10-Q

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 September 30, 2011

OR

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

For the transition period from                  to                   

Commission file number 001-34892

RHINO RESOURCE PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware (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).  oYes  x  No

As of November 11, 2011, 15,308,370 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 September 30, 2011 and December 31, 2010	2
	Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2011 and 2010	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 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	24
Item 3.	Quantatative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	59
PART II—Other Information		61
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	63
Item 3.	Defaults upon Senior Securities	63
Item 4.	[Removed and Reserved]	63
Item 5.	Other Information	63
Item 6.	Exhibits	68
SIGNATURES		70

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains certain “forward-looking statements.” Statements included in this report that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are reasonable as and when made. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements.

Any differences could be caused by a number of factors, including, but not limited to: changes in governmental regulation of the mining industry or the electric utility industry; adverse weather conditions and natural disasters; weakness in global economic conditions; decreases in demand for electricity and changes in demand for coal; poor mining conditions resulting from geological conditions or the effects of prior mining; equipment problems at mining locations; the availability of transportation for coal shipments; the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives; the availability and prices of competing electricity generation fuels; our ability to secure or acquire high-quality coal reserves; and our ability to find buyers for coal under favorable supply contracts. Other factors that could cause our actual results to differ from our projected results are described in (1) Part II, “Item 1A. Risk Factors” and elsewhere in this Form 10-Q, (2) our Annual Report on Form 10-K for the year ended December 31, 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)

	September 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	296		$	76
Accounts receivable, net of allowance for doubtful accounts ($0 as of September 30, 2011 and $19 as of December 31, 2010)	34,748			27,351
Inventories	14,013			15,635
Advance royalties, current portion	1,214			1,918
Prepaid expenses and other	4,444			5,376
Total current assets	54,715			50,356
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	603,868			442,112
Less accumulated depreciation, depletion and amortization	(183,086		)	(159,535		)
Net property, plant and equipment	420,782			282,577
Advance royalties, net of current portion	2,387			2,935
Investment in unconsolidated affiliate	20,597			18,749
Goodwill	202			202
Intangible assets	684			719
Other non-current assets	7,119			3,107
TOTAL	$	506,486		$	358,645
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	21,322		$	15,493
Accrued expenses and other	18,204			12,969
Current portion of long-term debt	1,994			2,908
Current portion of asset retirement obligations	3,861			4,350
Current portion of postretirement benefits	160			160
Total current liabilities	45,541			35,880
NON-CURRENT LIABILITIES:
Long-term debt	115,270			33,620
Asset retirement obligations	28,306			31,341
Other non-current liabilities	4,177			3,706
Postretirement benefits	7,003			6,481
Total non-current liabilities	154,756			75,148
Total liabilities	200,297			111,028
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners	293,903			236,582
General partner	11,661			10,410
Accumulated other comprehensive income	625			625
Total partners’ capital	306,189			247,617
TOTAL	$	506,486		$	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						Nine Months
	Ended September 30,						Ended September 30,
	2011			2010			2011			2010
REVENUES:
Coal sales	$	81,988		$	80,982		$	244,367		$	217,718
Freight and handling revenues	1,548			1,192			4,118			3,139
Other revenues	10,028			3,055			17,710			9,403
Total revenues	93,564			85,229			266,195			230,260
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	69,004			61,009			197,477			165,201
Freight and handling costs	1,331			913			3,271			2,357
Depreciation, depletion and amortization	9,157			8,343			26,513			24,146
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	6,350			4,074			15,345			11,677
(Gain) loss on sale/acquisition of assets—net	(2,702		)	(10,784		)	(2,836		)	(10,830		)
Total costs and expenses	83,140			63,555			239,770			192,551
INCOME FROM OPERATIONS	10,424			21,674			26,425			37,709
INTEREST & OTHER INCOME (EXPENSE):
Interest expense and other	(1,850		)	(1,469		)	(4,274		)	(4,251		)
Interest income and other	14			5			50			24
Equity in net income of unconsolidated affiliate	1,258			1,598			3,158			2,012
Total interest and other income (expense)	(578		)	134			(1,066		)	(2,215		)
INCOME BEFORE INCOME TAXES	9,846			21,808			25,359			35,494
INCOME TAXES	—			—			—			—
NET INCOME	$	9,846		$	21,808		$	25,359		$	35,494
Other comprehensive income -
Amortization. of actuarial gain under ASC Topic 815				(113		)				(113		)
COMPREHENSIVE INCOME	$	9,846		$	21,695		$	25,359		$	35,381
General partner’s interest in net income	$	197		n/a			$	507		n/a
Common unitholders’ interest in net income	$	5,240		n/a			$	12,718		n/a
Subordinated unitholders’ interest in net income	$	4,409		n/a			$	12,134		n/a
Net income per limited partner unit, basic:
Common units	$	0.36		n/a			$	0.98		n/a
Subordinated units	$	0.36		n/a			$	0.98		n/a
Net income per limited partner unit, diluted:
Common units	$	0.36		n/a			$	0.98		n/a
Subordinated units	$	0.36		n/a			$	0.98		n/a
Distributions paid per limited partner unit	$	0.455		n/a			$	1.3308		n/a
Weighted average number of limited partner units outstanding, basic:
Common units	14,732			n/a			12,993			n/a
Subordinated units	12,397			n/a			12,397			n/a
Weighted average number of limited partner units outstanding, diluted:
Common units	14,747			n/a			13,014			n/a
Subordinated units	12,397			n/a			12,397			n/a

 See notes to unaudited condensed consolidated financial statements.

3

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Nine Months Ended September 30
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	25,359		$	35,494
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	26,513			24,146
Accretion on asset retirement obligations	1,469			1,627
Accretion on interest-free debt	157			149
Amortization of advance royalties	906			697
Amortization of deferred revenue	(361		)	—
Amortization of debt issuance costs	774			—
Provision (reversal) for doubtful accounts	(19		)	—
Equity in net (income) of unconsolidated affiliate	(3,158		)	(2,012		)
Loss on retirement of advance royalties	79			390
(Gain) on sale/acquisition of assets—net	(2,836		)	(10,830		)
Equity-based compensation	643			—
Changes in assets and liabilities:
Accounts receivable	(4,913		)	(5,372		)
Inventories	1,621			(2,514		)
Advance royalties	(981		)	(1,269		)
Prepaid expenses and other assets	1,074			(820		)
Accounts payable	5,657			1,074
Accrued expenses and other liabilities	779			2,796
Asset retirement obligations	(1,967		)	(1,239		)
Postretirement benefits	521			548
Net cash provided by operating activities	51,317			42,865
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(64,606		)	(19,340		)
Proceeds from sales of property, plant, and equipment	1,841			93
Proceeds from sale of coal properties and related assets and liabilities	20,000			—
Principal payments received on notes receivable	5,270			1,142
Cash advances from isssuance of notes receivable	(5,270		)	(765		)
Changes in restricted cash	34			(3		)
Acquisition of coal companies and other properties	(119,299		)	(15,000		)
Return of capital from unconsolidated affiliate	1,311			—
Net cash used in investing activities	(160,719		)	(33,873		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	276,350			93,300
Repayments on line of credit	(194,450		)	(101,996		)
Proceeds from issuance of long-term debt	1,379
Repayments on long-term debt	(2,700		)	—
Net settlement of withholding taxes on employee unit awards vesting	(164		)	—
Debt issuance costs	(3,758		)	(783		)
Partner contributions	1,444			—
Distributions to unitholders	(35,038		)	—
Proceeds from issuance of common units, net of issuance costs	66,916			—
Payment of offering costs	(357		)	—
Net cash provided by (used in) financing activities	109,622			(9,479		)
NET INCREASE (DECREASE) CASH AND CASH EQUIVALENTS	220			(487		)
CASH AND CASH EQUIVALENTS—Beginning of period	76			687
CASH AND CASH EQUIVALENTS—End of period	$	296		$	200

See notes to unaudited condensed consolidated financial statements.

4

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011 AND DECEMBER 31, 2010 AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 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 nine months ended September 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 nine months ended September 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 September 30, 2011, condensed consolidated statements of operations for the three and nine month periods ended September 30, 2011 and 2010 and the condensed consolidated statements of cash flows for the nine months ended September 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. In addition to operating coal properties, the Operating Company manages and leases coal properties and collects royalties from such management and leasing activities. The Operating Company was formed in April 2003 and has been built via acquisitions.

In addition to the Operating Company’s coal operations, the Partnership has invested in oil and gas mineral rights that the Partnership expects to generate royalty revenues in future periods.

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.

Follow-on Offering

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

6

approximately $66.6 million, after deducting underwriting discounts and offering expenses of approximately $3.9 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 $68.0 million of outstanding indebtedness under the Partnership’s credit facility.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Investment in Joint Venture.  Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Partnership is determined to be the primary beneficiary. 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 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 and third quarters of 2011, the joint venture borrowed approximately $5.3 million from the Partnership. As of September 30, 2011, the joint venture had repaid the entire amount borrowed.

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 that owns or controls coal reserves and non-reserve coal deposits and surface acreage in eastern Kentucky. Elk Horn is expected to provide the Partnership 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

7

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. The Partnership completed a public offering of the Partnership’s common units in July 2011 that provided proceeds the Partnership used to repay existing indebtedness on its credit facility that was incurred from the Elk Horn acquisition. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date:

	(in thousands)
Cash	$	197
Accounts receivable	2,466
Prepaid expenses and other	95
Property, plant and equipment	7,113
Coal properties	112,522
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, 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. 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

8

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

Acquisition-related costs incurred 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 net income from Elk Horn prior to June 10, 2011, the effective date of the acquisition. The post-acquisition revenue of Elk Horn that is included in the Partnership’s results was approximately $5.9 million and $6.9 million for the three and nine months ended September 30, 2011, respectively. The post-acquisition net income of Elk Horn that is included in the Partnership’s results was approximately $3.8 million and $4.4 million for the three and nine months ended September 30, 2011, respectively.

The following table presents selected unaudited pro forma financial information for the three and nine months ended September 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. Supplemental pro forma revenue, net earnings and earnings per unit disclosures are as follows.

9

	Three months ended September 30,					Nine months ended September 30,
	2011			2010		2011		2010
	(in thousands)
Revenues:
As reported	$	93,564		$	85,229	$	266,195	$	230,260
Pro forma adjustments	—			3,081		9,477		6,529
Pro forma revenues	$	93,564		$	88,310	$	275,672	$	236,789
Net Income:
As reported	$	9,846		$	21,808	$	25,359	$	35,494
Pro forma adjustments	(158		)	1,018		2,549		1,265
Pro forma net income	$	9,688		$	22,826	$	27,908	$	36,759
Net income per limited partner unit, diluted:
As reported	$	0.36		n/a		$	0.98	n/a
Pro forma adjustments	$	(0.02	)	n/a		$	0.01	n/a
Pro forma net income	$	0.34		n/a		$	0.99	n/a

Acquisition of Oil and Gas Mineral Rights

During the three and nine months ended September 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 $0.3 million and approximately $6.1 million, respectively. In October 2011, the Partnership acquired additional oil and gas mineral rights for approximately $2.0 million to bring its total investment in the Cana Woodford region to approximately $8.1 million. The Partnership expects royalty revenues to be generated from these mineral rights in future periods.

The Partnership and an affiliate of Wexford Capital have participated with Gulfport Energy, a publicly traded company, to acquire an interest in a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately 16.8% of the common stock of Gulfport Energy as of September 30, 2011. During the three and nine months ended September 30, 2011, the Partnership completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $12.8 million and approximately $19.9 million, respectively. The Partnership is evaluating future alternatives for its Utica Shale investment.

Acquisition of Coal Property

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

10

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.

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

11

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 September 30, 2011 and December 31, 2010 consisted of the following:

	September 30,		December 31,
	2011		2010
	(in thousands)
Other prepaid expenses	$	620	$	929
Prepaid insurance	2,225		3,239
Prepaid leases	110		82
Supply inventory	1,319		956
Deposits	170		170
Total	$	4,444	$	5,376

5. PROPERTY, PLANT AND EQUIPMENT

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

	Useful Lives	September 30, 2011			December 31, 2010
		(in thousands)
Land and Land Improvements		$	32,893		$	25,748
Mining and other equipment and related facilities	2 - 20 Years	231,516			218,886
Mine development costs	1 - 15 Years	59,987			56,857
Coal properties	1 - 15 Years	263,263			132,431
Construction work in process		16,209			8,190
Total		603,868			442,112
Less accumulated depreciation, depletion and amortization		(183,086		)	(159,535		)
Net		$	420,782		$	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 nine months ended September 30, 2011 and 2010 were as follows:

12

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	6,488	$	6,803	$	19,769	$	20,238
Depletion expense for coal properties	1,510		470		3,358		1,441
Amortization expense for mine development costs	809		639		2,358		1,473
Amortization expense for intangible assets	12		12		36		75
Amortization expense for asset retirement costs	338		419		992		919
Total depreciation, depletion and amortization	$	9,157	$	8,343	$	26,513	$	24,146

Sale of Mining Assets

In August 2011, the Partnership closed on an agreement to sell and assign certain non-core mining assets and related liabilities located in the Phelps, Kentucky area of the Partnership’s Tug River mining complex for $20 million.  The mining assets include leasehold interests and permits to surface and mineral interests that include steam coal reserves and non-reserve coal deposits.  Additionally, the sales agreement includes the potential for additional payments of approximately $8.75 million dependent upon the future issuance of certain permits and the commencement of mining activities by the purchaser. These contingent payments are being accounted for as gain contingencies and will be recognized in the future when and if the contingencies are resolved. The transaction also transfers certain liabilities related to the assets sold. In relation to the sale of these assets and transfer of liabilities, the Partnership recorded a gain of approximately $2.4 million, which is included on the (Gain) loss on sale/acquisition of assets—net line of the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

6. GOODWILL AND INTANGIBLE ASSETS

ASC Topic 350 addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under the provisions of ASC Topic 350, goodwill and other intangible assets with indefinite useful lives are no longer amortized but instead tested for impairment at least annually. The Partnership has included goodwill in its Other category, as described in Note 18, “Segment Information,” for segment reporting purposes.

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

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

13

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

	Gross				Net
	Carrying		Accumulated		Carrying
	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	110	$	618
Developed Technology	78		12		66
Total	$	806	$	122	$	684

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 September 30, 2011:

			Developed
	Patent		Technology		Total
	(in thousands)
2011 (from Oct 1 to December 31)	$	11	$	1	$	12
2012	43		5		48
2013	43		5		48
2014	43		5		48
2015	43		5		48

7. OTHER NON-CURRENT ASSETS

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

14

	September 30,		December 31,
	2011		2010
	(in thousands)
Deposits and other	$	1,895	$	840
Debt issuance costs—net	5,194		2,211
Deferred expenses	30		56
Total	$	7,119	$	3,107

Debt issuance costs were approximately $8.1 million and approximately $4.3 million as of September 30, 2011 and December 31, 2010, respectively. Accumulated amortization of debt issuance costs were approximately $2.9 million and approximately $2.1 million as of September 30, 2011 and December 31, 2010, respectively.

8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

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

	September 30,		December 31,
	2011		2010
	(in thousands)
Payroll, bonus and vacation expense	$	4,230	$	3,570
Non income taxes	4,004		3,020
Royalty expenses	2,153		2,184
Accrued interest	679		460
Health claims	1,135		2,046
Workers’ compensation & pneumoconiosis	1,400		1,400
Deferred revenues	2,194		—
Other	2,409		289
Total	$	18,204	$	12,969

15

9. DEBT

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

	September 30,			December 31,
	2011			2010
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$	110,370		$	28,470
Note payable to H&L Construction Co., Inc.	2,459			2,973
Other notes payable	4,435			5,085
Total	117,264			36,528
Less current portion	(1,994		)	(2,908		)
Long-term debt	$	115,270		$	33,620

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

On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit. Borrowings under the facility bear interest, which varies depending upon the levels of certain financial ratios. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability that also varies depending upon the levels of certain financial ratios. Borrowings on the amended and restated senior secured credit facility are collateralized by all the unsecured assets of the Partnership. The amended and restated senior secured credit facility requires the Partnership to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Partnership was in compliance with all covenants contained in the amended and restated senior secured credit facility as of and for the period ended September 30, 2011. The amended and restated senior secured credit facility expires in July 2016.

16

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

At September 30, 2011, the Operating Company had borrowed $105.0 million at a variable interest rate of LIBOR plus 3.00% (3.23% at September 30, 2011) and an additional $5.4 million at a variable interest rate of PRIME plus 2.00% (5.25% at September 30, 2011). In addition, the Operating Company had outstanding letters of credit of approximately $26.0 million at a fixed interest rate of 3.00% at September 30, 2011. The Operating Company had not used $163.6 million of the borrowing availability at September 30, 2011.

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 $2.5 million as of September 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 $11.6 million and approximately $11.8 million as of September 30, 2011 and December 31, 2010, respectively.

10. ASSET RETIREMENT OBLIGATIONS

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

	Nine months ended September 30, 2011			Year ended December 31, 2010
	(in thousands)
Balance at beginning of period (including current portion)	$	35,691		$	45,101
Accretion expense	1,469			2,165
Adjustment resulting from addition of property	511			933
Adjustment resulting from disposal of property	(3,537		)	—
Adjustments to the liability from annual recosting and other	—			(10,202		)
Liabilities settled	(1,967		)	(2,306		)
Balance at end of period	32,167			35,691
Current portion of asset retirement obligation	3,861			4,350
Long-term portion of asset retirement obligation	$	28,306		$	31,341

11. EMPLOYEE BENEFITS

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

17

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service costs	$	116	$	122	$	349	$	337
Interest cost	74		83		222		219
Total	$	190	$	205	$	571	$	556

401(k) Plans—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Operating Company’s discretion. The expense under these plans for the three and nine months ended September 30, 2011 and 2010 was as follows:

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(in thousands)
401(k) plan expense	$	583	$	454	$	1,652	$	1,430

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 September 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 did not incur incremental compensation expense for the three months ended September 30, 2011 since the market price of the Partnership’s common units was below the IPO grant price. The Partnership recorded approximately $0.2 million in incremental compensation expense for the nine months ended September 30, 2011 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 September 30, 2011.

18

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of September 30, 2011, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of approximately 1.2 million, approximately 2.4 million, approximately 1.9 million and approximately 0.5 million tons of coal to 21 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.

Purchase Commitments—As of September 30, 2011, the Partnership had approximately 1.0 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2011 for approximately $2.6 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”). Purchased coal expense from coal purchase contracts and expense from OTC purchases for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(in thousands)
Purchased coal expense	$	1,326	$	1,289	$	6,211	$	3,109
OTC expense	$	771	$	791	$	785	$	2,907

There were no outstanding coal purchase commitments as of September 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 nine months ended September 30, 2011 and 2010 was as follows:

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(in thousands)
Lease expense	$	607	$	1,351	$	1,924	$	4,438
Royalty expense	$	3,692	$	3,112	$	11,444	$	9,312

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 nine months ended September 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.

19

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 September 30, 2011:

Three months ended September 30, 2011	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	197	$	5,240	$	4,409
Denominator:
Weighted avg units used to compute basic EPU	n/a		14,732		12,397
Effect of dilutive securities — LTIP awards	n/a		15		—
Weighted avg units used to compute diluted EPU	n/a		14,747		12,397
Net income per limited partner unit, basic	n/a		$	0.36	$	0.36
Net income per limited partner unit, diluted	n/a		$	0.36	$	0.36

Nine months ended September 30, 2011	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	507	$	12,718	$	12,134
Denominator:
Weighted avg units used to compute basic EPU	n/a		12,993		12,397
Effect of dilutive securities — LTIP awards	n/a		21		—
Weighted avg units used to compute diluted EPU	n/a		13,014		12,397
Net income per limited partner unit, basic	n/a		$	0.98	$	0.98
Net income per limited partner unit, diluted	n/a		$	0.98	$	0.98

15. MAJOR CUSTOMERS

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

	September 30,		Nine months		Nine months
	2011		ended		ended
	Receivable		September 30,		September 30,
	Balance		2011 Sales		2010 Sales
	(in thousands)
GenOn Energy, Inc. (fka Mirant Corporation)	$	3,707	$	44,178	$	31,530
Indiana Harbor Coke Company, L.P	4,199		29,812		40,351
American Electric Power Company, Inc.	3,902		34,273		25,800

20

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 September 30, 2011.

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2011 excludes approximately $1.8 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 nine months ended September 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

21

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 September 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	$	53,443	$	32,568	$	6,044		$	14,323	$	(14,323	)	$	—	$	1,509		$	93,564
DD&A	5,550		1,992		857			754		(754		)	—		758			9,157
Interest expense	691		675		201			32		(32		)	—		283			1,850
Net Income (loss)	$	3,904	$	6,313	$	(427	)	$	2,466	$	(1,208	)	$	1,258	$	(1,202	)	$	9,846

Reportable segment results of operations for the three months ended September 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	$	56,949	$	24,314	$	2,329	$	11,173	$	(11,173	)	$	—	$	1,637		$	85,229
DD&A	5,073		2,103		118		790		(790		)	—		1,049			8,343
Interest expense	610		556		65		11		(11		)	—		238			1,469
Net Income (loss)	$	7,821	$	2,586	$	11,014	$	3,134	$	(1,536	)	$	1,598	$	(1,211	)	$	21,808

Reportable segment results of operations for the nine months ended September 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	$	158,092	$	90,306	$	13,065		$	37,093	$	(37,093	)	$	—	$	4,732		$	266,195
DD&A	15,948		6,177		2,117			2,328		(2,328		)	—		2,271			26,513
Interest expense	1,640		1,429		360			49		(49		)	—		845			4,274
Net Income (loss)	$	10,336	$	18,036	$	(2,327	)	$	6,193	$	(3,035	)	$	3,158	$	(3,844	)	$	25,359

22

Reportable segment results of operations for the nine months ended September 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	$	147,207	$	70,995	$	7,134	$	24,850	$	(24,850	)	$	—	$	4,924		$	230,260
DD&A	14,587		6,077		354		2,331		(2,331		)	—		3,128			24,146
Interest expense	1,832		1,622		172		50		(50		)	—		625			4,251
Net Income (loss)	$	18,024	$	7,212	$	12,014	$	3,946	$	(1,934	)	$	2,012	$	(3,768	)	$	35,494

19. SUBSEQUENT EVENTS

On October 21, 2011, the Partnership announced a cash distribution of $0.48 per common unit and subordinated unit, or $1.92 per unit on an annualized basis. This total distribution of approximately $13.6 million, which includes approximately $0.3 million paid to the Partnership’s General Partner for their proportionate ownership interest, was paid on November 14, 2011 to all unitholders of record as of the close of business on November 1, 2011.

23

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 for periods prior to the completion of the initial public offering of Rhino Resource Partners LP on October 5, 2010 (the “IPO”) refer to Rhino Energy LLC and its subsidiaries. When used for periods subsequent to the completion of the IPO, “we,” “our,” “us,” or similar terms refer to Rhino Resource Partners LP and its subsidiaries. References to our “general partner” refer to Rhino GP LLC, the general partner of Rhino Resource Partners LP.

For ease and comparability purposes in comparing 2011 to 2010 results, the results of Rhino Resource Partners LP and Rhino Predecessor 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 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. In addition to our coal operations, we have invested in oil and gas mineral rights that we expect to generate royalty revenues in future periods, which we believe will help to diversify our income stream.

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

24

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 premium mid-vol and low-vol metallurgical coal, and an estimated 34.3 million tons of non-reserve coal deposits. As of September 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 nine months ended September 30, 2011, we generated revenues of approximately $93.6 million and approximately $266.2 million, respectively, and net income of approximately $9.8 million and approximately $25.4 million, respectively. Excluding results from the joint venture, for the three and nine months ended September 30, 2011, we produced approximately 1.2 million tons and approximately 3.5 million tons of coal, respectively, and sold approximately 1.2 million tons and approximately 3.6 million tons of coal, respectively. Excluding results from the joint venture, for the three and nine months ended September 30, 2011, approximately 79% and approximately 80%, respectively, of the tons sold were sold pursuant to supply contracts. Additionally, for the three and nine months ended September 30, 2011, the joint venture produced and sold approximately 0.1 million tons and approximately 0.2 million tons, respectively, of premium mid-vol metallurgical coal.

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 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

25

also help accelerate development of our contiguous northern Deane complex properties. The Elk Horn acquisition was funded with borrowings available under our credit facility, which were subsequently repaid with proceeds from an offering of our common units.

Acquisition of Oil and Gas Mineral Rights

During the three and nine months ended September 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 $0.3 million and approximately $6.1 million, respectively. In October 2011, we acquired additional oil and gas mineral rights for approximately $2.0 million to bring our total investment in the Cana Woodford region to approximately $8.1 million. We expect royalty revenues to be generated from these mineral rights in future periods.

We and an affiliate of Wexford Capital LP (“Wexford Capital”) have participated with Gulfport Energy, a publicly traded company, to acquire an interest in a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately 16.8% of the common stock of Gulfport Energy. During the three and nine months ended September 30, 2011, we completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $12.8 million and approximately $19.9 million, respectively.  Based on recent lease transactions in this region, we believe our Utica Shale investment could possibly provide a significant return.

Acquisition of Coal Property

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

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

Acquisition of the 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.

Sale of Mining Assets

In August 2011, we closed on an agreement to sell and assign certain non-core mining

26

assets and related liabilities located in the Phelps, Kentucky area of our Tug River mining complex for approximately $20 million.  The mining assets include leasehold interests and permits to surface and mineral interests that include steam coal reserves and non-reserve coal deposits.  Additionally, the sales agreement includes the potential for additional payments of approximately $8.75 million dependent upon the future issuance of certain permits and the commencement of mining activities by the purchaser.  The transaction also transfers certain liabilities related to the assets sold that we believe will positively impact future cash flows, while also supplying an immediate inflow of cash that we can utilize in our current operations.  Since we had limited mining operations on the assets that were sold, we believe the sale of these assets will not have a negative impact on our future financial results.

In relation to the sale of these assets and transfer of liabilities, we recorded a gain of approximately $2.4 million.

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. 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, 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 $66.6 million, after deducting underwriting discounts and offering expenses of approximately $3.9 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 $68.0 million of outstanding indebtedness under our credit facility.

27

Credit Facility

On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million.

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 September 30, 2011, we had commitments under sales contracts to deliver annually scheduled base quantities of approximately 1.2 million, approximately 2.4 million, approximately 1.9 million and approximately 0.5 million tons of coal to 21 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 September 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 September 30, 2011. Our Sands Hill mining complex, located in northern Ohio, included two surface mines, a preparation plant and a river terminal as of September 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

28

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 Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. As of September 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) Adjusted EBITDA, (2) coal revenues per ton and (3) cost of operations per ton.

Adjusted EBITDA.  The discussion of our results of operations below includes references to, and analysis of, our segments’ Adjusted EBITDA results. Adjusted EBITDA represents net income before deducting interest expense, income taxes and depreciation, depletion and amortization, including Rhino’s proportionate share of these expense items from its Rhino Eastern LLC joint venture, while also excluding certain non-recurring items. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Adjusted EBITDA should not be considered an alternative to net income, income from operations, cash flows from operating activities or any other measure of financial performance or liquidity 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 Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted 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 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.

29

Summary

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the three and nine months ended September 30, 2011 and 2010:

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
	(in millions)
Statement of Operations Data:
Total revenues	$	93.6		$	85.2		$	266.2		$	230.3
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	69.0			61.0			197.5			165.2
Freight and handling costs	1.3			0.9			3.3			2.4
Depreciation, depletion and amortization	9.2			8.3			26.5			24.1
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	6.4			4.1			15.4			11.7
(Gain) loss on sale/acquisition of assets	(2.7		)	(10.8		)	(2.8		)	(10.8		)
Income from operations	10.4			21.7			26.3			37.7
Interest and other income (expense):
Interest expense	(1.9		)	(1.5		)	(4.2		)	(4.2		)
Interest income	—			—			0.1			—
Equity in net income (loss) of unconsolidated affiliate	1.3			1.6			3.2			2.0
Total interest and other income (expense)	(0.6		)	0.1			(0.9		)	(2.2		)
Net income	$	9.8		$	21.8		$	25.4		$	35.5
Other Financial Data
Adjusted EBITDA †	$	21.3		$	21.2		$	57.4		$	54.2

† Refer to “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA to net income for each of the periods indicated.

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

Summary.  For the three months ended September 30, 2011, our total revenues increased to $93.6 million from $85.2 million for the three months ended September 30, 2010. We sold 1.2 million tons of coal for the three months ended September 30, 2011, which is a 7.0% increase compared to the tons of coal sold for the three months ended September 30, 2010. This increase was primarily 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 decreased while Adjusted EBITDA was relatively flat for the three months ended September 30, 2011 from the three months ended September 30, 2010.   Net income was approximately $9.8 million for the three months ended September 30, 2011 compared to net income of approximately $21.8 million (or $11.0 million excluding a $10.8 million gain from the Castle Valley acquisition) for the three months ended September 30, 2010. In addition to the

30

Castle Valley gain, net income decreased for the three months ended September 30, 2011 from the three months ended September 30, 2010 primarily due to a lower amount of metallurgical coal sold in our Central Appalachia region, which was partially offset by higher revenues from increased steam coal tons sold as well as increased contract prices for steam coal. Net income was also impacted period to period due to $1.3 million of income from our Rhino Eastern joint venture for the three months ended September 30, 2011 compared to income of $1.6 million for the three months ended September 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.

Adjusted EBITDA was $21.3 million for the three months ended September 30, 2011 compared to $21.2 million for the three months ended September 30, 2010 as lower net income in the 2011 period was offset by higher depreciation, depletion and amortization expense as well as higher interest expense when compared to 2010.

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

	Three months	Three months	Increase/
	ended	ended	(Decrease)
Segment	September 30, 2011	September 30, 2010	Tons	% *
	(in millions, except %)
Central Appalachia	0.6	0.6	—	(9.3	)%
Northern Appalachia	0.6	0.5	0.1	10.7	%
Rhino Western	0.1	0.1	—	159.7	%
Total *†	1.2	1.2	—	7.0	%

*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 September 30, 2011, which is relatively flat compared to the approximately 1.2 million tons sold in the three months ended September 30, 2010. Based upon actual versus rounded amounts, our tons sold increased, which 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 segment remained relatively constant at approximately 0.6 million tons for both the three months ended September 30, 2011 and 2010, while tons sold in our Northern Appalachia segment increased slightly to approximately 0.6 million tons from 0.5 million tons for the three months ended September 30, 2011 and 2010, respectively. Coal sales from our Rhino Western segment also remained constant at approximately 0.1 million tons for the three months ended September 30, 2011 and 2010, but increased 159.7% based upon whole numbers due to the increased production at Castle Valley.

31

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

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	September 30, 2011		September 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	46.4	$	56.8	$	(10.4	)	(18.4	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	7.1		0.2		6.9			3741.4	%
Total revenues	$	53.5	$	57.0	$	(3.5	)	(6.2	)%
Coal revenues per ton*	$	82.93	$	92.18	$	(9.25	)	(10.0	)%
Northern Appalachia
Coal revenues	$	29.6	$	21.9	$	7.7		35.3	%
Freight and handling revenues	1.6		1.2		0.4			29.9	%
Other revenues	1.4		1.2		0.2			14.6	%
Total revenues	$	32.6	$	24.3	$	8.3		33.9	%
Coal revenues per ton*	$	53.59	$	43.87	$	9.72		22.2	%
Rhino Western
Coal revenues	$	6.0	$	2.3	$	3.7		159.7	%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	6.0	$	2.3	$	3.7		159.5	%
Coal revenues per ton*	$	43.65	$	43.65	$	—		0.0	%
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	1.5		1.6		(0.1		)	(7.8	)%
Total revenues	$	1.5	$	1.6	$	(0.1	)	(7.8	)%
Coal revenues per ton	n/a		n/a		n/a			n/a
Total
Coal revenues	$	82.0	$	81.0	$	1.0		1.2	%
Freight and handling revenues	1.6		1.2		0.4			29.9	%
Other revenues	10.0		3.0		7.0			228.3	%
Total revenues	$	93.6	$	85.2	$	8.4		9.8	%
Coal revenues per ton*	$	65.61	$	69.32	$	(3.71	)	(5.4	)%

*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.

Our coal revenues for the three months ended September 30, 2011 increased by approximately $1.0 million, or 1.2%, to approximately $82.0 million from approximately $81.0 million for the three months ended September 30, 2010. The increase in coal revenues was due to a slight increase in volume of tons sold as well as higher contracted and spot prices for steam

32

coal. Coal revenues per ton were $65.61 for the three months ended September 30, 2011, a decrease of $3.71, or 5.4%, from $69.32 per ton for the three months ended September 30, 2010. This decrease in coal revenues per ton was primarily the result of lower amounts of metallurgical coal sold in our Central Appalachia segment, partially offset by higher contracted and spot prices for steam coal in our Northern Appalachia segment.

For our Central Appalachia segment, coal revenues decreased by approximately $10.4 million, or 18.4%, to approximately $46.4 million for the three months ended September 30, 2011 from approximately $56.8 million for the three months ended September 30, 2010 due to a decreased volume in tons sold of metallurgical coal. Coal revenues per ton for our Central Appalachia segment decreased by $9.25, or 10.0%, to $82.93 per ton for the three months ended September 30, 2011 as compared to $92.18 for the three months ended September 30, 2010, primarily due to lower amounts of metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to approximately $5.9 million of coal royalty revenue from Elk Horn.

For our Northern Appalachia segment, coal revenues were approximately $29.6 million for the three months ended September 30, 2011, an increase of approximately $7.7 million, or 35.3%, from approximately $21.9 million for the three months ended September 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 $9.72, or 22.2%, to $53.59 per ton for the three months ended September 30, 2011 as compared to $43.87 per ton for the three months ended September 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 $3.7 million, or 159.7%, to approximately $6.0 million for the three months ended September 30, 2011 from approximately $2.3 million for the three months ended September 30, 2010, as a result of the increased production at our Castle Valley complex. Coal revenues per ton for our Rhino Western segment were $43.65 for the three months ended September 30, 2011, which was flat compared to the three months ended September 30, 2010.

Other revenues for our Other category were relatively flat period to period at approximately $1.5 million for the three months ended September 30, 2011 compared to approximately $1.6 million for the three months ended September 30, 2010.

33

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 September 30, 2011		Three months ended September 30, 2010		Increase (Decrease)  %*
Met coal tons sold	111.4		203.6		(45.3	)%
Steam coal tons sold	447.3		412.2		8.5	%
Total tons sold †	558.7		615.8		(9.3	)%
Met coal revenue	$	13,579	$	26,232	(48.2	)%
Steam coal revenue	$	32,758	$	30,532	7.3	%
Total coal revenue †	$	46,337	$	56,764	(18.4	)%
Met coal revenues per ton	$	121.90	$	128.86	(5.4	)%
Steam coal revenues per ton	$	73.23	$	74.06	(1.1	)%
Total coal revenues per ton †	$	82.93	$	92.18	(10.0	)%
Met coal tons produced	112.3		210.8		(46.7	)%
Steam coal tons produced	380.5		306.0		24.4	%
Total tons produced †	492.8		516.8		(4.6	)%

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

34

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 September 30, 2011 and 2010:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	September 30, 2011		September 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	39.2	$	38.9	$	0.3		0.9	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	5.5		5.1		0.4			9.4	%
Selling, general and administrative	6.1		3.8		2.3			58.1	%
Cost of operations per ton*	$	70.26	$	63.21	$	7.05		11.2	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	20.6	$	16.8	$	3.8		22.4	%
Freight and handling costs	1.3		0.9		0.4			45.9	%
Depreciation, depletion and amortization	2.0		2.1		(0.1		)	(5.3	)%
Selling, general and administrative	0.1		0.1		—			(8.7	)%
Cost of operations per ton*	$	37.30	$	33.74	$	3.56		10.5	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	4.7	$	1.8	$	2.9		169.0	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	0.9		0.1		0.8			627.8	%
Selling, general and administrative	—		—		—			154.2	%
Cost of operations per ton*	$	33.76	$	32.59	$	1.17		3.6	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	4.5	$	3.5	$	1.0		27.4	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	0.8		1.0		(0.2		)	(27.8	)%
Selling, general and administrative	0.2		0.2		—			38.6	%
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)	$	69.0	$	61.0	$	8.0		13.1	%
Freight and handling costs	1.3		0.9		0.4			45.9	%
Depreciation, depletion and amortization	9.2		8.3		0.9			9.8	%
Selling, general and administrative	6.4		4.1		2.3			55.9	%
Cost of operations per ton*	$	55.22	$	52.23	$	2.99		5.7	%

* 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.

35

Cost of Operations.  Total cost of operations was $69.0 million for the three months ended September 30, 2011 as compared to $61.0 million for the three months ended September 30, 2010. Our cost of operations per ton was $55.22 for the three months ended September 30, 2011, an increase of $2.99, or 5.7%, from the three months ended September 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. Cost of operations also increased in our Northern Appalachia segment due to higher prices for diesel fuel and explosives at our Sands Hill surface mine operations, as well as roof control and methane issues encountered at our Hopedale underground mine.

Our cost of operations for the Central Appalachia segment was relatively flat at $39.2 million for the three months ended September 30, 2011 compared to $38.9 million for the three months ended September 30, 2010. Our cost of operations per ton increased to $70.26 per ton for the three months ended September 30, 2011 from $63.21 per ton for three months ended September 30, 2010. The increase in cost of operations per ton was due to production issues encountered for the three months ended September 30, 2011, which included the loss of high-wall mine production at our Grapevine surface mine.

In our Northern Appalachia segment, our cost of operations increased by $3.8 million, or 22.4%, to $20.6 million for the three months ended September 30, 2011 from $16.8 million for the three months ended September 30, 2010. Our cost of operations per ton increased to $37.30 for the three months ended September 30, 2011 compared to $33.74 for the three months ended September 30, 2010, an increase of $3.56 per ton, or 10.5%. The increases in cost of operations and cost of operations per ton were primarily due to higher prices for diesel fuel and explosives at our Sands Hill surface mine operations, as well as roof control and methane issues encountered at our Hopedale underground mine.

Our cost of operations for the Rhino Western segment increased by $2.9 million, or 169.0%, to $4.7 million for the three months ended September 30, 2011 from $1.8 million for the three months ended September 30, 2010. Our cost of operations per ton increased to $33.76 per ton for the three months ended September 30, 2011 from $32.59 per ton for three months ended September 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 $1.0 million for the three months ended September 30, 2011 as compared to the three months ended September 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 September 30, 2011 increased by $0.4 million, or 45.9%, to $1.3 million from $0.9 million for the three months ended September 30, 2010. This increase was primarily due to the increase in the number of tons sold for the three months ended September 30, 2011 as compared to the three months ended September 30, 2010, as well as higher fuel prices.

36

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization (“DD&A”) expense for the three months ended September 30, 2011 was $9.2 million as compared to $8.3 million for the three months ended September 30, 2010.

For the three months ended September 30, 2011, our depreciation cost decreased slightly to approximately $6.5 million compared to $6.8 million for the three months ended September 30, 2010.

For the three months ended September 30, 2011, our depletion cost was $1.5 million compared to $0.5 million for the three months ended September 30, 2010. This increase is primarily attributable to the increase in tons sold for the period ended September 30, 2011 as compared to the period ended September 30, 2010.

For the three months ended September 30, 2011 and 2010, our amortization cost was relatively flat at $1.2 million compared to $1.0 million, respectively.

Selling, General and Administrative.  Selling, general and administrative (“SG&A”) expense for the three months ended September 30, 2011 increased to $6.4 million as compared to $4.1 million for the three months ended September 30, 2010. The increase in SG&A expense is primarily attributable to the costs associated with being a publicly traded partnership, including an increase in expenditures for legal fees and other professional fees.

Interest Expense.  Interest expense for the three months ended September 30, 2011 was $1.9 million as compared to $1.5 million for the three months ended September 30, 2010, an increase of $0.4 million, or 25.9%. This increase was the result of an increase in the balance outstanding under our credit facility, primarily resulting from the acquisition of Elk Horn.

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.

37

(In thousands, except per ton data and %)	Three months  ended  September  30, 2011		Three months  ended  September  30, 2010		Increase  (Decrease)  %*
Eastern Met 100% Basis
Coal revenues	$	14,305	$	11,161	28.2	%
Total revenues	$	14,323	$	11,173	28.2	%
Coal revenues per ton*	$	207.17	$	198.85	4.2	%
Cost of operations	$	10,320	$	6,539	57.8	%
Cost of operations per ton*	$	149.46	$	116.51	28.3	%
Depreciation, depletion and amortization	$	754	$	790	(4.5	)%
Interest expense	$	32	$	11	186.6	%
Net income (loss)	$	2,466	$	3,134	(21.3	)%
Partnership’s portion of net income (loss)	$	1,258	$	1,598	(21.3	)%
Tons produced	71.8		56.9		26.1	%
Tons sold	69.1		56.1		23.0	%

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

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 to production, tons produced and tons sold in the third quarter of 2011 increased compared to the results from the same period in 2010, which also resulted in increased revenue. However, net income decreased slightly year-to-year primarily due to higher labor costs.

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

	Three months ended			Three months ended			Increase
Segment	September 30, 2011			September 30, 2010			(Decrease)
	(in millions)
Central Appalachia	$	3.9		$	7.8		$	(3.9	)
Northern Appalachia	6.3			2.6			3.7
Rhino Western *	(0.5		)	11.0			(11.5		)
Eastern Met **	1.3			1.6			(0.3		)
Other	(1.2		)	(1.2		)	—
Total	$	9.8		$	21.8		$	(12.0	)

*During the third quarter of 2010, we 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, located in Emery and Carbon Counties, Utah (referred to as our Castle Valley mining complex). Because the fair value

38

of the assets acquired exceeded the purchase price, we recorded a non-cash gain of $10.8 million that is reflected in our third quarter 2010 financial results for Rhino Western. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy.

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

For the three months ended September 30, 2011, total net income decreased to approximately $9.8 million compared to net income of approximately $21.8 million (or $11.0 million excluding a $10.8 million gain from the Castle Valley acquisition) for the three months ended September 30, 2010. In addition to the Castle Valley gain, net income decreased for the three months ended September 30, 2011 compared to the same period in 2010 primarily due to increased cost and expense, partially offset by increased coal revenues. For our Central Appalachia segment, net income decreased to $3.9 million for the three months ended September 30, 2011, a decrease of $3.9 million as compared to the three months ended September 30, 2010, primarily due to decreased coal revenues from lower amounts of metallurgical coal sold. Net income in our Northern Appalachia segment increased by $3.7 million to $6.3 million for the three months ended September 30, 2011, from $2.6 million for the three months ended September 30, 2010. This increase was primarily the result of an increase in sales. Net income in our Rhino Western segment decreased to a loss of $0.5 million for the three months ended September 30, 2011, compared to net income of $11.0 million for the three months ended September 30, 2010, which included the $10.8 million gain from the Castle Valley acquisition. In addition to the Castle Valley gain, the decrease in Rhino Western’s net income resulted from an increase in costs associated with increasing production at our Castle Valley operation during 2011. Our Eastern Met segment recorded net income of $1.3 million for the three months ended September 30, 2011, a decrease of $0.3 million from net income of $1.6 million for the three months ended September 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 $1.2 million for both the three months ended September 30, 2011 and 2010.

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

	Three months ended			Three months ended		Increase
Segment	September 30, 2011			September 30, 2010		(Decrease)
	(in millions)
Central Appalachia	$	10.1		$	13.5	$	(3.4	)
Northern Appalachia	9.0			5.2		3.8
Rhino Western	0.6			0.4		0.2
Eastern Met *	1.7			2.0		(0.3		)
Other	(0.1		)	0.1		(0.2		)
Total Adjusted EBITDA †	$	21.3		$	21.2	$	0.1

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

39

†Refer to “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA to net income for each of the periods indicated.

Total Adjusted EBITDA for the three months ended September 30, 2011 was $21.3 million, an increase of $0.1 million from the three months ended September 30, 2010 as lower net income in the 2011 period was offset by higher DD&A and interest expense compared to 2010.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Summary.  For the nine months ended September 30, 2011, our total revenues increased to $266.2 million from $230.3 million for the nine months ended September 30, 2010. We sold 3.6 million tons of coal for the nine months ended September 30, 2011, which is 0.4 million tons greater, or a 11.3% increase, than the 3.2 million tons of coal sold for the nine months ended September 30, 2010. This increase was the result of production being reactivated at a surface mine in our Central Appalachia segment earlier in 2011 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 nine months ended September 30, 2011, we decreased our coal inventories by approximately 28,000 tons. Our coal inventory decreased primarily in Central Appalachia due to increased sales, but this inventory decrease was partially offset by an inventory increase in Rhino Western due to production commencing at our Castle Valley operation in Utah.

Net income decreased for the nine months ended September 30, 2011 from the nine months ended September 30, 2010. Net income was approximately $25.4 million for the nine months ended September 30, 2011 compared to approximately $35.5 million (or $24.7 million excluding the $10.8 million gain from the Castle Valley acquisition) for the nine months ended September 30, 2010. In addition to the Castle Valley gain, a decrease in our Central Appalachia income in 2011 was offset by an increase in our Northern Appalachia income compared to 2010. Net income was also positively impacted period to period due to $3.2 million of income from our Rhino Eastern joint venture for the nine months ended September 30, 2011 compared to income of $2.0 million for the nine months ended September 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.

Adjusted EBITDA increased to $57.4 million for the nine months ended September 30, 2011 from $54.2 million for the nine months ended September 30, 2010. EBITDA increased period to period primarily due to an increase in DD&A expense. Adjusted EBITDA was also positively impacted period to period due to the net income impact from our Rhino Eastern joint venture.

40

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

	Nine months	Nine months	Increase/
	ended	ended	(Decrease)
Segment	September 30, 2011	September 30, 2010	Tons	% *
	(in millions, except %)
Central Appalachia	1.7	1.6	0.1	7.6	%
Northern Appalachia	1.6	1.5	0.1	6.6	%
Rhino Western	0.3	0.2	0.1	88.7	%
Total *†	3.6	3.2	0.4	11.3	%

*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 3.6 million tons of coal in the nine months ended September 30, 2011 as compared to approximately 3.2 million tons sold in the nine months ended September 30, 2010. This increase in tons sold was primarily due to production being reactivated at a surface mine in our Central Appalachia segment earlier in 2011 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 0.1 million, or 7.6%, to approximately 1.7 million tons for the nine months ended September 30, 2011 from approximately 1.6 million tons for the nine months ended September 30, 2010. For our Northern Appalachia segment, tons of coal sold increased by approximately 0.1 million, or 6.6%, for the nine months ended September 30, 2011 from approximately 1.5 million tons for the nine months ended September 30, 2010. Coal sales from our Rhino Western segment increased by approximately 0.1 million, or 88.7%, to approximately 0.3 million tons for the nine months ended September 30, 2011 from approximately 0.2 million tons for the nine months ended September 30, 2010.

41

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

	Nine months		Nine months
	ended		ended		Increase/(Decrease)
Segment	September 30, 2011		September 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	148.9	$	146.6	$	2.3		1.5	%
Freight and handling revenues	—		—		—			n/a
Other revenues	9.2		0.6		8.6			1467.3	%
Total revenues	$	158.1	$	147.2	$	10.9		7.4	%
Coal revenues per ton*	$	87.14	$	92.34	$	(5.20	)	(5.6	)%
Northern Appalachia
Coal revenues	$	82.4	$	64.0	$	18.4		28.8	%
Freight and handling revenues	4.1		3.1		1.0			31.2	%
Other revenues	3.8		3.9		(0.1		)	(3.0	)%
Total revenues	$	90.3	$	71.0	$	19.3		27.2	%
Coal revenues per ton*	$	53.00	$	43.84	$	9.16		20.9	%
Rhino Western
Coal revenues	$	13.1	$	7.1	$	6.0		83.2	%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	13.1	$	7.1	$	6.0		83.1	%
Coal revenues per ton*	$	42.38	$	43.66	$	(1.28	)	(2.9	)%
Other**
Coal revenues	n/a		n/a		n/a			n/a
Freight and handling revenues	n/a		n/a		n/a			n/a
Other revenues	4.7		5.0		(0.3		)	(3.9	)%
Total revenues	$	4.7	$	5.0	$	(0.3	)	(3.9	)%
Coal revenues per ton	n/a		n/a		n/a			n/a
Total
Coal revenues	$	244.4	$	217.7	$	26.7		12.2	%
Freight and handling revenues	4.1		3.1		1.0			31.2	%
Other revenues	17.7		9.5		8.2			88.4	%
Total revenues	$	266.2	$	230.3	$	35.9		15.6	%
Coal revenues per ton*	$	68.42	$	67.82	$	0.60		0.9	%

*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.

42

Our coal revenues for the nine months ended September 30, 2011 increased by approximately $26.7 million, or 12.2%, to approximately $244.4 million from approximately $217.7 million for the nine months ended September 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 $68.42 for the nine months ended September 30, 2011, an increase of $0.60, or 0.9%, from $67.82 per ton for the nine months ended September 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 $2.3 million, or 1.5%, to approximately $148.9 million for the nine months ended September 30, 2011 from approximately $146.6 million for the nine months ended September 30, 2010 due to increased volume in tons sold. Coal revenues per ton for our Central Appalachia segment decreased by $5.20, or 5.6%, to $87.14 per ton for the nine months ended September 30, 2011 as compared to $92.34 for the nine months ended September 30, 2010, primarily due to lower amounts of metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to approximately $6.9 million of coal royalty revenue from Elk Horn.

For our Northern Appalachia segment, coal revenues were approximately $82.4 million for the nine months ended September 30, 2011, an increase of approximately $18.4 million, or 28.8%, from approximately $64.0 million for the nine months ended September 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 $9.16, or 20.9%, to $53.00 per ton for the nine months ended September 30, 2011 as compared to $43.84 per ton for the nine months ended September 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 $6.0 million, or 83.2%, to approximately $13.1 million for the nine months ended September 30, 2011 from approximately $7.1 million for the nine months ended September 30, 2010 due to the start of production at our Castle Valley operation. Coal revenues per ton for our Rhino Western segment were $42.38 for the nine months ended September 30, 2011, a decrease of $1.28, or 2.9%, from $43.66 for the nine months ended September 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 decreased slightly period to period at approximately $4.7 million for the nine months ended September 30, 2011 compared to approximately $5.0 million for the nine months ended September 30, 2010.

43

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 %)	Nine  months  ended  September  30, 2011		Nine  months  ended  September  30, 2010		Increase  (Decrease)  %*
Met coal tons sold	481.0		508.8		(5.5	)%
Steam coal tons sold	1,227.8		1,079.1		13.8	%
Total tons sold †	1,708.8		1,587.9		7.6	%
Met coal revenue	$	57,744	$	66,781	(13.5	)%
Steam coal revenue	$	91,148	$	79,839	14.2	%
Total coal revenue †	$	148,892	$	146,620	1.5	%
Met coal revenues per ton	$	120.05	$	131.26	(8.5	)%
Steam coal revenues per ton	$	74.24	$	73.99	0.3	%
Total coal revenues per ton †	$	87.14	$	92.34	(5.6	)%
Met coal tons produced	472.9		548.9		(13.9	)%
Steam coal tons produced	1,147.0		1,036.7		10.6	%
Total tons produced †	1,619.9		1,585.6		2.2	%

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

44

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 nine months ended September 30, 2011 and 2010:

	Nine months		Nine months
	ended		ended		Increase/(Decrease)
Segment	September 30, 2011		September 30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	115.8	$	99.8	$	16.0		16.0	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	15.9		14.6		1.3			9.3	%
Selling, general and administrative	14.2		10.9		3.3			30.1	%
Cost of operations per ton*	$	67.79	$	62.86	$	4.93		7.8	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	56.3	$	50.0	$	6.3		12.6	%
Freight and handling costs	3.3		2.4		0.9			38.8	%
Depreciation, depletion and amortization	6.2		6.0		0.2			1.6	%
Selling, general and administrative	0.2		0.2		—			(9.9	)%
Cost of operations per ton*	$	36.19	$	34.26	$	1.93		5.6	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	11.1	$	4.9	$	6.2		128.6	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	2.1		0.4		1.7			498.0	%
Selling, general and administrative	0.1		0.1		—			56.2	%
Cost of operations per ton*	$	36.14	$	29.84	$	6.30		21.1	%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	14.3	$	10.5	$	3.8		35.4	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	2.3		3.1		(0.8		)	(27.4	)%
Selling, general and administrative	0.9		0.5		0.4			77.9	%
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)	$	197.5	$	165.2	$	32.3		19.5	%
Freight and handling costs	3.3		2.4		0.9			38.8	%
Depreciation, depletion and amortization	26.5		24.1		2.4			9.8	%
Selling, general and administrative	15.4		11.7		3.7			31.4	%
Cost of operations per ton*	$	55.29	$	51.46	$	3.83		7.4	%

* 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.

45

Cost of Operations.  Total cost of operations was $197.5 million for the nine months ended September 30, 2011 as compared to $165.2 million for the nine months ended September 30, 2010. Our cost of operations per ton was $55.29 for the nine months ended September 30, 2011, an increase of $3.83, or 7.4%, from the nine months ended September 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. In Northern Appalachia, we also experienced increased roof support costs at our Hopedale mine. Cost of operations also increased across all of the operating segments due to higher fuel prices.

Our cost of operations for the Central Appalachia segment increased by $16.0 million, or 16.0%, to $115.8 million for the nine months ended September 30, 2011 from $99.8 million for the nine months ended September 30, 2010. Our cost of operations per ton increased to $67.79 per ton for the nine months ended September 30, 2011 from $62.86 per ton for nine months ended September 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 $6.3 million, or 12.6%, to $56.3 million for the nine months ended September 30, 2011 from $50.0 million for the nine months ended September 30, 2010, primarily due to increased commodity prices driven by higher fuel costs. Our cost of operations per ton was $36.19 for the nine months ended September 30, 2011 compared to $34.26 for the nine months ended September 30, 2010, an increase of $1.93 per ton, or 5.6%. 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 of 2011, as well as roof control and methane issues encountered at our Hopedale underground mine in the third quarter of 2011.

Our cost of operations for the Rhino Western segment increased by $6.2 million, or 128.6%, to $11.1 million for the nine months ended September 30, 2011 from $4.9 million for the nine months ended September 30, 2010. Our cost of operations per ton increased to $36.14 per ton for the nine months ended September 30, 2011 from $29.84 per ton for nine months ended September 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 $3.8 million for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. This increase was primarily due to an increase in amounts spent for professional fees and outside services.

46

Freight and Handling.  Total freight and handling cost for the nine months ended September 30, 2011 increased by $0.9 million, or 38.8%, to $3.3 million from $2.4 million for the nine months ended September 30, 2010. This increase was primarily due to a 0.4 million increase in the number of tons sold for the period ended September 30, 2011 as compared to the period ended September 30, 2010.

Depreciation, Depletion and Amortization.  Total DD&A expense for the nine months ended September 30, 2011 was $26.5 million as compared to $24.1 million for the nine months ended September 30, 2010.

For the nine months ended September 30, 2011, our depreciation cost decreased slightly to $19.8 million as compared to $20.2 million for the nine months ended September 30, 2010.

For the nine months ended September 30, 2011, our depletion cost was $3.3 million compared to $1.4 million for the nine months ended September 30, 2010. This increase is primarily attributable to the increase in tons produced for the period ended September 30, 2011 as compared to the period ended September 30, 2010.

For the nine months ended September 30, 2011, our amortization cost was $3.4 million as compared to $2.5 million for the nine months ended September 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 nine months ended September 30, 2011 was $15.4 million as compared to $11.7 million for the nine months ended September 30, 2010. The increase in SG&A expense is primarily attributable to the costs associated with being a publicly traded partnership, including an increase in expenditures for legal fees and other professional fees.

Interest Expense.  Interest expense for the nine months ended September 30, 2011 was flat at $4.2 million compared to the nine months ended September 30, 2010.

47

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 %)	Nine months ended September 30, 2011		Nine months ended September 30, 2010		Increase (Decrease) %*
Eastern Met 100% Basis
Coal revenues	$	37,046	$	24,812	49.3	%
Total revenues	$	37,093	$	24,850	49.3	%
Coal revenues per ton*	$	198.70	$	136.40	45.7	%
Cost of operations	$	26,501	$	16,735	58.4	%
Cost of operations per ton*	$	142.14	$	92.00	54.5	%
Depreciation, depletion and amortization	$	2,328	$	2,331	(0.1	)%
Interest expense	$	49	$	50	(1.3	)%
Net income (loss)	$	6,193	$	3,946	57.0	%
Partnership’s portion of net income (loss)	$	3,158	$	2,012	57.0	%
Tons produced	189.1		186.1		1.6	%
Tons sold	186.4		181.9		2.5	%

* 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 these interruptions, tons produced and tons sold for the nine months ended September 30, 2011 increased slightly compared to the nine months ended September 30, 2010. Revenue and net income increased year-to-year due to favorable pricing for coal sold in 2011, partially offset by higher costs of operations.

48

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

	Nine months Ended			Nine months Ended			Increase
Segment	September 30, 2011			September 30, 2010			(Decrease)
	(in millions)
Central Appalachia	$	10.3		$	18.0		$	(7.7	)
Northern Appalachia	18.0			7.2			10.8
Rhino Western*	(2.3		)	12.0			(14.3		)
Eastern Met **	3.2			2.0			1.2
Other	(3.8		)	(3.7		)	(0.1		)
Total	$	25.4		$	35.5		$	(10.1	)

*During the third quarter of 2010, we 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, located in Emery and Carbon Counties, Utah (referred to as our Castle Valley mining complex). Because the fair value of the assets acquired exceeded the purchase price, we recorded a non-cash gain of $10.8 million that is reflected in our third quarter 2010 financial results for Rhino Western. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy.

**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 nine months ended September 30, 2011, total net income decreased to approximately $25.4 million compared to approximately $35.5 million (or $24.7 million excluding the $10.8 million gain from the Castle Valley acquisition) for the nine months ended September 30, 2010. For our Central Appalachia segment, net income decreased to $10.3 million for the nine months ended September 30, 2011, a decrease of $7.7 million as compared to the nine months ended September 30, 2010, primarily due to lower amounts of metallurgical coal sold and an increase in costs of operations. Net income in our Northern Appalachia segment increased by $10.8 million to $18.0 million for the nine months ended September 30, 2011, from $7.2 million for the nine months ended September 30, 2010. This increase was primarily the result of an increase in sales. Net income in our Rhino Western segment decreased by $14.3 million to a loss of $2.3 million for the nine months ended September 30, 2011, compared to income of $12.0 million for the nine months ended September 30, 2010. This decrease was primarily the result of the $10.8 million Castle Valley gain along with 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 $3.2 million for the nine months ended September 30, 2011, an increase of $1.2 million from net income of approximately $2.0 million for the nine months ended September 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 $3.8 million for the nine months ended September 30, 2011, which was relatively flat compared to a net loss of $3.7 million for the nine months ended September 30, 2010.

49

Adjusted EBITDA.  The following table presents Adjusted EBITDA by reportable segment for the nine months ended September 30, 2011 and 2010:

	Nine months Ended			Nine months Ended		Increase
Segment	September 30, 2011			September 30, 2010		(Decrease)
	(in millions)
Central Appalachia	$	27.8		$	34.4	$	(6.6	)
Northern Appalachia	25.6			14.9		10.7
Rhino Western	0.2			1.8		(1.6		)
Eastern Met *	4.5			3.1		1.4
Other	(0.7		)	—		(0.7		)
Total Adjusted EBITDA †	$	57.4		$	54.2	$	3.2

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

†Refer to “—Reconciliation of Adjusted EBITDA to Net Income by Segment” for reconciliations of Adjusted EBITDA to net income for each of the periods indicated.

Total Adjusted EBITDA for the nine months ended September 30, 2011 was $57.4 million, an increase of $3.2 million from the nine months ended September 30, 2010 primarily due to higher DD&A expense in 2011 compared to 2010. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA to net income on a segment basis.

Reconciliations of Adjusted EBITDA

The following tables present reconciliations of Adjusted EBITDA to the most directly comparable GAAP financial measures for each of the periods indicated. We believe the presentation of Adjusted EBITDA that includes the proportionate share of DD&A and interest expense for our Rhino Eastern joint venture is appropriate since our portion of Rhino Eastern’s net income that is recognized as a single line item in our financial statements is affected by these expense items. Since we do not reflect these proportionate expense items of DD&A and interest expense in our consolidated financial statements, we believe that the adjustment for these expense items in the EBITDA calculation is more representative of how we review our results and also provides investors with additional information that they can use to evaluate our results.

50

Three months ended	Central		Northern		Rhino			Eastern
September 30, 2011	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	3.9	$	6.3	$	(0.5	)	$	1.3	$	(1.2	)	$	9.8
Plus:
DD&A	5.5		2.0		0.9			—		0.8			9.2
Interest expense	0.7		0.7		0.2			—		0.3			1.9
Eastern Met DD&A-51%	—		—		—			0.4		—			0.4
Eastern Met interest expense-51%	—		—		—			—		—			—
Adjusted EBITDA†	$	10.1	$	9.0	$	0.6		$	1.7	$	(0.1	)	$	21.3

Three months ended	Central		Northern		Rhino			Eastern
September 30, 2010	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	7.8	$	2.6	$	11.0		$	1.6	$	(1.2	)	$	21.8
Less: Gain from Castle Valley acquisition **	—		—		(10.8		)	—		—			(10.8		)
Plus:
DD&A	5.1		2.1		0.1			—		1.0			8.3
Interest expense	0.6		0.5		0.1			—		0.3			1.5
Eastern Met DD&A-51%	—		—		—			0.4		—			0.4
Eastern Met interest expense-51%	—		—		—			—		—			—
Adjusted EBITDA†	$	13.5	$	5.2	$	0.4		$	2.0	$	0.1		$	21.2

Nine months ended	Central		Northern		Rhino			Eastern
September 30, 2011	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	10.3	$	18.0	$	(2.3	)	$	3.2	$	(3.8	)	$	25.4
Plus:
DD&A	15.9		6.2		2.1			—		2.3			26.5
Interest expense	1.6		1.4		0.4			—		0.8			4.2
Eastern Met DD&A-51%	—		—		—			1.2		—			1.2
Eastern Met interest expense-51%	—		—		—			0.1		—			0.1
Adjusted EBITDA†	$	27.8	$	25.6	$	0.2		$	4.5	$	(0.7	)	$	57.4

Nine months ended	Central		Northern		Rhino			Eastern
September 30, 2010	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	18.0	$	7.2	$	12.0		$	2.0	$	(3.7	)	$	35.5
Less: Gain from Castle Valley acquisition **	—		—		(10.8		)	—		—			(10.8		)
Plus:
DD&A	14.6		6.1		0.4			—		3.1			24.2
Interest expense	1.8		1.6		0.2			—		0.6			4.2
Eastern Met DD&A-51%	—		—		—			1.1		—			1.1
Eastern Met interest expense-51%	—		—		—			—		—			—
Adjusted EBITDA†	$	34.4	$	14.9	$	1.8		$	3.1	$	(0.0	)	$	54.2

51

*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.

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

**During the third quarter of 2010, we 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, located in Emery and Carbon Counties, Utah (referred to as our Castle Valley mining complex). Because the fair value of the assets acquired exceeded the purchase price, we recorded a non-cash gain of $10.8 million that is reflected in our third quarter 2010 financial results. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy. Management believes that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how management assesses the performance of the Partnership’s business. Management believes the adjustment of this item provides investors with additional information that they can utilize in evaluating the Partnership’s performance. Additionally, management believes the isolation of this item provides investors with enhanced comparability to prior and future periods of the Partnership’s operating results.

52

	Three months ended					Nine months ended
	September 30					September 30
	2011		2010			2011		2010
	(in millions)
Net cash provided by operating activities	$	17.3	$	18.0		$	51.3	$	42.9
Plus:
Increase in net operating assets	—		0.9			—		6.8
Gain on sale of assets	2.7		10.8			2.8		10.8
Amortization of deferred revenue	0.4		—			0.4		—
Interest expense	1.9		1.5			4.2		4.2
Equity in net income of unconsolidated affiliate	1.3		1.6			3.2		2.0
Less:
Decrease in net operating assets	1.5		—			1.8		—
Accretion on interest-free debt	—		0.1			0.1		0.1
Amortization of advance royalties	0.2		0.3			0.9		0.7
Amortization of debt issuance costs	0.3		—			0.8		—
Equity-based compensation	0.2		—			0.6		—
Loss on retirement of advance royalties	—		0.3			0.1		0.4
Accretion on asset retirement obligations	0.5		0.5			1.5		1.6
Loss on sale of assets	—		—			—		—
EBITDA†	$	20.9	$	31.6		$	56.1	$	63.9
Plus: Rhino Eastern DD&A-51%	0.4		0.4			1.2		1.1
Plus: Rhino Eastern interest expense-51%	—		—			0.1		—
Less: Gain from Castle Valley acquisition**	—		(10.8		)	—		(10.8		)
Adjusted EBITDA†	$	21.3	$	21.2		$	57.4	$	54.2

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

**During the third quarter of 2010, we 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, located in Emery and Carbon Counties, Utah (referred to as our Castle Valley mining complex). Because the fair value of the assets acquired exceeded the purchase price, we recorded a non-cash gain of $10.8 million that is reflected in our third quarter 2010 financial results. A gain resulted from this acquisition since the assets were purchased in a distressed sale out of bankruptcy. Management believes that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how management assesses the performance of the Partnership’s business. Management believes the adjustment of this item provides investors with additional information that they can utilize in evaluating the Partnership’s performance. Additionally, management believes the isolation of this item provides investors with enhanced comparability to prior and future periods of the Partnership’s operating results.

Liquidity and Capital Resources

Liquidity

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

53

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 September 30, 2011, our available liquidity was $163.9 million, including cash on hand of $0.3 million and $163.6 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 $51.3 million for the nine months ended September 30, 2011 as compared to $42.9 million for the nine months ended September 30, 2010.  This increase in cash provided by operating activities was primarily the result of positive net working capital changes in 2011 compared to unfavorable working capital changes in 2010.  For 2011, the positive working capital changes were primarily due to an increased accounts payable balance, partially offset by decreased accounts receivable.  For 2010, the unfavorable working capital changes were primarily due to an unfavorable change in accounts receivable caused by the timing of customer payments.

Net cash used in investing activities was $160.7 million for the nine months ended September 30, 2011 as compared to $33.9 million for the nine months ended September 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 $25.9 million for oil and gas mineral rights acquisitions in the Cana Woodford region and the Utica Shale region mentioned earlier.

Net cash provided by financing activities for the nine months ended September 30, 2011 was $109.6 million, which was primarily attributable to net borrowings under our credit agreement to fund the Elk Horn acquisition that was also partially funded with the net proceeds of approximately $68.0 million from the public offering of common units in July 2011.  Net cash used in financing activities for the nine months ended September 30, 2010 was $9.5 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. Additionally, we have incurred expansion capital expenditures to

54

acquire oil and gas mineral rights and we may incur additional expansion capital expenditures for drilling costs or to acquire additional oil and gas mineral rights.

Actual maintenance capital expenditures for the nine months ended September 30, 2011 were approximately $15.9 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the nine months ended September 30, 2011 were approximately $50.3 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 $25.9 million during the nine months ended September 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.

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

Credit Agreement

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

Loans under the credit agreement bear interest at either (i) a base rate equaling the highest of (a) the Federal Funds Open Rate plus 0.50%; (b) the prime rate; or (c) daily LIBOR plus 1.00%, plus an applicable margin in each case or (ii) LIBOR plus an applicable margin, at our option.  The applicable margin for the base rate option is 1.50% to 2.25%, and the applicable margin for the LIBOR option is 2.50% to 3.25%, each of which depends on our and our subsidiaries’ consolidated leverage ratio (“Consolidated Leverage Ratio”).  The credit agreement also contains letter of credit fees equal to an applicable margin of 2.50% to 3.25% depending on the Consolidated Leverage Ratio, multiplied by the aggregate amount available to be drawn on the letters of credit, and a 0.15% fronting fee payable to the administrative agent.  In addition, we incur a commitment fee on the unused portion of the credit agreement at a rate of 0.375% to 0.50% per annum, depending on the Consolidated Leverage Ratio. Borrowings on the line of credit are collateralized by all of our unsecured assets.

Our credit agreement requires us to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. As of September 30, 2011, we are in compliance

55

with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.

At September 30, 2011, we had borrowed $105.0 million at a variable interest rate of LIBOR plus 3.00% (3.23% at September 30, 2011) and an additional $5.4 million at a variable interest rate of PRIME plus 2.00% (5.25% at September 30, 2011). In addition, we had outstanding letters of credit of approximately $26.0 million at a fixed interest rate of 3.00% at September 30, 2011. We had not used $163.6 million of the borrowing availability at September 30, 2011. During the three month period ending September 30, 2011, we had average borrowings outstanding of approximately $126.6 million in relation to this credit agreement.

Off-Balance Sheet Arrangements

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

Federal and state laws require us to secure certain long-term obligations related to mine closure and reclamation costs. We typically secure these obligations by using surety bonds, an off-balance sheet instrument. The use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond or a bank letter of credit, either of which would require a greater use of our credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank letters of credit in an amount of up to 25% of the aggregate bond liability. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

As of September 30, 2011, we had $26.0 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

56

Form 10-K for the year ended December 31, 2010. There have been no significant changes in these policies and estimates as of September 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 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

57

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 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.

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

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.

58

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 September 30, 2011 and would have reduced net income by approximately $0.5 million for the nine months ended September 30, 2011. A hypothetical increase of 10% in steel prices would have reduced net income by $0.4 million for the three months ended September 30, 2011 and would have reduced net income by approximately $1.1 million for the nine months ended September 30, 2011. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.2 million for the three months ended September 30, 2011 and would have reduced net income by approximately $0.5 million for the nine months ended September 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 $0.4 million for the three months ended September 30, 2011 and would have changed our interest expense by $0.6 million for the nine months ended September 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.

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

59

concluded that our disclosure controls and procedures were effective as of September 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 September 30, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

60

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 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

61

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

62

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.

63

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 nine months ended September 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, or (b) a pattern of violations of mandatory health or safety standards under section 104(e) of the Mine Act. During the nine months ended September 30, 2011, Rhino Eastern received an MSHA notification of a potential pattern of violations under Section 104(e) of the Mine Act that is discussed further below. We have 8 pending legal actions before the Federal Mine Safety and Health Review Commission (the “Commission”) that were initiated during the three months ended September 30, 2011 and we have 74 total pending legal actions that were pending before the Commission during the nine months ended September 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 nine months ended September 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 September 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 understood it, resolved the issues identified in the November 19, 2010 notification.

On August 25, 2011, Rhino Eastern again received an MSHA notification of a potential pattern of violations under Section 104(e) of the Mine Act for the Eagle #1 Mine based on

64

MSHA’s continued monitoring of the Eagle #1 Mine for long-term compliance after the evaluation period that ended in March 2011. The notice from MSHA provided Rhino Eastern twenty days to review the violations and to develop a corrective action program in order to avoid a final finding of a pattern of violations and the imposition of sanctions pursuant to Section 104(e) of the Mine Act. Rhino Eastern’s Corrective Action Plan was acknowledged by MSHA on September 16, 2011. Rhino Eastern is carefully reviewing all of the historical safety data that resulted in the potential pattern of violations finding, and intends to fully cooperate with MSHA during this process.

The following table sets out additional information required by the Dodd-Frank Act for the three months ended September 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.

65

For the three months ended September 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)	ProposedAssessments(7)		Fatalities	Pending Legal Actions(8)
Hopedale Mining LLC	Hopedale Mine	33-00968	26	0	0	0	0	$	9,978	0	4
	Nelms Plant	33-04187	1	0	0	0	0	$	100	0	0
Sands Hill Mining LLC	Big Valley Mine	33-01358	0	0	0	0	0	$	200	0	0
	Clinton Stone	33-04041	0	0	0	0	0	$	—	0	0
CAM/Deane Mining LLC	Access Energy	15-19532	2	0	0	0	0	$	—	0	0
	Mine #28	15-18911	10	0	0	0	0	$	10,438	0	1
	Mine #30	15-18964	1	0	0	0	0	$	2,066	0	0
	Love Branch	15-19191	0	0	0	0	0	$	300	0	0
	Deane #1	15-18569	21	1	3	0	0	$	39,758	0	3
	Bevins Branch	15-18570	4	0	0	0	0	$	2,355	0	0
	Marion Branch	15-18100	0	0	0	0	0	$	—	0	0
	Three Mile Mine #1	15-17659	1	0	0	0	0	$	2,507	0	0
	Calloway North	15-19199	1	0	0	0	0	$	946	0	0
	Grapevine South	46-08930	0	0	0	0	0	$	—	0	0
	Rob Fork Processing	15-14468	2	0	0	0	0	$	2,715	0	0
	Jamboree Loadout	15-12896	0	0	0	0	0	$	—	0	0
	Mill Creek Prep Plant	15-16577	0	0	0	0	0	$	—	0	0
	Rhino Trucking	Q569	4	0	0	0	0	$	2,906	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	52	2	4	0	0	$	56,513	0	0
	Eagle #2	46-09201	12	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	$	2,639	0	0
Castle Valley Mining LLC	Castle Valley Mine #3	42-02263	1	0	0	0	0	$	262	0	0
	Castle Valley Mine #4	42-02335	1	0	0	0	0	$	1,140	0	0
	Bear Canyon Loading Facility	42-02395	0	0	0	0	0	$	—	0	0
Total			139	3	7	0	0	$	134,823	0	8

66

(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.

67

Item 6.    Exhibits.

Exhibit Number	Description
2.1	Asset Purchase Agreement, dated August 15, 2011, by and among CAM Mining LLC, CAM-Kentucky Real Estate LLC, and Revelation Energy, LLC, incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K (File No. 001-034892) filed on August 19, 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	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.
10.2	Amended and Restated Employment Agreement of R. Chad Hunt dated September 8, 2011, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892) filed on September 13, 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)
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)

68

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

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

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

69

SIGNATURES

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

	RHINO RESOURCE PARTNERS LP
	By: Rhino GP LLC, its General Partner
Date: November 14, 2011	By:	/s/ David G. Zatezalo
		David G. Zatezalo
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: November 14, 2011	By:	/s/ Richard A. Boone
		Richard A. Boone
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

70

EX-31.1

Exhibit 31.1

CERTIFICATION

I, David G. Zatezalo, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Rhino Resource Partners LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2011

/s/ David G. Zatezalo

David G. Zatezalo

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard A. Boone, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Rhino Resource Partners LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2011

/s/ Richard A. Boone

Richard A. Boone

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF
CHIEF EXECUTIVE OFFICER
OF RHINO GP LLC
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Quarterly Report on Form 10-Q of Rhino Resource Partners LP for the quarter ended September 30, 2011, I, David G. Zatezalo, President and Chief Executive Officer of Rhino GP LLC, the general partner of Rhino Resource Partners LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Quarterly Report Form 10-Q for the quarter ended September 30, 2011 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 fairly presents, in all material respects, the financial condition and results of operations of Rhino Resource Partners LP for the periods presented therein.

Date: November 14, 2011

/s/ David G. Zatezalo

David G. Zatezalo

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF
CHIEF FINANCIAL OFFICER
OF RHINO GP LLC
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this quarterly report on Form 10-Q of Rhino Resource Partners LP for the quarter ended September 30, 2011, I, Richard A. Boone, Senior Vice President and Chief Financial Officer of Rhino GP LLC, the general partner of Resource Partners LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 fairly presents, in all material respects, the financial condition and results of operations of Rhino Resource Partners LP for the periods presented therein.

Date: November 14, 2011

/s/ Richard A. Boone

Richard A. Boone

Senior Vice President and Chief Financial Officer

XML

Condensed Consolidated Statements Of Financial Position (Parenthetical) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Condensed Consolidated Statements Of Financial Position
Accounts receivable, allowance for doubtful accounts	$ 0	$ 19

XML

Condensed Consolidated Statements Of Operations And Comprehensive Income (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
REVENUES:
Coal sales	$ 81,988	$ 80,982	$ 244,367	$ 217,718
Freight and handling revenues	1,548	1,192	4,118	3,139
Other revenues	10,028	3,055	17,710	9,403
Total revenues	93,564	85,229	266,195	230,260
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	69,004	61,009	197,477	165,201
Freight and handling costs	1,331	913	3,271	2,357
Depreciation, depletion and amortization	9,157	8,343	26,513	24,146
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	6,350	4,074	15,345	11,677
(Gain) loss on sale/ acquisition of assets - net	(2,702)	(10,784)	(2,836)	(10,830)
Total costs and expenses	83,140	63,555	239,770	192,551
INCOME FROM OPERATIONS	10,424	21,674	26,425	37,709
INTEREST & OTHER INCOME (EXPENSE):
Interest expense and other	(1,850)	(1,469)	(4,274)	(4,251)
Interest income and other	14	5	50	24
Equity in net income of unconsolidated affiliate	1,258	1,598	3,158	2,012
Total interest and other income (expense)	(578)	134	(1,066)	(2,215)
INCOME BEFORE INCOME TAXES	9,846	21,808	25,359	35,494
INCOME TAXES
NET INCOME	9,846	21,808	25,359	35,494
Other comprehensive income - Amortization of actuarial gain under ASC Topic 815		(113)		(113)
COMPREHENSIVE INCOME	9,846	21,695	25,359	35,381
General partner's interest in net income	197		507
Distributions paid per limited partner unit	$ 0.455		$ 1.3308
Common Units [Member]
INTEREST & OTHER INCOME (EXPENSE):
Unitholders' interest in net income	5,240		12,718
Net income per limited partner unit, basic:
Net income per limited partner unit, basic	0.36		0.98
Net income per limited partner unit, diluted:
Net income per limited partner unit, diluted	$ 0.36		$ 0.98
Weighted average number of limited partner units outstanding, basic:
Weighted average number of limited partner units outstanding, basic	14,732		12,993
Weighted average number of limited partner units outstanding, diluted:
Weighted average number of limited partner units outstanding, diluted	14,747		13,014
Subordinated Units [Member]
INTEREST & OTHER INCOME (EXPENSE):
Unitholders' interest in net income	$ 4,409		$ 12,134
Net income per limited partner unit, basic:
Net income per limited partner unit, basic	0.36		0.98
Net income per limited partner unit, diluted:
Net income per limited partner unit, diluted	$ 0.36		$ 0.98
Weighted average number of limited partner units outstanding, basic:
Weighted average number of limited partner units outstanding, basic	12,397		12,397
Weighted average number of limited partner units outstanding, diluted:
Weighted average number of limited partner units outstanding, diluted	12,397		12,397

XML

Segment Information

9 Months Ended

Sep. 30, 2011

Segment Information

Segment Information

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 nine months ended September 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 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 September 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	$   53,443	$   32,568	$   6,044	$ 14,323	$   (14,323)	$               -	$   1,509	$    93,564
DD&A	5,550	1,992	857	754	(754)	-	758	9,157
Interest expense	691	675	201	32	(32)	-	283	1,850
Net Income (loss)	$     3,904	$     6,313	$    (427)	$   2,466	$     (1,208)	$       1,258	$ (1,202)	$      9,846

Reportable segment results of operations for the three months ended September 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	$   56,949	$   24,314	$   2,329	$ 11,173	$   (11,173)	$               -	$   1,637	$    85,229
DD&A	5,073	2,103	118	790	(790)	-	1,049	8,343
Interest expense	610	556	65	11	(11)	-	238	1,469
Net Income (loss)	$     7,821	$     2,586	$ 11,014	$   3,134	$     (1,536)	$       1,598	$ (1,211)	$    21,808

Reportable segment results of operations for the nine months ended September 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	$ 158,092	$   90,306	$ 13,065	$ 37,093	$   (37,093)	$               -	$   4,732	$  266,195
DD&A	15,948	6,177	2,117	2,328	(2,328)	-	2,271	26,513
Interest expense	1,640	1,429	360	49	(49)	-	845	4,274
Net Income (loss)	$   10,336	$   18,036	$ (2,327)	$   6,193	$     (3,035)	$       3,158	$ (3,844)	$    25,359

Reportable segment results of operations for the nine months ended September 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	$ 147,207	$   70,995	$   7,134	$ 24,850	$   (24,850)	$               -	$   4,924	$  230,260
DD&A	14,587	6,077	354	2,331	(2,331)	-	3,128	24,146
Interest expense	1,832	1,622	172	50	(50)	-	625	4,251
Net Income (loss)	$   18,024	$     7,212	$ 12,014	$   3,946	$     (1,934)	$       2,012	$ (3,768)	$    35,494

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2011	Nov. 11, 2011
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	Rhino Resource Partners LP
Entity Central Index Key	0001490630
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding		15,308,370

XML

Other Non-Current Assets

9 Months Ended

Sep. 30, 2011

Other Non-Current Assets

Other Non-Current Assets

7. OTHER NON-CURRENT ASSETS

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

	September 30,	December 31,
	2011	2010
	(in thousands)
Deposits and other	$              1,895	$                 840
Debt issuance costs—net	5,194	2,211
Deferred expenses	30	56
Total	$              7,119	$              3,107

Debt issuance costs were approximately $8.1 million and approximately $4.3 million as of September 30, 2011 and December 31, 2010, respectively. Accumulated amortization of debt issuance costs were approximately $2.9 million and approximately $2.1 million as of September 30, 2011 and December 31, 2010, respectively.

XML

Equity-Based Compensation

9 Months Ended

Sep. 30, 2011

Equity-Based Compensation

Equity-Based Compensation

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 September 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 did not incur incremental compensation expense for the three months ended September 30, 2011 since the market price of the Partnership's common units was below the IPO grant price. The Partnership recorded approximately $0.2 million in incremental compensation expense for the nine months ended September 30, 2011 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 September 30, 2011.

XML

Business Combinations And Other Acquisitions

9 Months Ended

Sep. 30, 2011

Business Combinations And Other Acquisitions

Business Combinations And Other Acquisitions

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 that owns or controls coal reserves and non-reserve coal deposits and surface acreage in eastern Kentucky. Elk Horn is expected to provide the Partnership 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. The Partnership completed a public offering of the Partnership's common units in July 2011 that provided proceeds the Partnership used to repay existing indebtedness on its credit facility that was incurred from the Elk Horn acquisition. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date:

	(in thousands)
Cash	$                   197
Accounts receivable	2,466
Prepaid expenses and other	95
Property, plant and equipment	7,113
Coal properties	112,522
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, 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. 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 from the closing date 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 consideration transferred by the Partnership as representations and warranties were expected to be valid as of the acquisition date.

Acquisition-related costs incurred 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 net income from Elk Horn prior to June 10, 2011, the effective date of the acquisition. The post-acquisition revenue of Elk Horn that is included in the Partnership's results was approximately $5.9 million and $6.9 million for the three and nine months ended September 30, 2011, respectively. The post-acquisition net income of Elk Horn that is included in the Partnership's results was approximately $3.8 million and $4.4 million for the three and nine months ended September 30, 2011, respectively.

The following table presents selected unaudited pro forma financial information for the three and nine months ended September 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. Supplemental pro forma revenue, net earnings and earnings per unit disclosures are as follows.

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
Revenues:	(in thousands)
As reported	$         93,564	$         85,229	$       266,195	$       230,260
Pro forma adjustments	-	3,081	9,477	6,529
Pro forma revenues	$         93,564	$         88,310	$       275,672	$       236,789
Net Income:
As reported	$           9,846	$         21,808	$         25,359	$         35,494
Pro forma adjustments	(158)	1,018	2,549	1,265
Pro forma net income	$           9,688	$         22,826	$         27,908	$         36,759
Net income per limited partner unit, diluted:
As reported	$             0.36	n/a	$             0.98	n/a
Pro forma adjustments	$            (0.02)	n/a	$             0.01	n/a
Pro forma net income	$             0.34	n/a	$             0.99	n/a

Acquisition of Oil and Gas Mineral Rights

During the three and nine months ended September 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 $0.3 million and approximately $6.1 million, respectively. In October 2011, the Partnership acquired additional oil and gas mineral rights for approximately $2.0 million to bring its total investment in the Cana Woodford region to approximately $8.1 million. The Partnership expects royalty revenues to be generated from these mineral rights in future periods.

The Partnership and an affiliate of Wexford Capital have participated with Gulfport Energy, a publicly traded company, to acquire an interest in a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately 16.8% of the common stock of Gulfport Energy as of September 30, 2011. During the three and nine months ended September 30, 2011, the Partnership completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $12.8 million and approximately $19.9 million, respectively. The Partnership is evaluating future alternatives for its Utica Shale investment.

Acquisition of Coal Property

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

In June 2011, 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.  

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.

XML

Debt

9 Months Ended

Sep. 30, 2011

Debt

Debt

9. DEBT

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

	September 30,	December 31,
	2011	2010
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$           110,370	$             28,470
Note payable to H&L Construction Co., Inc.	2,459	2,973
Other notes payable	4,435	5,085
Total	117,264	36,528
Less current portion	(1,994)	(2,908)
Long-term debt	$           115,270	$             33,620

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

On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit. Borrowings under the facility bear interest, which varies depending upon the levels of certain financial ratios. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability that also varies depending upon the levels of certain financial ratios. Borrowings on the amended and restated senior secured credit facility are collateralized by all the unsecured assets of the Partnership. The amended and restated senior secured credit facility requires the Partnership to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Partnership was in compliance with all covenants contained in the amended and restated senior secured credit facility as of and for the period ended September 30, 2011. The amended and restated senior secured credit facility expires in July 2016.

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

At September 30, 2011, the Operating Company had borrowed $105.0 million at a variable interest rate of LIBOR plus 3.00% (3.23% at September 30, 2011) and an additional $5.4 million at a variable interest rate of PRIME plus 2.00% (5.25% at September 30, 2011). In addition, the Operating Company had outstanding letters of credit of approximately $26.0 million at a fixed interest rate of 3.00% at September 30, 2011. The Operating Company had not used $163.6 million of the borrowing availability at September 30, 2011.

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 $2.5 million as of September 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 $11.6 million and approximately $11.8 million as of September 30, 2011 and December 31, 2010, respectively.

XML

Earnings Per Unit ("EPU")

9 Months Ended

Sep. 30, 2011

Earnings Per Unit ("EPU")

Earnings Per Unit ("EPU")

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 September 30, 2011:

Three months ended September 30, 2011	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$             197	$               5,240	$                 4,409
Denominator:
Weighted avg units used to compute basic EPU	n/a	14,732	12,397
Effect of dilutive securities — LTIP awards	n/a	15	-
Weighted avg units used to compute diluted EPU	n/a	14,747	12,397
Net income per limited partner unit, basic	n/a	$                 0.36	$                   0.36
Net income per limited partner unit, diluted	n/a	$                 0.36	$                   0.36

Nine months ended September 30, 2011	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$             507	$             12,718	$               12,134
Denominator:
Weighted avg units used to compute basic EPU	n/a	12,993	12,397
Effect of dilutive securities — LTIP awards	n/a	21	-
Weighted avg units used to compute diluted EPU	n/a	13,014	12,397
Net income per limited partner unit, basic	n/a	$                 0.98	$                   0.98
Net income per limited partner unit, diluted	n/a	$                 0.98	$                   0.98

XML

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligations

Asset Retirement Obligations

10. ASSET RETIREMENT OBLIGATIONS

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

	Nine months ended September 30, 2011	Year ended December 31, 2010
	(in thousands)
Balance at beginning of period (including current portion)	$                             35,691	$                             45,101
Accretion expense	1,469	2,165
Adjustment resulting from addition of property	511	933
Adjustment resulting from disposal of property	(3,537)	-
Adjustments to the liability from annual recosting and other	-	(10,202)
Liabilities settled	(1,967)	(2,306)
Balance at end of period	32,167	35,691
Current portion of asset retirement obligation	3,861	4,350
Long-term portion of asset retirement obligation	$                             28,306	$                             31,341

XML

Accrued Expenses And Other Current Liabilities

9 Months Ended

Sep. 30, 2011

Accrued Expenses And Other Current Liabilities

Accrued Expenses And Other Current Liabilities

8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

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

	September 30,	December 31,
	2011	2010
	(in thousands)
Payroll, bonus and vacation expense	$              4,230	$              3,570
Non income taxes	4,004	3,020
Royalty expenses	2,153	2,184
Accrued interest	679	460
Health claims	1,135	2,046
Workers' compensation & pneumoconiosis	1,400	1,400
Deferred revenues	2,194	-
Other	2,409	289
Total	$             18,204	$             12,969

XML

Basis Of Presentation And Organization

9 Months Ended

Sep. 30, 2011

Basis Of Presentation And Organization

Basis Of Presentation And Organization

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 nine months ended September 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 nine months ended September 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 September 30, 2011, condensed consolidated statements of operations for the three and nine month periods ended September 30, 2011 and 2010 and the condensed consolidated statements of cash flows for the nine months ended September 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 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. In addition to operating coal properties, the Operating Company manages and leases coal properties and collects royalties from such management and leasing activities. The Operating Company was formed in April 2003 and has been built via acquisitions.

In addition to the Operating Company's coal operations, the Partnership has invested in oil and gas mineral rights that the Partnership expects to generate royalty revenues in future periods.

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.

Follow-on Offering

On July 18, 2011, the Partnership completed a public offering of 2,875,000 common units, representing limited partner interests in the Partnership, at a price of $24.50 per common unit. Of the common units issued, 375,000 units were issued in connection with the exercise of the underwriters' option to purchase additional units. Net proceeds from the offering were approximately $66.6 million, after deducting underwriting discounts and offering expenses of approximately $3.9 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 $68.0 million of outstanding indebtedness under the Partnership's credit facility.

XML

Prepaid Expenses And Other Current Assets

9 Months Ended

Sep. 30, 2011

Prepaid Expenses And Other Current Assets

Prepaid Expenses And Other Current Assets

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

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

	September 30,	December 31,
	2011	2010
	(in thousands)
Other prepaid expenses	$                         620	$                         929
Prepaid insurance	2,225	3,239
Prepaid leases	110	82
Supply inventory	1,319	956
Deposits	170	170
Total	$                      4,444	$                      5,376

XML

Property, Plant And Equipment

9 Months Ended

Sep. 30, 2011

Property, Plant And Equipment

Property, Plant And Equipment

5. PROPERTY, PLANT AND EQUIPMENT

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

	Useful Lives	September 30, 2011	December 31, 2010
		(in thousands)
Land and Land Improvements		$       32,893	$         25,748
Mining and other equipment and related facilities	2 - 20 Years	231,516	218,886
Mine development costs	1 - 15 Years	59,987	56,857
Coal properties	1 - 15 Years	263,263	132,431
Construction work in process		16,209	8,190
Total		603,868	442,112
Less accumulated depreciation, depletion and amortization		(183,086)	(159,535)
Net		$     420,782	$       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 nine months ended September 30, 2011 and 2010 were as follows:

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$ 6,488	$       6,803	$    19,769	$    20,238
Depletion expense for coal properties	1,510	470	3,358	1,441
Amortization expense for mine development costs	809	639	2,358	1,473
Amortization expense for intangible assets	12	12	36	75
Amortization expense for asset retirement costs	338	419	992	919
Total depreciation, depletion and amortization	$ 9,157	$       8,343	$    26,513	$    24,146

Sale of Mining Assets

In August 2011, the Partnership closed on an agreement to sell and assign certain non-core mining assets and related liabilities located in the Phelps, Kentucky area of the Partnership's Tug River mining complex for $20 million. The mining assets include leasehold interests and permits to surface and mineral interests that include steam coal reserves and non-reserve coal deposits. Additionally, the sales agreement includes the potential for additional payments of approximately $8.75 million dependent upon the future issuance of certain permits and the commencement of mining activities by the purchaser. These contingent payments are being accounted for as gain contingencies and will be recognized in the future when and if the contingencies are resolved. The transaction also transfers certain liabilities related to the assets sold. In relation to the sale of these assets and transfer of liabilities, the Partnership recorded a gain of approximately $2.4 million, which is included on the (Gain) loss on sale/acquisition of assets—net line of the Partnership's unaudited condensed consolidated statements of operations and comprehensive income.

XML

Commitments And Contingencies

9 Months Ended

Sep. 30, 2011

Commitments And Contingencies

Commitments And Contingencies

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of September 30, 2011, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of approximately 1.2 million, approximately 2.4 million, approximately 1.9 million and approximately 0.5 million tons of coal to 21 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.

Purchase Commitments—As of September 30, 2011, the Partnership had approximately 1.0 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2011 for approximately $2.6 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"). Purchased coal expense from coal purchase contracts and expense from OTC purchases for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
	(in thousands)
Purchased coal expense	$               1,326	$               1,289	$               6,211	$               3,109
OTC expense	$                  771	$                  791	$                  785	$               2,907

There were no outstanding coal purchase commitments as of September 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 nine months ended September 30, 2011 and 2010 was as follows:

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
	(in thousands)
Lease expense	$                  607	$               1,351	$               1,924	$               4,438
Royalty expense	$               3,692	$               3,112	$             11,444	$               9,312

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 nine months ended September 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.

XML

Goodwill And Intangible Assets

9 Months Ended

Sep. 30, 2011

Goodwill And Intangible Assets

Goodwill And Intangible Assets

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 September 30, 2011 and December 31, 2010 consisted of the following:

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

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

	Gross		Net
	Carrying	Accumulated	Carrying
	Amount	Amortization	Amount
	(in thousands)
Patent	$            728	$            110	$            618
Developed Technology	78	12	66
Total	$            806	$            122	$            684

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 September 30, 2011:

		Developed
	Patent	Technology	Total
	(in thousands)
2011 (from Oct 1 to December 31)	$             11	$              1	$             12
2012	43	5	48
2013	43	5	48
2014	43	5	48
2015	43	5	48

XML

Fair Value Of Financial Instruments

9 Months Ended

Sep. 30, 2011

Fair Value Of Financial Instruments

Fair Value Of Financial Instruments

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 September 30, 2011.

XML

Condensed Consolidated Statements Of Cash Flows (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 25,359	$ 35,494
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	26,513	24,146
Accretion on asset retirement obligations	1,469	1,627
Accretion on interest - free debt	157	149
Amortization of advance royalties	906	697
Amortization of deferred revenue	(361)
Amortization of debt issuance costs	774
Provision (reversal) for doubtful accounts	(19)
Equity in net (income) of unconsolidated affiliate	(3,158)	(2,012)
Loss on retirement of advance royalties	79	390
(Gain) on sale/ acquisition of assets - net	(2,836)	(10,830)
Equity-based compensation	643
Changes in assets and liabilities:
Accounts receivable	(4,913)	(5,372)
Inventories	1,621	(2,514)
Advance royalties	(981)	(1,269)
Prepaid expenses and other assets	1,074	(820)
Accounts payable	5,657	1,074
Accrued expenses and other liabilities	779	2,796
Asset retirement obligations	(1,967)	(1,239)
Postretirement benefits	521	548
Net cash provided by operating activities	51,317	42,865
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(64,606)	(19,340)
Proceeds from sales of property, plant, and equipment	1,841	93
Proceeds from sale of coal properties and related assets and liabilities	20,000
Principal payments received on notes receivable	5,270	1,142
Cash advances from issuance of notes receivable	(5,270)	(765)
Changes in restricted cash	34	(3)
Acquisition of coal companies and other properties	(119,299)	(15,000)
Return of capital from unconsolidated affiliate	1,311
Net cash used in investing activities	(160,719)	(33,873)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	276,350	93,300
Repayments on line of credit	(194,450)	(101,996)
Proceeds from issuance of long-term debt	1,379
Repayments on long-term debt	(2,700)
Net settlement of withholding taxes on employee unit awards vesting	(164)
Debt issuance costs	(3,758)	(783)
Partner contributions	1,444
Distributions to unitholders	(35,038)
Proceeds from issuance of common units, net of issuance costs	66,916
Payment of offering costs	(357)
Net cash provided by (used in) financing activities	109,622	(9,479)
NET INCREASE (DECREASE) CASH AND CASH EQUIVALENTS	220	(487)
CASH AND CASH EQUIVALENTS-Beginning of period	76	687
CASH AND CASH EQUIVALENTS-End of period	$ 296	$ 200

XML

Supplemental Disclosures Of Cash Flow Information

9 Months Ended

Sep. 30, 2011

Supplemental Disclosures Of Cash Flow Information

Supplemental Disclosures Of Cash Flow Information

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2011 excludes approximately $1.8 million of property additions, which are recorded in accounts payable.

XML

Subsequent Events

9 Months Ended

Sep. 30, 2011

Subsequent Events

Subsequent Events

19. SUBSEQUENT EVENTS

On October 21, 2011, the Partnership announced a cash distribution of $0.48 per common unit and subordinated unit, or $1.92 per unit on an annualized basis. This total distribution of approximately $13.6 million, which includes approximately $0.3 million paid to the Partnership's General Partner for their proportionate ownership interest, was paid on November 14, 2011 to all unitholders of record as of the close of business on November 1, 2011.

XML

Summary Of Significant Accounting Policies And General

9 Months Ended

Sep. 30, 2011

Summary Of Significant Accounting Policies And General

Summary Of Significant Accounting Policies And General

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 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 and third quarters of 2011, the joint venture borrowed approximately $5.3 million from the Partnership. As of September 30, 2011, the joint venture had repaid the entire amount borrowed.

XML

Employee Benefits

9 Months Ended

Sep. 30, 2011

Employee Benefits

Employee Benefits

11. EMPLOYEE BENEFITS

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

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
	(in thousands)
Service costs	$                  116	$                  122	$                  349	$                  337
Interest cost	74	83	222	219
Total	$                  190	$                  205	$                  571	$                  556

401(k) Plans—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant's salary with an additional matching contribution possible at the Operating Company's discretion. The expense under these plans for the three and nine months ended September 30, 2011 and 2010 was as follows:

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
	(in thousands)
401(k) plan expense	$                  583	$                  454	$               1,652	$               1,430

XML

Major Customers

9 Months Ended

Sep. 30, 2011

Major Customers

Major Customers

15. MAJOR CUSTOMERS

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

	September 30,	Nine months	Nine months
	2011	ended	ended
	Receivable	September 30,	September 30,
	Balance	2011 Sales	2010 Sales
	(in thousands)
GenOn Energy, Inc. (fka Mirant Corporation)	$                  3,707	$                44,178	$                31,530
Indiana Harbor Coke Company, L.P	4,199	29,812	40,351
American Electric Power Company, Inc.	3,902	34,273	25,800

XML

Condensed Consolidated Statements Of Financial Position (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
CURRENT ASSETS:
Cash and cash equivalents	$ 296	$ 76
Accounts receivable, net of allowance for doubtful accounts ($0 as of September 30, 2011 and $19 as of December 31, 2010)	34,748	27,351
Inventories	14,013	15,635
Advance royalties, current portion	1,214	1,918
Prepaid expenses and other	4,444	5,376
Total current assets	54,715	50,356
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	603,868	442,112
Less accumulated depreciation, depletion and amortization	(183,086)	(159,535)
Net property, plant and equipment	420,782	282,577
Advance royalties, net of current portion	2,387	2,935
Investment in unconsolidated affiliate	20,597	18,749
Goodwill	202	202
Intangible assets	684	719
Other non-current assets	7,119	3,107
TOTAL	506,486	358,645
LIABILITIES AND PARTNERS' CAPITAL
Accounts payable	21,322	15,493
Accrued expenses and other	18,204	12,969
Current portion of long-term debt	1,994	2,908
Current portion of asset retirement obligations	3,861	4,350
Current portion of postretirement benefits	160	160
Total current liabilities	45,541	35,880
NON-CURRENT LIABILITIES:
Long-term debt	115,270	33,620
Asset retirement obligations	28,306	31,341
Other non-current liabilities	4,177	3,706
Postretirement benefits	7,003	6,481
Total non-current liabilities	154,756	75,148
Total liabilities	200,297	111,028
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS' CAPITAL:
Limited partners	293,903	236,582
General partner	11,661	10,410
Accumulated other comprehensive income	625	625
Total partners' capital	306,189	247,617
TOTAL	$ 506,486	$ 358,645