June 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	15,513		$	13,686
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	17,356			15,803
Accretion on asset retirement obligations	979			1,085
Accretion on interest-free debt	104			98
Amortization of advance royalties	756			374
Amortization of debt issuance costs	510			—
Equity in net (income) of unconsolidated affiliate	(1,901		)	(414		)
Loss on retirement of advance royalties	79			113
(Gain) on sale of assets—net	(134		)	(47		)
Equity-based compensation	474			—
Changes in assets and liabilities:
Accounts receivable	1,042			2,000
Inventories	(2,795		)	(6,059		)
Advance royalties	(671		)	(897		)
Prepaid expenses and other assets	263			(697		)
Accounts payable	1,712			(1,703		)
Accrued expenses and other liabilities	1,610			2,053
Asset retirement obligations	(1,217		)	(866		)
Postretirement benefits	357			342
Net cash provided by operating activities	34,037			24,871
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(35,305		)	(11,440		)
Proceeds from sales of property, plant, and equipment	486			70
Principal payments received on notes receivable	1,720			98
Cash advances from issuance of notes receivable	(2,230		)	(255		)
Changes in restricted cash	—			(3		)
Acquisition of coal companies and other properties	(119,299		)	(58		)
Return of capital from unconsolidated affiliate	1,311			—
Net cash used in investing activities	(153,317		)	(11,588		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	217,000			45,950
Repayments on line of credit	(71,963		)	(59,732		)
Proceeds from issuance of long-term debt	1,379			—
Repayments on long-term debt	(1,577		)	—
Net settlement of employee withholding taxes on unit awards vested	(164		)
Debt issuance costs	(1,000		)	—
Partner contributions	6			—
Distributions to unitholders	(22,181		)	—
Payment of offering costs	(18		)	—
Net cash provided by (used in) financing activities	121,482			(13,782		)
NET INCREASE (DECREASE) CASH & CASH EQUIVALENTS	2,202			(499		)
CASH AND CASH EQUIVALENTS—Beginning of period	76			687
CASH AND CASH EQUIVALENTS—End of period	$	2,278		$	188

See notes to unaudited condensed consolidated financial statements.

4

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2011 AND DECEMBER 31, 2010 AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2011 AND 2010

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.

For income, expense and cash flow items for the three and six months ended June 30, 2010, the Partnership has disclosed figures of Rhino Energy LLC (the “Predecessor” or the “Operating Company”) as the Partnership had no operations during this period. The closing of the Partnership’s initial public offering (“IPO”) and the contribution of the membership interests in the Operating Company to the Partnership did not result in any basis change of the assets of the Predecessor as the Partnership and Predecessor were entities under common control and the Predecessor was contributed to the Partnership and continued operations in consistently the same manner after being contributed to the Partnership. For these reasons as well as year-to-year comparability of financial results, the income, expense and cash flow results of the Predecessor are presented for the three and six months ended June 30, 2010, as applicable.

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, 2011, condensed consolidated statements of operations for the three and six month periods ended June 30, 2011 and 2010 and the condensed consolidated statements of cash flows for the six months ended June 30, 2011 and 2010 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, 2010 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, 2010 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, 2010 filed with the SEC.

Organization—The Partnership is a Delaware limited partnership formed on April 19, 2010 to acquire the Predecessor, 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

5

Kentucky, Ohio, West Virginia, and Utah.  The Operating Company also has one underground mine located in Colorado that was temporarily idled at year-end 2010. The majority of the Operating Company’s sales are made to domestic utilities and other coal-related organizations in the United States. The Operating Company was formed in April 2003 and has been built via acquisitions.

Initial Public Offering

On October 5, 2010, the Partnership completed its IPO of 3,730,600 common units, representing limited partner interests in the Partnership, at a price of $20.50 per common unit. Of the common units issued, 486,600 units were issued in connection with the exercise of the underwriters’ option to purchase additional units. Net proceeds from the offering were approximately $71.3 million, after deducting underwriting discounts of approximately $5.2 million, of which approximately $62.0 million was received by the Partnership and approximately $9.3 million was paid directly to the Partnership’s sponsor, Wexford Capital LP (“Wexford Capital”), as reimbursement for capital expenditures incurred by affiliates of Wexford Capital with respect to the assets contributed to the Partnership in connection with the offering. The Partnership used the net proceeds from this offering, less offering expenses of approximately $3.0 million incurred at the IPO date, and a related capital contribution by Rhino GP LLC, the Partnership’s general partner (the “General Partner”) of approximately $10.4 million, to repay approximately $69.4 million of outstanding indebtedness under the Operating Company’s credit facility. The Partnership paid additional offering expenses after the IPO date of approximately $0.7 million for total offering expenses of approximately $3.7 million.

In connection with the closing of the IPO, the owners of the Operating Company contributed their membership interests in the Operating Company to the Partnership, and the Partnership issued 12,397,000 subordinated units representing limited partner interests in the Partnership and 8,666,400 common units to Rhino Energy Holdings LLC, an affiliate of Wexford Capital, and issued incentive distribution rights to the General Partner. Upon the closing of the IPO, and as required by the Operating Company’s credit agreement by and among the Operating Company, as borrower, and its subsidiaries as guarantors, and PNC Bank, National Association, as agent, and the other lenders thereto (as amended from time to time, the “Credit Agreement”), the Partnership pledged 100% of the membership interests in the Operating Company to the agent on behalf of itself and the other lenders to secure the Operating Company’s obligations under the Credit Agreement.

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. Equity method 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. When net losses from an equity method investment exceed its carrying amount, the investment balance is reduced to zero and additional losses are not provided for. The Partnership

6

resumes accounting for the investment under the equity method when the entity subsequently reports net income and the Partnership’s share of that net income exceeds the share of net losses not recognized during the period the equity method was suspended. Investments are written down 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 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’s exposure to potential losses the joint venture may incur is in proportion to the Partnership’s ownership interest in the joint venture. The Partnership considers the operations of this entity to comprise a reporting segment and has provided additional detail related to this operation in Note 18, “Segment Information.”

In the second of quarter of 2011, the Partnership issued a note to the joint venture for approximately $2.2 million. As of June 30, 2011, the joint venture had repaid approximately $1.7 million of this note leaving an outstanding balance of approximately $0.5 million as of June 30, 2011. The note receivable is recorded in Prepaid expenses and other on the Partnership’s unaudited condensed consolidated statements of financial position.

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 $119.5 million in cash consideration, or approximately $119.3 million net of cash acquired (referred to as the “Elk Horn Acquisition”). Elk Horn is a coal leasing company located in eastern Kentucky that is expected to provide the Partnership with mineral reserves and royalty revenues in future periods. The Partnership believes there is potential upside from this acquisition to be provided by Elk Horn’s currently unleased proven and probable reserves in Southern Floyd County, Kentucky (“Southern Floyd”).  The Partnership also believes there are additional synergies to this acquisition as a large portion of Elk Horn’s property is contiguous with the Partnership’s Deane complex property. The potential addition of infrastructure that would facilitate the increase of Southern Floyd production would also help accelerate development of the Partnership’s contiguous northern Deane complex properties.

The Elk Horn acquisition was initially funded with borrowings under the Partnership’s credit facility. As discussed in Subsequent Events footnote 19, 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:

7

	(in thousands)
Cash	$	197
Accounts receivable	2,466
Prepaid expenses and other	95
Property, plant and equipment (incl coal properties)	119,635
Other non-current assets	1,124
Accounts payable	(211		)
Accrued expenses and other	(3,299		)
Asset retirement obligations	(511		)
Assets acquired	119,496
Total consideration	$	119,496

Although the responsibility of valuation remains with the Partnership’s management, the determination of the fair values of the various assets and liabilities acquired will be 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, the coal properties and any potential intangible assets acquired are not yet complete due to the extended amount of time required to complete these activities and the values listed in the table above for these items are the Partnership’s estimates of fair value at this time. Any change to the acquisition date value of the identifiable net assets during the measurement period (up to one year from the acquisition date) will affect the amount of the purchase price allocated and may result in the recognition of goodwill or a gain on the acquisition. Subsequent changes to the purchase price allocation will be adjusted retroactively if material to the Partnership’s consolidated financial results.

The fair value of accounts receivable approximates its carrying value of $2.5 million. The gross amount due from customers is $3.4 million, of which $0.9 million is estimated to be uncollectible due to the bankruptcy of one customer in late 2010.

Accrued expenses and other liabilities of $3.3 million assumed in the Elk Horn transaction consisted mostly of liabilities for unearned revenue related to advance royalty payments received from customers. The liabilities assumed at the acquisition date did not consist of any contingent liabilities that would result in future adjustments to the purchase price allocation.

The acquisition of Elk Horn is included in Acquisition of coal companies and other properties in the investing section of the condensed consolidated statements of cash flows. Of the total purchase price, approximately $6.1 million has been placed in escrow for a period of 12 months to secure indemnification obligations of Elk Horn and its former ownership members relating to the accuracy of representations and warranties, as well as potential adjustments related to working capital. The acquisition consideration held in escrow does not meet the definition of contingent consideration as provided under the accounting guidance for business combinations. The amount held in escrow was included in the acquisition accounting as part of the

8

consideration transferred by the Partnership as representations and warranties were expected to be valid as of the acquisition date.

Acquisition-related costs incurred in the second quarter for the Elk Horn acquisition were immaterial.

The Partnership’s unaudited condensed consolidated statements of operations and comprehensive income do not include revenue, costs or earnings from Elk Horn prior to June 10, 2011, the effective date of the acquisition. The post-acquisition revenue and net earnings of Elk Horn that is included in the Partnership’s results was approximately $1.0 million and $0.5 million, respectively, for the three and six months ended June 30, 2011.

The following table presents selected unaudited pro forma financial information for the three and six months ended June 30, 2011 and 2010, as if the acquisition had occurred on January 1, 2010. 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 certain pro forma items that are directly attributable to the acquisition and are expected to have a continuing impact on financial results.  These pro forma adjustment items include increased depletion expense related to the anticipated 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 and additional common units issued from the public offering completed in July 2011, as discussed in Footnote 19. Supplemental pro forma revenue, net earnings and earnings per unit disclosures are as follows.

	Three months ended June 30,					Six months ended June 30,
	2011			2010		2011		2010
	(in thousands)
Revenues:
As reported	$	89,877		$	78,428	$	172,632	$	145,031
Pro forma adjustments	3,419			2,054		9,477		3,450
Pro forma revenues	$	93,296		$	80,482	$	182,109	$	148,481
Net Income:
As reported	$	9,377		$	7,142	$	15,513	$	13,686
Pro forma adjustments	258			47		2,511		(88		)
Pro forma net income	$	9,635		$	7,189	$	18,024	$	13,598
Net income per limited partner unit, diluted:
As reported	$	0.37		n/a		$	0.61	n/a
Pro forma adjustments	$	(0.03	)	n/a		$	0.03	n/a
Pro forma net income	$	0.34		n/a		$	0.64	n/a

9

Acquisition of Oil and Gas Mineral Rights

During the three and six months ended June 30, 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 $2.7 million and approximately $5.8 million, respectively. The Partnership expects royalty revenues to be generated from these mineral rights in future periods.

The Partnership and an affiliate of Wexford Capital are participating with Gulfport Energy, a publicly traded company, in the acquisition of a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately 18% of the common stock of Gulfport Energy as of March 31, 2011. In the second quarter of 2011, the Partnership purchased approximately a $7.0 million interest in a portfolio of leases and in July 2011, the Partnership purchased an additional approximately $10.1 million interest in a portfolio of leases, bringing its total investment to approximately $17.1 million.  The Partnership expects to participate in additional acquisitions of leases for an aggregate amount not to exceed $40 million, which includes the Partnership’s proportionate share of future drilling costs. Drilling is expected to begin on these properties in late 2011. The Partnership is expected to fund its share of drilling costs through a portion of the cash flow generated by such leases. The Partnership expects royalty revenues to be generated from these mineral rights in future periods.

Acquisition of Coal Property

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 plans to fully explore these properties and intends to confirm additional mineable underground metallurgical coal reserves and eventually commence production.

Acquisition of the C.W. Mining Company

In August 2010, the Predecessor acquired certain assets for cash consideration of approximately $15.0 million from the Trustee of the Federal Bankruptcy Court charged with the sale of the C. W. Mining Company assets. These assets are located in Emery and Carbon Counties, Utah. Prior to the purchase of the assets, the Operating Company formed a new wholly owned subsidiary, Castle Valley Mining LLC (“Castle Valley”).  Castle Valley in turn acquired the following assets and liabilities (of the former C.W. Mining Company) from the Operating Company:

·the Coal Operating Agreement whereby Castle Valley becomes a sub-lessee of certain federal coal leases owned by the Bureau of Land Management;

·buildings, mining equipment, conveyor belts and belt structure, a truck loading facility and other mining assets; and

·reclamation or “end of mine” liabilities.

10

The Partnership staffed the location and rehabilitated the mine and equipment and began production from these assets at one underground mine in the first quarter of 2011. The coal produced and sold from these mining assets is being sold as steam coal.

The Partnership allocated the purchase price of $15.0 million to the assets and liabilities acquired based upon their respective fair values in accordance with Accounting Standards Codification (“ASC”) Topic 805. The fair value of the assets acquired and liabilities assumed in this transaction are as follows:

	(in thousands)
Mining and other equipment & related facilities	$	8,689
Asset retirement costs	933
Coal properties	17,100
Asset retirement obligation liability assumed	(933		)
Net assets acquired	25,789
Gain on bargain purchase	(10,789		)
Total consideration	$	15,000

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. Because the fair value of the assets acquired exceeded the purchase price, the Partnership recorded a gain of $10.8 million in the third quarter of 2010. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy.

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of June 30, 2011 and December 31, 2010 consisted of the following:

	June 30,		December 31,
	2011		2010
	(in thousands)
Other prepaid expenses	$	857	$	929
Notes receivable	510		—
Deferred offering costs	35		—
Prepaid insurance	2,915		3,239
Prepaid leases	84		82
Supply inventory	1,416		956
Deposits	170		170
Total	$	5,987	$	5,376

11

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of June 30, 2011 and December 31, 2010 are summarized by major classification as follows:

	Useful Lives	June 30, 2011			December 31, 2010
		(in thousands)
Land and Land Improvements		$	32,053		$	25,748
Mining and other equipment and related facilities	2 - 20 Years	224,969			218,886
Mine development costs	1 - 15 Years	60,106			56,857
Coal properties	1 - 15 Years	265,701			132,431
Construction work in process		13,811			8,190
Total		596,640			442,112
Less accumulated depreciation, depletion and amortization		(175,843		)	(159,535		)
Net		$	420,797		$	282,577

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, 2011 and 2010 were as follows:

	Three months ended June 30,					Six months ended June 30,
	2011			2010		2011		2010
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	6,545		$	6,832	$	13,281	$	13,435
Depletion expense for coal properties	978			517		1,849		971
Amortization expense for mine development costs	801			423		1,549		834
Amortization expense for intangible assets	12			12		23		63
Amortization expense for asset retirement costs	(124		)	254		654		500
Total depreciation, depletion and amortization	$	8,212		$	8,038	$	17,356	$	15,803

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. The Partnership has included goodwill in its Other category, as described in Note 18, “Segment Information”, for segment reporting purposes.

Goodwill as of June 30, 2011 and December 31, 2010 consisted of the following:

12

June 30,		December 31,
2011		2010
(in thousands)
$	202	$	202

Intangible assets as of June 30, 2011 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	100	$	628
Developed Technology	78		11		67
Total	$	806	$	111	$	695

Intangible assets as of December 31, 2010 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	79	$	649
Developed Technology	78		8		70
Total	$	806	$	87	$	719

The Partnership considers these intangible assets to have a useful life of seventeen years. The intangible assets are amortized over their useful life on a straight line basis.

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, 2011:

			Developed
	Patent		Technology		Total
	(in thousands)
2011 (from July 1 to December 31)	$	22	$	2	$	24
2012	43		5		48
2013	43		5		48
2014	43		5		48
2015	43		5		48

13

7. OTHER NON-CURRENT ASSETS

Other non-current assets as of June 30, 2011 and December 31, 2010 consisted of the following:

	June 30,		December 31,
	2011		2010
	(in thousands)
Deposits and other	$	1,704	$	840
Debt issuance costs—net	2,700		2,211
Deferred expenses	47		56
Total	$	4,451	$	3,107

Debt issuance costs were approximately $5.3 million and approximately $4.3 million as of June 30, 2011 and December 31, 2010, respectively. Accumulated amortization of debt issuance costs were approximately $2.6 million and approximately $2.1 million as of June 30, 2011 and December 31, 2010, respectively.

8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of June 30, 2011 and December 31, 2010 consisted of the following:

	June 30,		December 31,
	2011		2010
	(in thousands)
Payroll, bonus and vacation expense	$	4,334	$	3,570
Non income taxes	3,418		3,020
Royalty expenses	2,423		2,184
Accrued interest	786		460
Health claims	2,226		2,046
Workers’ compensation & pneumoconiosis	1,400		1,400
Deferred revenues	2,542		—
Other	1,435		289
Total	$	18,564	$	12,969

14

9. DEBT

Debt as of June 30, 2011 and December 31, 2010 consisted of the following:

	June 30,			December 31,
	2011			2010
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$	173,510		$	28,470
Note payable to H&L Construction Co., Inc.	2,633			2,973
Other notes payable	5,328			5,085
Total	181,471			36,528
Less current portion	(2,930		)	(2,908		)
Long-term debt	$	178,541		$	33,620

Senior Secured Credit Facility with PNC Bank, N.A.—The 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 discussed earlier. As part of exercising this option to increase the available amount under the credit agreement, the 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 and in Cash flows from financing activities in the Partnership’s unaudited condensed consolidated statements of cash flows.

Borrowings under the line of credit bear interest which varies depending upon the grouping of the borrowings within the line of credit. At June 30, 2011, the Operating Company had borrowed $165.0 million at a variable interest rate of LIBOR plus 3.00% (3.19% at June 30, 2011) and an additional $8.5 million at a variable interest rate of PRIME plus 1.50% (4.75% at June 30, 2011). In addition, the Operating Company had outstanding letters of credit of $24.7 million at a fixed interest rate of 3.00% at June 30, 2011. The credit agreement expires in February 2013. At June 30, 2011, the Operating Company had not used $51.8 million of the borrowing availability. As part of the agreement, the Operating Company is required to pay a commitment fee of 0.5% on the unused portion of the borrowing availability. Borrowings on the line of credit are collateralized by all the unsecured assets of the Partnership.

The revolving credit commitment 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, selling or assigning stock. The Partnership was in compliance with all covenants contained in the credit agreement as of and for the period ended June 30, 2011.

15

On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility. See Note 19 for more details of the amended and restated credit facility.

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 balance of this note was approximately $2.6 million as of June 30, 2011 and the note is secured by mineral rights purchased by the Partnership from H&L Construction Co., Inc. These mineral rights had a carrying amount of approximately $11.7 million and approximately $11.8 million as of June 30, 2011 and December 31, 2010, respectively.

10. ASSET RETIREMENT OBLIGATIONS

The changes in asset retirement obligations for the six months ended June 30, 2011 and the year ended December 31, 2010 are as follows:

	Six months ended June 30, 2011			Year ended December 31, 2010
	(in thousands)
Balance at beginning of period (including current portion)	$	35,691		$	45,101
Accretion expense	979			2,165
Adjustment resulting from addition of property	511			933
Adjustments to the liability from annual recosting and other	—			(10,202		)
Liabilities settled	(1,217		)	(2,306		)
Balance at end of period	35,964			35,691
Current portion of asset retirement obligation	5,359			4,350
Long-term portion of asset retirement obligation	$	30,605		$	31,341

11. EMPLOYEE BENEFITS

Net periodic benefit cost for the three and six months ended June 30, 2011 and 2010 are as follows:

	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service costs	$	116	$	106	$	233	$	214
Interest cost	74		69		148		136
Amortization of (gain)	—		—		—		—
Total	$	190	$	175	$	381	$	350

401(k) Plans—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the

16

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, 2011 and 2010 was as follows:

	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
	(in thousands)
401(k) plan expense	$	548	$	484	$	1,068	$	976

12. EQUITY-BASED COMPENSATION

In October 2010, the General Partner adopted 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, 2011, the General Partner granted phantom units to certain of the Partnership’s employees and restricted units and unit awards to its directors. These grants were made in connection with the IPO completed in October 2010.

With the vesting of the first portion of the employees’ 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 from December 31, 2010 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.  The Partnership recorded approximately $0.1 million and $0.2 million in incremental compensation expense for the three and six months ended June 30, 2011, respectively, due to the modification of these awards. The equity balance of approximately $0.2 million accrued as of December 31, 2010 for the non-vested awards was also reclassified from the Limited partners’ capital account to Accrued expenses and other in the current liability portion in the unaudited condensed consolidated statement of financial position as of June 30, 2011.

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of June 30, 2011, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of approximately 2.3 million, approximately 3.0 million, approximately 1.9 million and approximately 0.5 million tons of coal to 20 customers for the remainder of 2011, 6 customers in 2012, 3 customers in 2013 and 1 customer in 2014, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

17

Purchase Commitments—As of June 30, 2011, the Partnership had approximately 2.0 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2011 for approximately $5.3 million. In the second quarter of 2011, the Partnership entered into additional commitments to purchase diesel fuel at fixed prices from January through December 2012 for a total of approximately 4.0 million gallons for approximately $14.0 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”). Purchase coal expense from coal purchase contracts and expense from OTC purchases for the three and six months ended June 30, 2011 and 2010 were as follows:

	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
	(in thousands)
Purchased coal expense	$	1,562	$	1,522	$	4,885	$	1,820
OTC expense	$	—	$	2,136	$	14	$	2,116

There were no outstanding coal purchase commitments as of June 30, 2011.

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, 2011 and 2010 was as follows:

	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
	(in thousands)
Lease expense	$	642	$	1,460	$	1,317	$	3,087
Royalty expense	$	3,915	$	3,447	$	7,752	$	6,201

Joint Venture—Pursuant to the joint venture agreement with Patriot, the Partnership is required to contribute additional capital to assist in funding the development and operations of the joint venture. During the three and six months ended June 30, 2011 and 2010, the Partnership did not make any capital contributions. The Partnership may be required to contribute additional capital to the joint venture in subsequent periods.

18

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 three and six month periods ended June 30, 2011:

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
	2011		ended		ended
	Receivable		June 30,		June 30,
	Balance		2011 Sales		2010 Sales
	(in thousands)
GenOn Energy, Inc. (fka Mirant Corporation)	$	3,363	$	26,484	$	17,352
Indiana Harbor Coke Company, L.P	2,782		18,602		25,461
American Electric Power Company, Inc.	4,889		24,586		17,429

19

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 carrying value of the Partnership’s debt instruments and notes receivable approximate fair value since effective rates for these instruments are comparable to market at June 30, 2011.

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

The unaudited condensed consolidated statement of cash flows for the six months ended June 30, 2011 excludes approximately $1.0 million of property additions, which are recorded in accounts payable.

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 at year-end 2010. The Partnership sells primarily to electric utilities in the United States. In addition, with the acquisition of Elk Horn mentioned earlier, the Partnership also leases coal reserves to third parties in exchange for royalty revenues. For the three and six months ended June 30, 2011, the Partnership has four reportable business 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. Within the Central Appalachia, Northern Appalachia and Rhino Western reporting segments, the Partnership has aggregated operating segments that have similar geography and similar economic characteristics in terms of product sold, product quality and end customers. Within the Central Appalachia reporting segment, the Partnership has aggregated four operating segments representing its three mining complexes located in Eastern Kentucky and Southern West Virginia and the Elk Horn operations.  In the Northern Appalachia reporting segment, the Partnership has aggregated two operating segments representing its Sands Hill mining complex and its Hopedale mining complex.  In the Rhino Western reporting segment, the Partnership has aggregated two operating segments representing its Colorado mine, which was temporarily idled at year-end 2010, and its Utah mining complex. 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.

In interim periods for 2010, prior to reporting full-year December 31, 2010 results, the Partnership had included its Colorado mine in the Other category since this operation did not meet the quantitative thresholds requiring separate disclosure as a reportable segment. With the acquisition of the Utah mining complex in August 2010, the Partnership began to aggregate the Colorado mine and Utah mining complex as one reportable segment as discussed above. For

20

comparability purposes, the segment data for previous interim periods has been reclassified to present the results of the Colorado mine in the Rhino Western segment instead of the Other category.

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

Reportable segment results of operations for the three months ended June 30, 2011 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			Segments
	(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 three months ended June 30, 2010 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	$	51,668	$	22,680	$	2,356	$	8,255	$	(8,255	)	$	—	$	1,724		$	78,428
DD&A	4,821		2,098		105		790		(790		)	—		1,014			8,038
Interest expense	595		484		45		22		(22		)	—		186			1,310
Net Income (loss)	$	5,469	$	2,044	$	378	$	1,066	$	(522	)	$	544	$	(1,293	)	$	7,142

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

21

Reportable segment results of operations for the six months ended June 30, 2010 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	$	90,258	$	46,681	$	4,805	$	13,676	$	(13,676	)	$	—	$	3,287		$	145,031
DD&A	9,514		3,974		236		1,541		(1,541		)	—		2,079			15,803
Interest expense	1,222		1,065		107		39		(39		)	—		387			2,781
Net Income (loss)	$	10,203	$	4,626	$	1,000	$	812	$	(398	)	$	414	$	(2,557	)	$	13,686

19. SUBSEQUENT EVENTS

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 estimated offering expenses of approximately $4.0 million. The Partnership used the net proceeds from this offering, and a related capital contribution by the General Partner of approximately $1.4 million, to repay approximately $67.8 million of outstanding indebtedness under the Partnership’s credit facility.

On July 25, 2011, the Partnership announced a cash distribution of $0.455 per common unit and subordinated unit, or $1.82 per unit on an annualized basis. This distribution was paid on August 12, 2011 to all unitholders of record as of the close of business on August 4, 2011.

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 line of credit are collateralized by all the unsecured assets of the Partnership. The revolving credit commitment 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 credit agreement expires in July 2016.

22

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 “Rhino Predecessor,” “we,” “our,” “us” or similar terms when used in a historical context refer to Rhino Energy LLC and its subsidiaries, which have been recently contributed to Rhino Resource Partners LP  in connection with its initial public offering, which was completed on October 5, 2010 (the “IPO”).  When used in the present tense or prospectively, those 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.

For ease and comparability purposes in comparing 2011 to 2010 results, the results of Rhino Resource Partners LP and Rhino Energy LLC for 2010 have been combined as if Rhino Resource Partners LP was in existence for the entirety of 2010. Since Rhino Resource Partners LP maintained the historical basis of the Rhino Predecessor’s net assets, management believes that the combined Rhino Resource Partners LP and Rhino Predecessor results for 2011 are comparable with 2010. 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, 2010 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2010 included in our 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 entitled “Cautionary Note Regarding Forward- Looking Statements” in this Form 10-Q.

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 such management and leasing activities.

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, 2010, we controlled an estimated 309.0 million tons of proven and probable coal reserves, consisting of an estimated 297.0 million tons of steam coal and an estimated 12.0 million tons of metallurgical coal. In addition, as of December 31, 2010, we controlled an estimated 271.8 million tons of non-reserve coal deposits. As of December 31, 2010, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 22.2 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of

23

premium mid-vol and low-vol metallurgical coal, and an estimated 34.3 million tons of non-reserve coal deposits. Our and the joint venture’s proven and probable coal reserves and non-reserve coal deposits were the same in all material respects as of December 31, 2010. As of June 30, 2011, we operated eleven mines, including six underground and five surface mines, located in Kentucky, Ohio, West Virginia and Utah. In addition, the joint venture operated one underground mine in West Virginia. During 2010, we operated one underground mine in Colorado, but we temporarily idled this mine at year end 2010. The number of mines that we operate may vary from time to time depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

Our principal business strategy is to safely, efficiently and profitably produce, 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 by, for example, serving as a natural hedge to help mitigate our exposure to certain operating costs, such as diesel fuel, steel products and other commodities consumed in the mining process.

For the three and six months ended June 30, 2011, we generated revenues of approximately $89.9 million and approximately $172.6 million, respectively, and net income of approximately $9.4 million and approximately $15.5 million, respectively. Excluding results from the joint venture, for the three and six months ended June 30, 2011, we produced approximately 1.2 million tons and approximately 2.4 million tons of coal, respectively, and sold approximately 1.2 million tons and approximately 2.3 million tons of coal, respectively, approximately 81% of which were pursuant to supply contracts for both periods. Additionally, the joint venture produced and sold approximately 0.1 million tons of premium mid-vol metallurgical coal for the three and six months ended June 30, 2011.

Recent Developments

Acquisitions

Acquisition of The Elk Horn Coal Company, LLC

In June 2011, we completed the acquisition of 100% of the ownership interests in The Elk Horn Coal Company, LLC (“Elk Horn”) for approximately $119.5 million in cash consideration, or approximately $119.3 million net of cash acquired. Elk Horn is a coal leasing company located in eastern Kentucky that is expected to provide us with mineral reserves and royalty revenues in future periods. We believe there is potential upside from this acquisition to be provided by Elk Horn’s currently unleased proven and probable reserves in Southern Floyd County, Kentucky (“Southern Floyd”). We also believe there are additional synergies to this acquisition as a large portion of Elk Horn’s property is contiguous with our Deane complex property and the potential addition of infrastructure that would facilitate the increase of Southern Floyd production would also help accelerate development of our contiguous northern Deane

24

complex properties. The Elk Horn acquisition was funded with borrowings available under our credit facility.

Acquisition of Oil and Gas Mineral Rights

During the three and six months ended June 30, 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 $2.7 million and approximately $5.8 million, respectively. We expect royalty revenues to be generated from these mineral rights in future periods.

We and an affiliate of Wexford Capital are participating with Gulfport Energy, a publicly traded company, to acquire a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately 18% of the common stock of Gulfport Energy. In the second quarter of 2011, we purchased approximately a $7.0 million interest in a portfolio of leases and in July 2011, we purchased approximately an additional $10.1 million interest in a portfolio of leases, bringing its total investment to approximately $17.1 million.  We expect to participate in additional acquisitions of leases for an aggregate amount not to exceed $40 million, which includes our proportionate share of future drilling costs. Drilling is expected to begin on these properties in late 2011. We expect to fund our share of drilling costs through a portion of the cash flow generated by such leases. We expect royalty revenues to be generated from these mineral rights in future periods.

We believe income from the Cana Woodford and Utica Shale investments will provide a natural hedge against our own hydrocarbon needs and will help to diversify our income stream.

Acquisition of Coal Property

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 C.W. Mining Company

In August 2010, we acquired certain mining assets of C.W. Mining Company out of bankruptcy (the “Castle Valley Acquisition”) for cash consideration of approximately $15.0 million. The assets acquired are located in Emery and Carbon Counties, Utah and include coal reserves and non-reserve coal deposits, underground mining equipment and infrastructure, an overland belt conveyor system, a loading facility and support facilities. Production from these assets began at one underground mine in January 2011 and the steam coal produced is being sold into the utility and industrial markets.

Initial Public Offering

On October 5, 2010, we completed our IPO, in which we sold an aggregate of 3,730,600 common units, representing limited partner interests in us, at a price of $20.50 per common unit.

25

Of the common units issued, 486,600 units were issued in connection with the exercise of the underwriters’ option to purchase additional units. Net proceeds from the offering were approximately $71.3 million, after deducting underwriting discounts of approximately $5.2 million, of which approximately $62.0 million was received by us and approximately $9.3 million was paid directly to our sponsor, Wexford Capital LP (“Wexford Capital”), as reimbursement for capital expenditures incurred by affiliates of Wexford Capital with respect to the assets contributed to us in connection with the offering. We used the net proceeds from this offering, less offering expenses of approximately $3.0 million incurred at the IPO date, and a related capital contribution by our general partner of approximately $10.4 million, to repay approximately $69.4 million of outstanding indebtedness under our credit facility. We paid additional offering expenses after the IPO date of approximately $0.7 million for total offering expenses of approximately $3.7 million.

In connection with the closing of the IPO, the owners of Rhino Energy LLC contributed their membership interests in Rhino Energy LLC to us, and we issued 12,397,000 subordinated units representing limited partner interests in us and 8,666,400 common units to Rhino Energy Holdings LLC, an affiliate of Wexford Capital, and issued incentive distribution rights to our general partner.

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 $66.4 million, after deducting underwriting discounts and estimated offering expenses of approximately $4.0 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

In connection with our IPO, we amended our credit agreement to revise certain restrictive provisions, allow for the equity transfer of Rhino Energy LLC to us in the event of a successful IPO and provide for quarterly cash distributions of available cash, as that term is defined in our partnership agreement. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.”

On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of 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, we are 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

26

the line of credit are collateralized by all of our unsecured assets. The revolving credit commitment requires that we 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 credit agreement expires in July 2016.

Factors That Impact Our Business

Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems at mining locations, (4) the availability of transportation for coal shipments or (5) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives.

On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation, (2) the availability and prices of competing electricity-generation fuels, (3) our ability to secure or acquire high-quality coal reserves and (4) our ability to find buyers for coal under favorable supply contracts.

We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of June 30, 2011, we had commitments under sales contracts to deliver annually scheduled base quantities of approximately 2.3 million, approximately 3.0 million, approximately 1.9 million and approximately 0.5 million tons of coal to 20 customers for the remainder of 2011, 6 customers in 2012, 3 customers in 2013 and 1 customer in 2014, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

Results of Operations

Segment Information

We conduct business through four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Eastern Met. 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, as of June 30, 2011, together included four underground mines, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. Additionally, we have aggregated the Elk Horn operations with our Central Appalachia segment. 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 southern Ohio, included one underground mine and one preparation plant and loadout facility as of June 30, 2011. Our Sands Hill mining complex, located in northern Ohio, included two surface mines, a preparation plant and a river terminal as of June 30, 2011. Our Rhino Western segment includes our two underground mines in the Western Bituminous region. One of these underground mines, our McClane Canyon mine in Colorado, was temporarily idled at the end of 2010 and our Castle Valley mining complex in Utah began production in January 2011. The Eastern Met segment includes our 51% equity interest in the results of operations of the joint venture, which owns the

27

Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. As of June 30, 2011, this complex was comprised of one underground mine and a preparation plant and loadout facility owned by our joint venture partner. Our Other category includes our roof bolt manufacturing operation, limestone operations and various businesses that provide support services such as reclamation, maintenance and transportation, the costs of which are reflected in our cost of operations.

Evaluating Our Results of Operations

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

EBITDA.  The discussion of our results of operations below includes references to, and analysis of, our segments’ EBITDA results. EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used by management primarily as a measure of our segments’ operating performance. EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Because not all companies calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. Please read “—Reconciliation of EBITDA to Net Income by Segment” for reconciliations of EBITDA to net income 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.

28

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, 2011 and 2010:

	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
	(in millions)
Statement of Operations Data:
Total revenues	$	89.9		$	78.4		$	172.6		$	145.0
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	67.4			57.8			128.5			104.2
Freight and handling costs	1.1			0.8			1.9			1.4
Depreciation, depletion and amortization	8.2			8.0			17.4			15.8
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	3.7			3.9			8.9			7.6
(Gain) loss on sale of assets	—			—			(0.1		)	—
Income from operations	9.5			7.9			16.0			16.0
Interest and other income (expense):
Interest expense	(1.4		)	(1.3		)	(2.4		)	(2.8		)
Interest income	0.1			—			—			0.1
Equity in net income (loss) of unconsolidated affiliate	1.2			0.5			1.9			0.4
Total interest and other income (expense)	(0.1		)	(0.8		)	(0.5		)	(2.3		)
Net income	$	9.4		$	7.1		$	15.5		$	13.7
Other Financial Data
EBITDA	$	19.0		$	16.5		$	35.3		$	32.3

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Summary.  For the three months ended June 30, 2011, our total revenues increased to $89.9 million from $78.4 million for the three months ended June 30, 2010. We sold 1.2 million tons of coal for the three months ended June 30, 2011, which is 0.1 million tons greater, or a 10.1% increase, than the 1.1 million tons of coal sold for the three months ended June 30, 2010. This increase was the result of increased production at our Castle Valley operation in Utah, partially offset by the idling of our McClane Canyon mine in Colorado.

Net income and EBITDA increased for the three months ended June 30, 2011 from the three months ended June 30, 2010.  Net income was approximately $9.4 million for the three months ended June 30, 2011 compared to approximately $7.1 million for the three months ended June 30, 2010 due to higher revenues from increased tons sold as well as increased contract prices for steam coal, partially offset by higher costs and expenses. Net income was also positively impacted period to period due to $1.2 million of income from our Rhino Eastern joint venture for the three months ended June 30, 2011 compared to income of $0.5 million for the three months ended June 30, 2010, 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.

29

EBITDA increased to $19.0 million for the three months ended June 30, 2011 from $16.5 million for the three months ended June 30, 2010. EBITDA increased period to period primarily due to increased net income, which includes the positive 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, 2011 and 2010:

	Three months	Three months	Increase/
	ended	ended	(Decrease)
Segment	June 30, 2011	June 30, 2010	Tons	% *
	(in millions, except %)
Central Appalachia	0.6	0.6	—	4.0	%
Northern Appalachia	0.5	0.5	—	6.5	%
Rhino Western	0.1	0.1	—	105.4	%
Total *†	1.2	1.1	0.1	10.1	%

*Percentages are calculated based on actual amounts and not the rounded amounts presented in this table.  Totals may not foot due to rounding.

†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 1.2 million tons of coal in the three months ended June 30, 2011 as compared to approximately 1.1 million tons sold in the three months ended June 30, 2010. This increase in tons sold was primarily due to increased production at our Castle Valley operation in Utah, partially offset by the idling of our McClane Canyon mine in Colorado. Tons of coal sold in our Central Appalachia and Northern Appalachia segments remained constant at approximately 0.6 million tons and approximately 0.5 million tons, respectively, for both the three months ended June 30, 2011 and 2010. Coal sales from our Rhino Western segment also remained constant at approximately 0.1 million tons for the three months ended June 30, 2011 and 2010, but increased 105.4% based upon whole numbers due to the increased production at Castle Valley.

30

Revenues.  The following table presents revenues and coal revenues per ton by reportable segment for the three months ended June 30, 2011 and 2010:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2011		June 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	53.1	$	51.3	$	1.8		3.4	%
Freight and handling revenues	—		—		—			n/a
Other revenues	1.7		0.3		1.4			453.0	%
Total revenues	$	54.8	$	51.6	$	3.2		6.1	%
Coal revenues per ton*	$	89.59	$	90.07	$	(0.48	)	(0.5	)%
Northern Appalachia
Coal revenues	$	26.0	$	20.4	$	5.6		27.6	%
Freight and handling revenues	1.5		1.0		0.5			43.2	%
Other revenues	1.3		1.3		—			(2.8	)%
Total revenues	$	28.8	$	22.7	$	6.1		26.6	%
Coal revenues per ton*	$	52.13	$	43.50	$	8.63		19.8	%
Rhino Western
Coal revenues	$	4.7	$	2.4	$	2.3		99.1	%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	4.7	$	2.4	$	2.3		99.1	%
Coal revenues per ton*	$	42.32	$	43.66	$	(1.34	)	(3.1	)%
Other**
Coal revenues	n/a		n/a		n/a			n/a
Freight and handling revenues	n/a		n/a		n/a			n/a
Other revenues	1.6		1.7		(0.1		)	(4.6	)%
Total revenues	$	1.6	$	1.7	$	(0.1	)	(4.6	)%
Coal revenues per ton	n/a		n/a		n/a			n/a
Total
Coal revenues	$	83.8	$	74.1	$	9.7		13.1	%
Freight and handling revenues	1.5		1.0		0.5			43.2	%
Other revenues	4.6		3.3		1.3			38.7	%
Total revenues	$	89.9	$	78.4	$	11.5		14.6	%
Coal revenues per ton*	$	69.70	$	67.81	$	1.89		2.8	%

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

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

Our coal revenues for the three months ended June 30, 2011 increased by approximately $9.7 million, or 13.1%, to approximately $83.8 million from approximately $74.1 million for the three months ended June 30, 2010. The increase in coal revenues was due to increased volume in tons sold as well as higher contracted and spot prices for steam coal. Coal revenues per ton were

31

$69.70 for the three months ended June 30, 2011, an increase of $1.89, or 2.8%, from $67.81 per ton for the three months ended June 30, 2010. This increase in coal revenues per ton was primarily the result of higher contracted and spot prices for steam coal.

For our Central Appalachia segment, coal revenues increased by approximately $1.8 million, or 3.4%, to approximately $53.1 million for the three months ended June 30, 2011 from approximately $51.3 million for the three months ended June 30, 2010 due to increased volume in tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $0.48, or 0.5%, to $89.59 per ton for the three months ended June 30, 2011 as compared to $90.07 for the three months ended June 30, 2010, due to lower contracted prices, primarily related to metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to approximately $1.0 million of coal leasing revenue from Elk Horn.

For our Northern Appalachia segment, coal revenues were approximately $26.0 million for the three months ended June 30, 2011, an increase of approximately $5.6 million, or 27.6%, from approximately $20.4 million for the three months ended June 30, 2010, as a result of higher contracted and spot prices for steam coal as well as higher volumes of tons sold. Coal revenues per ton for our Northern Appalachia segment increased by $8.63, or 19.8%, to $52.13 per ton for the three months ended June 30, 2011 as compared to $43.50 per ton for the three months ended June 30, 2010. This increase was primarily due to higher contracted and spot prices for steam coal.

For our Rhino Western segment, coal revenues increased by approximately $2.3 million, or 99.1%, to approximately $4.7 million for the three months ended June 30, 2011 from approximately $2.4 million for the three months ended June 30, 2010, as a result of the increased production at our Castle Valley complex. Coal revenues per ton for our Rhino Western segment were $42.32 for the three months ended June 30, 2011, a decrease of $1.34, or 3.1%, from $43.66 for the three months ended June 30, 2010. The decrease in coal revenues per ton was due to lower market prices for coal produced at Castle Valley compared to coal sold from our McClane Canyon mine in 2010.

Other revenues for our Other category were relatively flat period to period at approximately $1.6 million for the three months ended June 30, 2011 compared to approximately $1.7 million for the three months ended June 30, 2010.

32

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, 2011		Three months ended June 30, 2010		Increase (Decrease) %*
Met coal tons sold	194.7		171.1		13.8	%
Steam coal tons sold	398.3		399.1		(0.2	)%
Total tons sold †	593.0		570.2		4.0	%
Met coal revenue	$	23,419	$	22,615	3.6	%
Steam coal revenue	$	29,706	$	28,743	3.4	%
Total coal revenue †	$	53,125	$	51,358	3.4	%
Met coal revenues per ton	$	120.27	$	132.18	(9.0	)%
Steam coal revenues per ton	$	74.60	$	72.02	3.6	%
Total coal revenues per ton †	$	89.59	$	90.07	(0.5	)%
Met coal tons produced	161.8		208.2		(22.3	)%
Steam coal tons produced	380.4		374.9		1.5	%
Total tons produced †	542.2		583.1		(7.0	)%

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

33

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, 2011 and 2010:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2011		June 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	41.0	$	36.3	$	4.7		12.9	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	4.7		4.8		(0.1		)	(1.3	)%
Selling, general and administrative	3.3		3.7		(0.4		)	(11.3	)%
Cost of operations per ton*	$	69.19	$	63.74	$	5.45		8.6	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	18.1	$	16.0	$	2.1		12.6	%
Freight and handling costs	1.1		0.8		0.3			46.1	%
Depreciation, depletion and amortization	2.0		2.1		(0.1		)	(3.2	)%
Selling, general and administrative	0.1		0.1		—			(8.9	)%
Cost of operations per ton*	$	36.18	$	34.22	$	1.96		5.7	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	4.0	$	1.7	$	2.3		139.6	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	0.7		0.1		0.6			537.5	%
Selling, general and administrative	—		—		—			89.9	%
Cost of operations per ton*	$	36.18	$	31.01	$	5.17		16.6	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	4.3	$	3.8	$	0.5		14.6	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	0.8		1.0		(0.2		)	(25.6	)%
Selling, general and administrative	0.3		0.1		0.2			80.4	%
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)	$	67.4	$	57.8	$	9.6		16.6	%
Freight and handling costs	1.1		0.8		0.3			46.1	%
Depreciation, depletion and amortization	8.2		8.0		0.2			2.2	%
Selling, general and administrative	3.7		3.9		(0.2		)	(7.2	)%
Cost of operations per ton*	$	56.07	$	52.94	$	3.13		5.9	%

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

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

34

Cost of Operations.  Total cost of operations was $67.4 million for the three months ended June 30, 2011 as compared to $57.8 million for the three months ended June 30, 2010. Our cost of operations per ton was $56.07 for the three months ended June 30, 2011, an increase of $3.13, or 5.9%, from the three months ended June 30, 2010. These overall increases in the cost of operations and cost of operations on a per ton basis were due to increased costs in our Rhino Western segment due to increased production at our Castle Valley mine along with costs associated with idling our McClane Canyon mine. In addition, we experienced higher costs in our Central Appalachia operations due to increased transportation and maintenance costs from our Grapevine surface mine located in the Tug River complex as well as increased roof support costs at our Hopedale mine in our Northern Appalachia operations. Cost of operations also increased across all of the operating segments due to higher fuel prices.  In addition, costs associated with coal revenue such as royalties and severance taxes increased as coal revenue per ton increased during the quarter.

Our cost of operations for the Central Appalachia segment increased by $4.7 million, or 12.9%, to $41.0 million for the three months ended June 30, 2011 from $36.3 million for the three months ended June 30, 2010. Our cost of operations per ton increased to $69.19 per ton for the three months ended June 30, 2011 from $63.74 per ton for three months ended June 30, 2010. The increases in cost of operations and costs of operations per ton were primarily due to increased transportation and maintenance costs from the Grapevine surface mine located in the Tug River complex.

In our Northern Appalachia segment, our cost of operations increased by $2.1 million, or 12.6%, to $18.1 million for the three months ended June 30, 2011 from $16.0 million for the three months ended June 30, 2010, primarily due to the cost of the inventory sold in the second quarter that had built up in the first quarter of 2011 from the flooding on the Ohio River. Our cost of operations per ton increased to $36.18 for the three months ended June 30, 2011 compared to $34.22 for the three months ended June 30, 2010, an increase of $1.96 per ton, or 5.7%. The increase in costs of operations per ton was primarily due to the idling of our Sands Hill operations due to flooding on the Ohio River that limited shipments early in the second quarter.

Our cost of operations for the Rhino Western segment increased by $2.3 million, or 139.6%, to $4.0 million for the three months ended June 30, 2011 from $1.7 million for the three months ended June 30, 2010. Our cost of operations per ton increased to $36.18 per ton for the three months ended June 30, 2011 from $31.01 per ton for three months ended June 30, 2010. These increases in cost of operations and cost of operations per ton were primarily due to increased costs associated with increasing production at our Castle Valley mine along with costs associated with idling our McClane Canyon mine.

Cost of operations in our Other category increased by $0.5 million for the three months ended June 30, 2011 as compared to the three months ended June 30, 2010. 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, 2011 increased by $0.3 million, or 46.1%, to $1.1 million from $0.8 million for the three months ended June 30, 2010. This increase was primarily due to a 0.1 million increase in the

35

number of tons sold for the period ended June 30, 2011 as compared to the period ended June 30, 2010.

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization (“DD&A”) expense for the three months ended June 30, 2011 was $8.2 million as compared to $8.0 million for the three months ended June 30, 2010.

For the three months ended June 30, 2011, our depreciation cost was relatively flat at $6.5 million as compared to $6.8 million for the three months ended June 30, 2010.

For the three months ended June 30, 2011, our depletion cost was $1.0 million compared to $0.5 million for the three months ended June 30, 2010. This increase is primarily attributable to the increase in tons produced for the period ended June 30, 2011 as compared to the period ended June 30, 2010.

For the three months ended June 30, 2011 and 2010, our amortization cost was relatively flat at $0.7 million.

Selling, General and Administrative.  Selling, general and administrative (“SG&A”) expense for the three months ended June 30, 2011 was relatively flat $3.7 million as compared to $3.9 million for the three months ended June 30, 2010.

Interest Expense.  Interest expense for the three months ended June 30, 2011 was $1.4 million as compared to $1.3 million for the three months ended June 30, 2010, an increase of $0.1 million, or 4.2%. This increase was primarily the result of an increase in the balance outstanding under our credit facility.

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.

36

(In thousands, except per ton data and %)	Three months ended June 30, 2011		Three months ended June 30, 2010		Increase (Decrease) %*
Eastern Met 100% Basis
Coal revenues	$	12,466	$	8,234	51.4	%
Total revenues	$	12,478	$	8,255	51.2	%
Coal revenues per ton*	$	198.96	$	116.17	71.3	%
Cost of operations	$	8,786	$	5,014	75.2	%
Cost of operations per ton*	$	140.22	$	70.75	98.2	%
Net income	$	2,355	$	1,066	120.9	%
Partnership’s portion of net income	$	1,201	$	544	120.9	%
Tons produced	60.9		72.0		(15.3	)%
Tons sold	62.7		70.9		(11.6	)%

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

Beginning on March 18, 2011, MSHA issued two orders requiring Rhino Eastern’s Eagle #1 mine to be idled until water located in previous mine works above the mine was removed. Rhino Eastern lost production at this mine for approximately three weeks while this water was removed. Additionally, on June 27, 2011, a fatality occurred at Rhino Eastern’s Eagle #1 mine due to a rib fall that tragically killed one miner.  Production was idled at this mine while we and MSHA investigated the events surrounding this accident. Production resumed at Rhino Eastern’s Eagle #1 mine in July once the investigations were completed. Despite the interruptions that caused tons produced and tons sold in the second quarter of 2011 to be less than the results from the same period in 2010, revenue and net income increased year-to-year due to favorable pricing for coal sold in 2011.

Net Income (Loss).  The following table presents net income (loss) by reportable segment for the three months ended June 30, 2011 and 2010:

	Three months ended			Three months ended			Increase
Segment	June 30, 2011			June 30, 2010			(Decrease)
	(in millions)
Central Appalachia	$	4.4		$	5.5		$	(1.1	)
Northern Appalachia	5.4			2.0			3.4
Rhino Western	(0.7		)	0.4			(1.1		)
Eastern Met *	1.2			0.5			0.7
Other	(0.9		)	(1.3		)	0.4
Total	$	9.4		$	7.1		$	2.3

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

37

For the three months ended June 30, 2011, total net income increased to approximately $9.4 million compared to approximately $7.1 million the three months ended June 30, 2010, primarily due to increases in coal revenues, partially offset by increased costs and expenses. For our Central Appalachia segment, net income decreased to $4.4 million for the three months ended June 30, 2011, a decrease of $1.1 million as compared to the three months ended June 30, 2010, primarily due to increased costs of operations, partially offset by approximately $0.5 million of net income from Elk Horn. Net income in our Northern Appalachia segment increased by $3.4 million to $5.4 million for the three months ended June 30, 2011, from $2.0 million for the three months ended June 30, 2010. This increase was primarily the result of an increase in sales. Net income in our Rhino Western segment decreased by $1.1 million to a loss of $0.7 million for the three months ended June 30, 2011, compared to income of $0.4 million for the three months ended June 30, 2010. This decrease was primarily the result of an increase in costs associated with increasing production at our Castle Valley operation. Our Eastern Met segment recorded net income of $1.2 million for the three months ended June 30, 2011, an increase of $0.7 million from income of $0.5 million for the three months ended June 30, 2010.  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. For the Other category, we had a net loss of $0.8 million for the three months ended June 30, 2011, a decrease of $0.5 million as compared to a net loss of $1.3 million for the three months ended June 30, 2010.  This decrease in loss was primarily due to decreased DD&A costs.

EBITDA.  The following table presents EBITDA by reportable segment for the three months ended June 30, 2011 and 2010:

	Three months ended		Three months ended		Increase
Segment	June 30, 2011		June 30, 2010		(Decrease)
	(in millions)
Central Appalachia	$	9.7	$	10.9	$	(1.2	)
Northern Appalachia	7.9		4.6		3.3
Rhino Western	0.1		0.5		(0.4		)
Eastern Met *	1.2		0.5		0.7
Other	0.1		—		0.1
Total	$	19.0	$	16.5	$	2.5

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

Total EBITDA for the three months ended June 30, 2011 was $19.0 million, an increase of $2.5 million from the three months ended June 30, 2010 primarily due to an increase in net income. 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 EBITDA” for reconciliations of EBITDA to net income on a segment basis.

38

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Summary.  For the six months ended June 30, 2011, our total revenues increased to $172.6 million from $145.0 million for the six months ended June 30, 2010. We sold 2.3 million tons of coal for the six months ended June 30, 2011, which is 0.3 million tons greater, or a 13.7% increase, than the 2.0 million tons of coal sold for the six months ended June 30, 2010. This increase was the result of production being reactivated at a surface mine in our Central Appalachia segment as well as the start of production at our Castle Valley operation in Utah, partially offset by the idling of our McClane Canyon mine in Colorado.

For the six months ended June 30, 2011, we increased our coal inventories by approximately 47 thousand tons. Our coal inventory increased primarily due to production commencing at our Castle Valley operation in Utah.

Net income and EBITDA increased for the six months ended June 30, 2011 from the six months ended June 30, 2010.  Net income was approximately $15.5 million for the six months ended June 30, 2011 compared to approximately $13.7 million for the six months ended June 30, 2010 due to higher revenues, which were partially offset by higher costs and expenses. Net income was also positively impacted period to period due to $1.9 million of income from our Rhino Eastern joint venture for the six months ended June 30, 2011 compared to income of $0.4 million for the six months ended June 30, 2010, 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.

EBITDA increased to $35.3 million for the six months ended June 30, 2011 from $32.3 million for the six months ended June 30, 2010. EBITDA increased period to period due to increased net income and DD&A, partially offset by lower interest expense. EBITDA was also positively impacted period to period due to the net income impact from our Rhino Eastern joint venture.

Tons Sold.  The following table presents tons of coal sold by reportable segment for the six months ended June 30, 2011 and 2010:

	Six months	Six months	Increase/
	ended	ended	(Decrease)
Segment	June 30, 2011	June 30, 2010	Tons	% *
	(in millions, except %)
Central Appalachia	1.2	1.0	0.2	18.3	%
Northern Appalachia	1.0	1.0	—	4.4	%
Rhino Western	0.2	0.1	0.1	54.3	%
Total *†	2.3	2.0	0.3	13.7	%

*Percentages are calculated based on actual amounts and not the rounded amounts presented in this table.  Totals may not foot due to rounding.

39

†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 2.3 million tons of coal in the six months ended June 30, 2011 as compared to approximately 2.0 million tons sold in the six months ended June 30, 2010. This increase in tons sold was primarily due to production being reactivated at a surface mine in our Central Appalachia segment as well as the start of production at our Castle Valley operation in Utah, partially offset by the idling of our McClane Canyon mine in Colorado. Tons of coal sold in our Central Appalachia segment increased by approximately 0.2 million, or 18.3%, to approximately 1.2 million tons for the six months ended June 30, 2011 from approximately 1.0 million tons for the six months ended June 30, 2010. For our Northern Appalachia segment, tons of coal sold remained constant at approximately 1.0 million tons for both the six months ended June 30, 2011 and 2010. Coal sales from our Rhino Western segment increased by approximately 0.1 million, or 54.3%, to approximately 0.2 million tons for the six months ended June 30, 2011 from approximately 0.1 million tons for the six months ended June 30, 2010.

40

Revenues.  The following table presents revenues and coal revenues per ton by reportable segment for the six months ended June 30, 2011 and 2010:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2011		June 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	102.6	$	89.9	$	12.7		14.1	%
Freight and handling revenues	—		—		—			n/a
Other revenues	2.1		0.4		1.7			420.8	%
Total revenues	$	104.7	$	90.3	$	14.4		15.9	%
Coal revenues per ton*	$	89.18	$	92.44	$	(3.26	)	(3.5	)%
Northern Appalachia
Coal revenues	$	52.8	$	42.1	$	10.7		25.5	%
Freight and handling revenues	2.6		1.9		0.7			32.0	%
Other revenues	2.3		2.7		(0.4		)	(11.2	)%
Total revenues	$	57.7	$	46.7	$	11.0		23.7	%
Coal revenues per ton*	$	52.68	$	43.83	$	8.85		20.2	%
Rhino Western
Coal revenues	$	7.0	$	4.7	$	2.3		46.1	%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	7.0	$	4.7	$	2.3		46.1	%
Coal revenues per ton*	$	41.34	$	43.67	$	(2.33	)	(5.3	)%
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		3.3		(0.1		)	(1.9	)%
Total revenues	$	3.2	$	3.3	$	(0.1	)	(1.9	)%
Coal revenues per ton	n/a		n/a		n/a			n/a
Total
Coal revenues	$	162.4	$	136.7	$	25.7		18.8	%
Freight and handling revenues	2.6		1.9		0.7			32.0	%
Other revenues	7.6		6.4		1.2			21.0	%
Total revenues	$	172.6	$	145.0	$	27.6		19.0	%
Coal revenues per ton*	$	69.93	$	66.96	$	2.97		4.4	%

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

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

41

Our coal revenues for the six months ended June 30, 2011 increased by approximately $25.7 million, or 18.8%, to approximately $162.4 million from approximately $136.7 million for the six months ended June 30, 2010. The increase in coal revenues was due to increased volume in tons sold as well as higher contracted and spot prices for our steam coal. Coal revenues per ton were $69.93 for the six months ended June 30, 2011, an increase of $2.97, or 4.4%, from $66.96 per ton for the six months ended June 30, 2010. This increase in coal revenues per ton was primarily the result of higher contracted and spot prices for steam coal.

For our Central Appalachia segment, coal revenues increased by approximately $12.7 million, or 14.1%, to approximately $102.6 million for the six months ended June 30, 2011 from approximately $89.9 million for the six months ended June 30, 2010 due to increased volume in tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $3.26, or 3.5%, to $89.18 per ton for the six months ended June 30, 2011 as compared to $92.44 for the six months ended June 30, 2010, due to lower contracted prices, primarily related to metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to approximately $1.0 million of coal leasing revenue from Elk Horn.

For our Northern Appalachia segment, coal revenues were approximately $52.8 million for the six months ended June 30, 2011, an increase of approximately $10.7 million, or 25.5%, from approximately $42.1 million for the six months ended June 30, 2010, primarily as a result of higher contracted and spot prices for steam coal. Coal revenues per ton for our Northern Appalachia segment increased by $8.85, or 20.2%, to $52.68 per ton for the six months ended June 30, 2011 as compared to $43.83 per ton for the six months ended June 30, 2010. This increase was primarily due to higher contracted and spot prices for steam coal.

For our Rhino Western segment, coal revenues increased by approximately $2.3 million, or 46.1%, to approximately $7.0 million for the six months ended June 30, 2011 from approximately $4.7 million for the six months ended June 30, 2010 due to the start of production at our Castle Valley operation. Coal revenues per ton for our Rhino Western segment were $41.34 for the six months ended June 30, 2011, a decrease of $2.33, or 5.3%, from $43.67 for the six months ended June 30, 2010. The decrease in coal revenues per ton was due to lower market prices for coal produced at our Castle Valley mine compared to coal sold from our McClane Canyon mine in 2010.

Other revenues for our Other category were relatively flat period to period at approximately $3.2 million for the six months ended June 30, 2011 compared to approximately $3.3 million for the six months ended June 30, 2010.

42

Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, 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, 2011		Six months ended June 30, 2010		Increase (Decrease) %*
Met coal tons sold	369.6		305.2		21.1	%
Steam coal tons sold	780.4		666.9		17.0	%
Total tons sold †	1,150.0		972.1		18.3	%
Met coal revenue	$	44,165	$	40,549	8.9	%
Steam coal revenue	$	58,390	$	49,330	18.4	%
Total coal revenue †	$	102,555	$	89,879	14.1	%
Met coal revenues per ton	$	119.50	$	132.86	(10.1	)%
Steam coal revenues per ton	$	74.82	$	73.97	1.1	%
Total coal revenues per ton †	$	89.18	$	92.44	(3.5	)%
Met coal tons produced	360.5		338.1		6.6	%
Steam coal tons produced	766.5		730.7		4.9	%
Total tons produced †	1,127.0		1,068.8		5.4	%

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

43

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, 2011 and 2010:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2011		June 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	76.5	$	60.9	$	15.6		25.7	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	10.4		9.5		0.9			9.3	%
Selling, general and administrative	8.2		7.1		1.1			15.1	%
Cost of operations per ton*	$	66.58	$	62.64	$	3.94		6.3	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	35.7	$	33.1	$	2.6		7.6	%
Freight and handling costs	1.9		1.4		0.5			34.3	%
Depreciation, depletion and amortization	4.2		4.0		0.2			5.3	%
Selling, general and administrative	0.1		0.2		(0.1		)	(10.6	)%
Cost of operations per ton*	$	35.57	$	34.53	$	1.04		3.0	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	6.5	$	3.2	$	3.3		106.2	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.3		0.2		1.1			433.3	%
Selling, general and administrative	—		—		—			38.4	%
Cost of operations per ton*	$	38.08	$	28.51	$	9.57		33.6	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	9.8	$	7.0	$	2.8		39.4	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.5		2.1		(0.6		)	(27.2	)%
Selling, general and administrative	0.6		0.3		0.3			98.5	%
Cost of operations per ton**	n/a		n/a		n/a			n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	128.5	$	104.2	$	24.3		23.3	%
Freight and handling costs	1.9		1.4		0.5			34.3	%
Depreciation, depletion and amortization	17.4		15.8		1.6			9.8	%
Selling, general and administrative	8.9		7.6		1.3			18.3	%
Cost of operations per ton*	$	55.33	$	51.02	$	4.31		8.4	%

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

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

44

Cost of Operations.  Total cost of operations was $128.5 million for the six months ended June 30, 2011 as compared to $104.2 million for the six months ended June 30, 2010. Our cost of operations per ton was $55.33 for the six months ended June 30, 2011, an increase of $4.31, or 8.4%, from the six months ended June 30, 2010. These overall increases in the cost of operations and cost of operations on a per ton basis were due to increased costs in our Rhino Western segment due to preparing our Castle Valley mine to begin production early in 2011 along with costs associated with idling our McClane Canyon mine. In addition, we experienced higher costs in our Central Appalachia operations due to an increased number of regulatory actions at Mine 28 in our Rob Fork mining complex along with increased transportation and maintenance costs from our Grapevine surface mine located in the Tug River complex. Cost of operations also increased across all of the operating segments due to higher fuel prices.  In addition, costs associated with coal revenue such as royalties and severance taxes increased as coal revenue per ton increased.

Our cost of operations for the Central Appalachia segment increased by $15.6 million, or 25.7%, to $76.5 million for the six months ended June 30, 2011 from $60.9 million for the six months ended June 30, 2010. Our cost of operations per ton increased to $66.58 per ton for the six months ended June 30, 2011 from $62.64 per ton for six months ended June 30, 2010. The increases in cost of operations and costs of operations per ton were primarily due to an increased number of regulatory actions at Mine 28 located in the Rob Fork mining complex along with increased transportation and maintenance costs from the Grapevine surface mine located in the Tug River complex.

In our Northern Appalachia segment, our cost of operations increased by $2.6 million, or 7.6%, to $35.7 million for the six months ended June 30, 2011 from $33.1 million for the six months ended June 30, 2010, primarily due to increased commodity prices driven by higher fuel costs. Our cost of operations per ton was $35.57 for the six months ended June 30, 2011 compared to $34.53 for the six months ended June 30, 2010, an increase of $1.04 per ton, or 3.0%. The increase in costs of operations per ton was primarily due to the idling of our Sands Hill operation due to flooding on the Ohio River that limited shipments early in the second quarter.

Our cost of operations for the Rhino Western segment increased by $3.3 million, or 106.2%, to $6.5 million for the six months ended June 30, 2011 from $3.2 million for the six months ended June 30, 2010. Our cost of operations per ton increased to $38.08 per ton for the six months ended June 30, 2011 from $28.51 per ton for six months ended June 30, 2010. These increases in cost of operations and cost of operations per ton were primarily due to increased costs associated with preparing our Castle Valley mine to begin production early in 2011 along with costs associated with idling our McClane Canyon mine.

Cost of operations in our Other category increased by $2.8 million for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010. 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, 2011 increased by $0.5 million, or 34.3%, to $1.9 million from $1.4 million for the six months

45

ended June 30, 2010. This increase was primarily due to a 0.3 million increase in the number of tons sold for the period ended June 30, 2011 as compared to the period ended June 30, 2010.

Depreciation, Depletion and Amortization.  Total DD&A expense for the six months ended June 30, 2011 was $17.4 million as compared to $15.8 million for the six months ended June 30, 2010.

For the six months ended June 30, 2011, our depreciation cost was relatively flat at $13.3 million as compared to $13.4 million for the six months ended June 30, 2010.

For the six months ended June 30, 2011, our depletion cost was $1.9 million compared to $1.0 million for the six months ended June 30, 2010. This increase is primarily attributable to the increase in tons produced for the period ended June 30, 2011 as compared to the period ended June 30, 2010.

For the six months ended June 30, 2011, our amortization cost was $2.2 million as compared to $1.4 million for the six months ended June 30, 2010. This increase is primarily attributable to the acceleration of amortization for both mine development costs and asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative.  SG&A expense for the six months ended June 30, 2011 was $8.9 million as compared to $7.6 million for the six months ended June 30, 2010. 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, 2011 was $2.4 million as compared to $2.8 million for the six months ended June 30, 2010, a decrease of $0.4 million, or 12.8%. This decrease was primarily the result of a reduction in the balance outstanding under our credit facility during the six month period, even though the credit facility balance did increase toward the latter part of the second quarter in 2011 due to our recent acquisitions discussed earlier.

46

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, 2011		Six months ended June 30, 2010		Increase (Decrease) %*
Eastern Met 100% Basis
Coal revenues	$	22,741	$	13,651	66.6	%
Total revenues	$	22,770	$	13,676	66.5	%
Coal revenues per ton*	$	193.72	$	108.53	78.5	%
Cost of operations	$	16,181	$	10,196	58.7	%
Cost of operations per ton*	$	137.83	$	81.06	70.0	%
Net income	$	3,727	$	812	359.2	%
Partnership’s portion of net income	$	1,901	$	414	359.2	%
Tons produced	117.3		129.1		(9.2	)%
Tons sold	117.4		125.8		(6.7	)%

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

Rhino Eastern’s Eagle #1 mine was removed from the potential pattern of violation list in March 2011 by MSHA. However, beginning on March 18, 2011, MSHA issued two orders requiring this mine to be idled until water located in previous mine works above the mine was removed. Rhino Eastern lost production at this mine for approximately three weeks while this water was removed. Additionally, on June 27, 2011, a fatality occurred at Rhino Eastern’s Eagle #1 mine due to a rib fall that tragically killed one miner.  Production was idled at this mine while we and MSHA investigated the events surrounding this accident. Production resumed at Rhino Eastern’s Eagle #1 mine in July once the investigations were completed. Despite the interruptions that caused tons produced and tons sold for the six months ended June 30, 2011 to be less than the results from the same period in 2010, revenue and net income increased year-to-year due to favorable pricing for coal sold in 2011.

47

Net Income (Loss).  The following table presents net income (loss) by reportable segment for the six months ended June 30, 2011 and 2010:

	Six months Ended			Six months Ended			Increase
Segment	June 30, 2011			June 30, 2010			(Decrease)
	(in millions)
Central Appalachia	$	6.4		$	10.2		$	(3.8	)
Northern Appalachia	11.7			4.6			7.1
Rhino Western	(1.9		)	1.0			(2.9		)
Eastern Met *	1.9			0.4			1.5
Other	(2.6		)	(2.5		)	(0.1		)
Total	$	15.5		$	13.7		$	1.8

*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, 2011, total net income increased to approximately $15.5 million compared to approximately $13.7 million for the six months ended June 30, 2010 due to increases in coal revenues, which were partially offset by increased costs and expenses. For our Central Appalachia segment, net income decreased to $6.4 million for the six months ended June 30, 2011, a decrease of $3.8 million as compared to the six months ended June 30, 2010, primarily due to increases in costs of operations, partially offset by approximately $0.5 million of net income from Elk Horn. Net income in our Northern Appalachia segment increased by $7.1 million to $11.7 million for the six months ended June 30, 2011, from $4.6 million for the six months ended June 30, 2010. This increase was primarily the result of an increase in sales. Net income in our Rhino Western segment decreased by $2.9 million to a loss of $1.9 million for the six months ended June 30, 2011, compared to income of $1.0 million for the six months ended June 30, 2010. This decrease was primarily the result of an increase in costs associated with preparing our Castle Valley operation to begin production in early 2011. Our Eastern Met segment recorded net income of approximately $1.9 million for the six months ended June 30, 2011, an increase of $1.5 million from net income of approximately $0.4 million for the six months ended June 30, 2010.  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. For the Other category, we had a net loss of $2.6 million for the six months ended June 30, 2011, which was relatively flat compared to a net loss of $2.5 million for the six months ended June 30, 2010.

48

EBITDA. The following table presents EBITDA by reportable segment for the six months ended June 30, 2011 and 2010:

	Six months Ended			Six months Ended		Increase
Segment	June 30, 2011			June 30, 2010		(Decrease)
	(in millions)
Central Appalachia	$	17.8		$	20.9	$	(3.1	)
Northern Appalachia	16.7			9.7		7.0
Rhino Western	(0.5		)	1.3		(1.8		)
Eastern Met *	1.9			0.4		1.5
Other	(0.6		)	—		(0.6		)
Total	$	35.3		$	32.3	$	3.0

*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 EBITDA for the six months ended June 30, 2011 was $35.3 million, an increase of $3.0 million from the six months ended June 30, 2010 primarily due to an increase in net income of $1.8 million along with an increase in DD&A expense of $1.6 million, partially offset by a decrease in interest expense of $0.4 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, DD&A and interest expense are not presented separately for our Eastern Met segment. Please read “—Reconciliations of EBITDA” for reconciliations of EBITDA to net income on a segment basis.

Reconciliations of EBITDA

EBITDA represents net income before interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used by management primarily as a measure of the Partnership’s operating performance. Because not all companies calculate EBITDA identically, our calculation may not be comparable to similarly titled measures of other companies. EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. The following tables present reconciliations of EBITDA to the most directly comparable GAAP financial measures for each of the periods indicated:

Three months ended	Central		Northern		Rhino			Eastern
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

49

Three months ended	Central		Northern		Rhino		Eastern
June 30, 2010	Appalachia		Appalachia		Western		Met *		Other			Total**
	(in millions)
Net income	$	5.5	$	2.0	$	0.4	$	0.5	$	(1.3	)	$	7.1
Plus:
DD&A	4.8		2.1		0.1		—		1.0			8.0
Interest expense	0.6		0.5		—		—		0.3			1.3
EBITDA† **	$	10.9	$	4.6	$	0.5	$	0.5	$	—		$	16.5

Six months ended	Central		Northern		Rhino			Eastern
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

Six months ended	Central		Northern		Rhino		Eastern
June 30, 2010	Appalachia		Appalachia		Western		Met *		Other			Total
	(in millions)
Net income	$	10.2	$	4.6	$	1.0	$	0.4	$	(2.5	)	$	13.7
Plus:
DD&A	9.5		4.0		0.2		—		2.1			15.8
Interest expense	1.2		1.1		0.1		—		0.4			2.8
EBITDA†	$	20.9	$	9.7	$	1.3	$	0.4	$	—		$	32.3

*	Includes our 51% equity interest in the results of the joint venture, which owns the Rhino Eastern mining complex located in West Virginia and for which we serve as manager.
**	Totals may not foot due to rounding.
†	EBITDA is calculated based on actual amounts and not the rounded amounts presented in this table.

50

	Three months ended				Six months ended
	June 30				June 30
	2011		2010		2011		2010
	(in millions)
Net cash provided by operating activities	$	28.0	$	20.3	$	34.0	$	24.9
Plus:
Increase in net operating assets	—		—		—		5.9
Gain on sale of assets	—		—		0.1		—
Interest expense	1.4		1.3		2.4		2.8
Equity in net income of unconsolidated affiliate	1.2		0.5		1.9		0.4
Less:
Decrease in net operating assets	10.5		5.0		0.2		—
Accretion on interest-free debt	0.1		—		0.1		0.1
Amortization of advance royalties	0.2		0.1		0.7		0.4
Amortization of debt issuance costs	0.2		—		0.5		—
Equity-based compensation	0.1		—		0.5		—
Loss on sale of assets	—		—		—		—
Loss on retirement of advance royalties	—		—		0.1		0.1
Accretion on asset retirement obligations	0.5		0.5		1.0		1.1
Equity in net loss of unconsolidated affiliate	—		—		—		—
EBITDA†	$	19.0	$	16.5	$	35.3	$	32.3

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

Liquidity and Capital Resources

Liquidity

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

The principal indicators of our liquidity are our cash on hand and availability under our credit agreement. As of June 30, 2011, our available liquidity was $54.1 million, including cash on hand of $2.3 million and $51.8 million available under our credit agreement.

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

Cash Flows

Net cash provided by operating activities was $34.0 million for the six months ended June 30, 2011 as compared to $24.9 million for the six months ended June 30, 2010.  This increase in cash provided by operating activities was primarily the result of favorable working

51

capital changes in 2011 compared to unfavorable working capital changes in 2010. For 2011, favorable working capital changes in accounts payable and accrued expenses and other liabilities offset an unfavorable change in inventories that resulted from coal inventory increasing at our Castel Valley mine as we increased production while attempting to secure long-term sales contracts with customers.  For 2010, the unfavorable working capital changes were primarily due to an unfavorable change in inventories caused by market conditions.

Net cash used in investing activities was $153.3 million for the six months ended June 30, 2011 as compared to $11.6 million for the six months ended June 30, 2010.  The increase in cash used in investing activities was primarily due to the acquisition of Elk Horn for approximately $119.3 million, net of cash acquired, along with increased amounts expended for the purchase of mining equipment and other asset acquisitions, including approximately $12.8 million for oil and gas mineral rights acquisitions related to Cana Woodford and Utica Shale mentioned earlier.

Net cash provided by financing activities for the six months ended June 30, 2011 was $121.5 million, which was primarily attributable to borrowings under our credit agreement to fund the Elk Horn acquisition.  Net cash used in financing activities for the six months ended June 30, 2010 was $13.8 million, which were primarily attributable to net repayments of borrowings under our credit agreement.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to meet environmental and safety regulations. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves to the extent such expenditures are made to maintain our long-term operating capacity. Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of reserves, equipment for a new mine or the expansion of an existing mine to the extent such expenditures are expected to expand our long-term operating capacity.

Actual maintenance capital expenditures for the six months ended June 30, 2011 were approximately $6.4 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the six months ended June 30, 2011 were approximately $29.9 million. As discussed earlier, we completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma and in the Utica Shale region of eastern Ohio for a total purchase price of approximately $12.8 million during the six months ended June 30, 2011 that was classified as an expansion capital expenditure.  Additionally, we acquired approximately 32,600 acres and associated surface rights in Randolph and Upshur Counties, West Virginia for approximately $7.5 million that was also classified as an expansion capital expenditure. The remaining amounts were primarily spent for our internal development projects.  For the year ending December 31, 2011, we have budgeted $46.0 million to $55.0 million for capital expenditures.

52

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

Rhino Energy LLC, our wholly owned subsidiary, as borrower, and we and our operating subsidiaries, as guarantors, are parties to our $200.0 million credit agreement, which is available for general partnership purposes, including working capital and capital expenditures, and may be increased by up to $75.0 million with the consent of the lenders, so long as there is no event of default. Of the $200.0 million, $50.0 million is available for letters of credit. 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.

As of June 30, 2011, we had borrowings outstanding under our credit agreement of approximately $173.5 million and $24.7 million of letters of credit in place, leaving approximately $51.8 million of availability under our credit agreement. During the three month period ending June 30, 2011, we had average borrowings outstanding of approximately $75.0 million in relation to this credit agreement.

Our obligations under the credit agreement are secured by substantially all of our assets, including the equity interests in our subsidiaries. Indebtedness under the credit agreement is guaranteed by us and all of our wholly owned subsidiaries.

Our credit agreement bears interest at either (1) LIBOR plus 3.0% to 3.5% per annum, depending on our leverage ratio, or (2) a base rate that is the sum of (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.5% or (c) LIBOR plus 1.0% and (ii) 1.5% to 2.0% per annum, depending on our leverage ratio. We incur letter of credit fees equal to the then applicable spread above LIBOR on the undrawn face amount of standby letters of credit and a 15 basis point fronting fee payable to the administrative agent on the aggregate face amount of such letters of credit. In addition, we incur a commitment fee on the unused portion of the credit agreement at a rate of 0.5% per annum. The credit agreement will mature in February 2013. At that time, the credit agreement will terminate and all outstanding amounts thereunder will be due and payable, unless the credit agreement is amended.

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 June 30, 2011, we are in compliance with respect to all covenants contained in the credit agreement.

On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and the guarantors and lenders, which are parties

53

thereto. Refer to “Recent Developments” for further discussion of the amended and restated senior secured credit facility.

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, 2011, we had $24.7 million in letters of credit outstanding, of which $21.3 million served as collateral for surety bonds.

Critical Accounting Policies and Estimates

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

The accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are fully described in our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no significant changes in these policies and estimates as of June 30, 2011.

Recent Accounting Pronouncements

In December 2010, the FASB published Accounting Standards Update (“ASU”) No. 2010-28, “When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”. Testing for goodwill impairment is a two-step test. When a goodwill impairment test is performed (either on an annual or interim basis), an entity must

54

assess whether the carrying amount of a reporting unit exceeds its fair value (Step 1). If it does, an entity must perform an additional test to determine whether goodwill has been impaired and to calculate the amount of that impairment (Step 2). The update in ASU No. 2010-28 states that if the carrying amount of a reporting unit is zero or negative, the second step of the impairment test shall be performed to measure the amount of impairment loss, if any, when it is more likely than not that a goodwill impairment exists. In considering whether it is more likely than not that a goodwill impairment exists, an entity shall evaluate whether there are adverse qualitative factors. Qualitative factors may include:

·A significant adverse change in legal factors or in the business climate;

·An adverse action or assessment by a regulator;

·Unanticipated competition;

·A loss of key personnel;

·A more-likely-than-not expectation that a reporting unit or a significant portion of a reporting unit will be sold or otherwise disposed of;

·The testing for recoverability under the Impairment or Disposal of Long-Lived Assets Subsections of Subtopic 360-10 of a significant asset group within a reporting unit; or

·Recognition of a goodwill impairment loss in the financial statements of a subsidiary that is a component of a reporting unit.

The amendments in ASU No. 2010-28 are effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. We have adopted the provisions of ASU No. 2010-28 effective January 1, which had no impact on our goodwill balance.

In December 2010, the FASB published ASU No. 2010-29, “Disclosure of Supplementary Pro Forma Information for Business Combinations”. The accounting guidance on business combinations requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. If comparative financial statements are presented, the pro forma revenue and earnings of the combined entity for the comparable prior reporting period should be reported as though the acquisition date for all business combinations that occurred during the current year had been as of the beginning of the comparable prior annual reporting period. ASU No. 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments in ASU No. 2010-29 also expand the supplemental pro forma disclosures under business combination accounting to include a description of the nature and amount of material, nonrecurring pro forma adjustments

55

directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU No. 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We have adopted the provisions of ASU No. 2010-29 effective January 1, 2011.

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. The following market risk disclosures should be read in conjunction with the qualitative and quantitative market risk disclosures contained in our Annual Report on Form 10-K for the year ended December 31, 2010.

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 approximately $0.2 million for the three months ended June 30, 2011 and would have reduced net income by approximately $0.3 million for the six months ended June 30, 2011. A hypothetical increase of 10% in steel prices would have reduced net income by $0.4 million for the three months ended June 30, 2011 and would have reduced net income by approximately $0.7 million for the six months ended June 30, 2011. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.1 million for the three months ended June 30, 2011 and would have reduced net income by approximately $0.3 million for the six months ended June 30, 2011.

Interest Rate Risk

Borrowings under our senior secured credit facility are at variable rates and, as result, we have exposure to changes in interest rates. 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 of our credit facility by 1% would have changed our interest expense by $0.3 million for the three months ended June 30, 2011 and would have changed our interest expense by $0.6 million for the six months ended June 30, 2011.

We have not entered into interest rate hedging agreements in the past, and have no plans to do so in the future.  Due to fluctuating balances in the amount outstanding under this credit agreement, we do not believe such hedging agreements would be cost effective.

56

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, 2011 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, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

57

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, 2010, 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, 2010. However, there are a number of additional risks described below relating to the Elk Horn acquisition that must be considered. 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.

Risks related to the Elk Horn acquisition

If we fail to realize the anticipated benefits of the Elk Horn acquisition, unitholders may receive lower returns than they expect.

The success of our recent acquisition of Elk Horn will depend, in part, on our ability to realize the anticipated business opportunities and growth prospects of Elk Horn’s business. We may not realize the full benefits we expect to result from the acquisition, or realize these benefits within the time frame that is currently expected. The benefits of the acquisition may be offset by operating losses relating to changes in commodity prices, or in coal industry conditions, or by an increase in operating or other costs or other difficulties. For example, we have limited experience in the coal leasing business and cannot assure you that we will be able to effectively manage our new business operations or capitalize on expected business opportunities. Our limited experience in the coal leasing business could result in increased operating and other costs and have a material adverse effect on our results of operations and cash available for distribution to our unitholders. Further, we have not had the opportunity to evaluate Elk Horn management’s estimate of coal reserves and non-reserve coal deposits to the same degree that we have had the opportunity to evaluate substantially all of our previously owned or controlled coal reserves and non-reserve coal deposits. As a result, it is possible that when we further evaluate Elk Horn’s coal reserves and non-reserve coal deposits, the amount of the estimate could change materially. If we fail to realize the benefits we anticipate from the acquisition, unitholders may receive lower returns on our common units than they expect.

The lessees’ mining operations and their financial condition and results of operations are subject to some of the same risks and uncertainties that we face as a mine operator.

The mining operations and financial condition and results of operations of Elk Horn’s

58

lessees are subject to the same risks and uncertainties that we face as a mine operator. Please see “Item 1A Risk Factors—Risks Inherent in Our Business” described in our Annual Report on Form 10-K for the year ended December 31, 2010. If any such risks were to occur, the business, financial condition and results of operations of the lessees could be adversely affected and as a result our coal royalty revenues and cash available for distribution could be adversely affected.

If Elk Horn lessees do not manage their operations well, their production volumes and our royalty revenues could decrease.

Elk Horn depends on its lessees to effectively manage their operations on the leased properties. The lessees make their own business decisions with respect to their operations within the constraints of their leases, including decisions relating to:

· marketing of the coal mined;

· mine plans, including the amount to be mined and the method of mining;

· processing and blending coal;

· expansion plans and capital expenditures;

· credit risk of their customers;

· permitting;

· insurance and surety bonding;

· acquisition of surface rights and other coal estates;

· employee wages;

· transportation arrangements;

· compliance with applicable laws, including environmental laws; and

· mine closure and reclamation.

A failure on the part of one of the lessees to make royalty payments could give Elk Horn the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If Elk Horn repossessed any of its properties, it might not be able to find a replacement lessee or enter into a new lease on favorable terms within a reasonable period of time. In addition, the existing lessee could be subject to bankruptcy proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If Elk Horn enters into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced. In addition, it may be difficult to secure new or replacement lessees for small or isolated coal reserves, since industry trends toward consolidation favor larger-scale, higher-technology mining operations in order to increase

59

productivity.

Lessees could satisfy obligations to their customers with coal from properties other than Elk Horn’s, depriving us of the ability to receive amounts in excess of minimum royalty payments.

Coal supply contracts often require operators to satisfy their obligations to their customers with resources mined from specific reserves or may provide the operator flexibility to source the coal from various reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, mine operating costs, cost and availability of transportation, and customer specifications. If a lessee satisfies its obligations to its customers with coal from properties Elk Horn does not own or lease, production on its properties will decrease, and we will receive lower royalty revenues.

A lessee may incorrectly report royalty revenues, which might not be identified by Elk Horn’s lessee audit process or its mine inspection process or, if identified, might be identified in a subsequent period.

Elk Horn depends on its lessees to correctly report production and royalty revenues on a monthly basis. Its regular lessee audits and mine inspections may not discover any irregularities in these reports or, if Elk Horn does discover errors, it might not identify them in the reporting period in which they occurred. Any undiscovered reporting errors could result in a loss of royalty revenues and errors identified in subsequent periods could lead to accounting disputes as well as disputes with the lessees.

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.    [Removed and Reserved.]

Item 5.    Other Information.

Federal Mine Safety and Health Act Information

The recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). The following disclosures respond to that legislation. While we believe the following disclosures meet the requirements of the Dodd-Frank Act, it is possible that any rule making by the SEC will require disclosures to be presented in a form or with information that differs from the following.

60

Whenever MSHA believes that a violation of the Mine Act, any health or safety standard, or any regulation has occurred, it may issue a citation that describes the violation and fixes a time within which the operator must abate the violation.  In these situations, MSHA typically proposes a civil penalty, or fine, as a result of the violation, that the operator is ordered to pay.  In evaluating the information below regarding mine safety and health, investors should take into account factors such as: (a) the number of citations and orders will vary depending on the size of a coal mine, (b) the number of citations issued will vary from inspector to inspector and mine to mine, and (c) citations and orders can be contested and appealed, and during that process are often reduced in severity and amount, and are sometimes dismissed.

Responding to the Dodd-Frank Act legislation, we report that, for the six months ended June 30, 2011, none of our operating subsidiaries received written notice from MSHA of (a) a violation under section 110(b)(2) of the Mine Act for failure to make reasonable efforts to eliminate a known violation of a mandatory safety or health standard that substantially proximately caused, or reasonably could have been expected to cause, death or serious bodily injury, (b) a pattern of violations of mandatory health or safety standards under section 104(e) of the Mine Act, or (c) the potential to have such a pattern. We have 11 pending legal actions before the Federal Mine Safety and Health Review Commission (the “Commission”) that were initiated during the three months ended June 30, 2011 and we have 78 total pending legal actions that were pending before the Commission during the six months ended June 30, 2011, which includes the legal proceedings before the Commission as well as all contests of citations and penalty assessments which are not before an administrative law judge.  All of these pending legal actions constitute challenges by us of citations issued by MSHA.  There was one mining-related fatality during the six months ended June 30, 2011 that occurred at Rhino Eastern’s Eagle #1 Mine located in Bolt, West Virginia.

On November 19, 2010, Rhino Eastern received an MSHA notification of a potential pattern of violations under Section 104(e) of the Mine Act for Rhino Eastern’s Eagle #1 Mine located in Bolt, West Virginia, based on MSHA’s initial screening of compliance records for the twelve months ended August 31, 2010 and of accident and employment records for the twelve months ended June 30, 2010. Rhino Eastern carefully reviewed all of the historical safety data that resulted in the potential pattern of violations finding.  On December 7, 2010, Rhino Eastern submitted a Corrective Action Plan to MSHA and this plan became effective on December 31, 2010. In a letter dated March 15, 2011, MSHA notified Rhino Eastern that MSHA concluded that Rhino Eastern’s Eagle #1 Mine achieved the target for its significant and substantial (“S&S”) violations during the potential pattern of violations period. Because Rhino Eastern reduced its S&S violations to the targeted rate of S&S violations, MSHA decided to not consider Eagle #1 Mine for a pattern of violations notice pursuant to Section 104(e)(1) of the Mine Act at such time. This decision, as we understand it, resolves the issues identified in the November 19, 2010 notification.

The following table sets out additional information required by the Dodd-Frank Act for the three months ended June 30, 2011. The mine data retrieval system maintained by MSHA may show information that is different than what is provided herein.  Any such difference may be attributed to the need to update that information on MSHA’s system and/or other factors.

61

For the three months ended June 30, 2011

Company	Mine(1)	MSHA ID	104(a) S & S (2)	104 (b)(3)	104 (d)(4)	107 (a)(5)	110 (b)(2) (6)	Proposed Assessments(7)		Fatalities	Pending Legal Actions(8)
Hopedale Mining LLC	Hopedale Mine	33-00968	13	0	0	0	0	$	7,421	0	7
	Nelms Plant	33-04187	1	0	0	0	0	$	—	0	0
Sands Hill Mining LLC	Big Valley Mine	33-01358	0	0	0	0	0	$	—	0	0
	Clinton Stone	33-04041	0	0	0	0	0	$	200	0	0
CAM/Deane Mining LLC	Access Energy	15-19532	0	0	0	0	0	$	—	0	0
	Mine #28	15-18911	22	0	0	0	0	$	52,000	0	4
	Mine #30	15-18964	3	0	0	0	0	$	1,212	0	0
	Love Branch	15-19191	2	0	0	0	0	$	3,535	0	0
	Deane #1	15-18569	12	0	0	0	0	$	18,212	0	0
	Bevins Branch	15-18570	0	0	0	0	0	$	—	0	0
	Marion Branch	15-18100	0	1	0	0	0	$	—	0	0
	Three Mile Mine #1	15-17659	0	0	0	0	0	$	—	0	0
	Calloway North	15-19199	18	0	0	0	0	$	2,208	0	0
	Grapevine South	46-08930	5	0	0	0	0	$	—	0	0
	Rob Fork Processing	15-14468	2	0	0	0	0	$	—	0	0
	Jamboree Loadout	15-12896	0	0	0	0	0	$	—	0	0
	Mill Creek Prep Plant	15-16577	2	0	0	0	0	$	1,498	0	0
	Rhino Trucking	Q569	3	0	0	0	0	$	392	0	0
	Rhino Reclamation Services	R134	0	0	0	0	0	$	—	0	0
	Rhino Services	S359	0	0	0	0	0	$	—	0	0
Rhino Eastern LLC(9)	Eagle #1	46-08758	43	1	2	0	0	$	99,399	1	0
	Eagle #2	46-09201	9	0	0	0	0	$	—	0	0
	Sewell Mine	46-02166	0	0	0	0	0	$	—	0	0
McClane Canyon Mining LLC	McClane Canyon Mine	05-03013	0	0	0	0	0	$	1,705	0	0
Castle Valley Mining LLC	Castle Valley Mine #3	42-02263	0	0	0	0	0	$	—	0	0
	Castle Valley Mine #4	42-02335	0	0	0	0	0	$	—	0	0
	Bear Canyon Loading Facility	42-02395	0	0	0	0	0	$	—	0	0
Total			135	2	2	0	0	$	187,782	1	11

62

(1) The foregoing table does not include the following: (i) facilities which have been idle or closed unless they received a citation or order issued by MSHA; and (ii) permitted mining sites where we have not begun operations and therefore have not received any citations.

(2) Mine Act section 104(a) citations shown above are for alleged violations of health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.

(3) Mine Act section 104(b) orders are for alleged failures to totally abate a citation within the period of time specified in the citation.

(4) Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

(5) Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated and result in orders of immediate withdrawal from the area of the mine affected by the condition.

(6) The total number of flagrant violations issued under section 110(b)(2) of the Mine Act.

(7) Amounts shown include MSHA assessments proposed as of December 31, 2010, on the citations and orders reflected in this table. Citations and orders which have not yet been assessed are not included.

(8) By way of summary, the Commission has jurisdiction to hear not only challenges to citations, orders, and penalties but also certain complaints by miners.

(9) Rhino Eastern LLC is owned 51% by a subsidiary of Rhino Energy LLC and 49% by a subsidiary of Patriot Coal Corporation. Rhino Energy LLC serves as manager of the joint venture.

63

Item 6.Exhibits.

Exhibit Number	Description
2.1	Agreement of Merger among Rhino Resource Partners LP, Rhino Energy LLC, The Elk Horn Acquisition Co. LLC, and The Elk Horn Coal Company, LLC, and Peter Sisitsky, dated as of June 10,2011 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-34892) filed on June 16, 2011)
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	Assignment and Assumption Agreement dated May 6, 2011, by and between Rhino Exploration LLC, Gulfport Energy Corporation and Windsor Ohio LLC, incorporated by reference to Exhibit 10.24 of the Registration Statement on Form S-1 (File No. 333-175138), filed on June 24, 2011.
10.2	Amended and Restated Employment Agreement of Richard A. Boone dated May 31, 2011, incorporated by reference to Exhibit 10.17 of the Registration Statement on Form S-1 (File No. 333-175138), filed on June 24, 2011.
10.3	Amended and Restated Credit Agreement, dated July 29, 2011 by and among Rhino Energy LLC, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets and Union Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners, Union Bank, N.A., as Syndication Agent, Raymond James Bank, FSB, Wells Fargo Bank, National Association and the Huntington National Bank, as Co-Documentation Agents and the guarantors and lenders party thereto, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on August 4, 2011.
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)

64

Exhibit Number	Description
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)
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF§	XBRL Taxonomy Definition Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document

The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1 and 32.2) with this Form 10-Q.

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

65

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 12, 2011	By:	/s/ David G. Zatezalo
		David G. Zatezalo
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: August 12, 2011	By:	/s/ Richard A. Boone
		Richard A. Boone
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

66