UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2010

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

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

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

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

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

Large accelerated filer o		Accelerated filer o

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

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

As of November 11, 2010, 12,406,760 common units and 12,397,000 subordinated units were outstanding.

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PART I.—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

RHINO ENERGY LLC

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	September 30, 2010			December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	199,601		$	686,537
Accounts receivable, net of allowance for doubtful accounts ($18,992 as of September 30, 2010 and $18,992 as of December 31, 2009, respectively)	29,754,948			24,383,376
Inventories	16,685,959			14,171,907
Advance royalties, current portion	1,774,822			1,014,588
Prepaid expenses and other	5,588,290			4,569,464
Total current assets	54,003,620			44,825,872
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	433,514,328			398,903,511
Less accumulated depreciation, depletion and amortization	(151,913,553		)	(128,223,914		)
Net property, plant and equipment	281,600,775			270,679,597
Advance royalties, net of current portion	2,981,275			3,558,332
Investment in unconsolidated affiliate	19,198,758			17,186,362
Goodwill	201,500			201,500
Intangible assets	730,931			806,000
Other non-current assets	2,935,708			2,726,800
TOTAL	$	361,652,567		$	339,984,463
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	14,925,718		$	13,851,368
Accrued expenses and other	18,080,034			15,075,419
Current portion of long-term debt	729,944			2,241,634
Current portion of asset retirement obligations	5,427,614			5,427,614
Current portion of postretirement benefits	95,139			95,139
Total current liabilities	39,258,449			36,691,174
NON-CURRENT LIABILITIES
Long-term debt	112,859,783			119,895,791
Asset retirement obligations	40,766,186			39,673,696
Other non-current liabilities	20			208,315
Postretirement benefits	5,775,903			5,114,854
Total non-current liabilities	159,401,892			164,892,656
Total liabilities	198,660,341			201,583,830
COMMITMENTS AND CONTINGENCIES (NOTE 11)
MEMBERS’ EQUITY:
Members’ investment	22,907,427			$	22,907,427
Retained earnings	138,720,901			114,016,015
Accumulated other comprehensive income	1,363,898			1,477,191
Total members’ equity	162,992,226			138,400,633
TOTAL	$	361,652,567		$	339,984,463

See notes to unaudited condensed consolidated financial statements.

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RHINO ENERGY LLC

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
REVENUES:
Coal sales	$	80,982,264		$	92,457,519		$	217,718,119		$	310,727,428
Freight and handling revenues	1,191,855			1,405,622			3,139,063			3,904,290
Other revenues	3,054,918			3,174,922			9,402,635			8,501,399
Total revenues	85,229,037			97,038,063			230,259,817			323,133,117
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	61,008,731			76,163,761			165,200,708			259,682,159
Freight and handling costs	912,652			1,159,745			2,356,839			3,135,902
Depreciation, depletion and amortization	8,343,357			8,633,575			24,146,244			28,505,378
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	4,073,643			3,317,124			11,677,633			12,306,158
(Gain) loss on sale of assets—net	5,528			389,684			(41,244		)	1,677,760
Total costs and expenses	74,343,911			89,663,889			203,340,180			305,307,357
INCOME FROM OPERATIONS	10,885,126			7,374,174			26,919,637			17,825,760
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense and other	(1,469,597		)	(1,791,246		)	(4,250,604		)	(4,682,081		)
Interest income and other	5,074			47,265			23,457			116,568
Equity in net income (loss) of unconsolidated affiliate	1,598,450			773,408			2,012,396			505,742
Total interest and other income (expense)	133,927			(970,573		)	(2,214,751		)	(4,059,771		)
INCOME BEFORE INCOME TAXES	11,019,053			6,403,601			24,704,886			13,765,989
INCOME TAXES	—			—			—			—
NET INCOME	11,019,053			6,403,601			24,704,886			13,765,989
Other comprehensive income:
Amortization of actuarial gain under ASC Topic 815	(113,293		)	—			(113,293		)	—
COMPREHENSIVE INCOME	10,905,760			6,403,601			24,591,593			13,765,989

See notes to unaudited condensed consolidated financial statements.

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RHINO ENERGY LLC

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	24,704,886		$	13,765,989
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	24,146,244			28,505,378
Accretion on asset retirement obligations	1,627,497			2,113,172
Accretion on interest-free debt	148,545			151,676
Amortization of advance royalties	696,434			(182,237		)
Equity in net income of unconsolidated affiliate	(2,012,396		)	(505,742		)
(Gain) loss on retirement of advance royalties	389,429			—
(Gain) loss on sale of assets—net	(41,244		)	1,677,760
Settlement of litigation	—			(1,772,535		)
Changes in assets and liabilities:
Accounts receivable	(5,371,572		)	(1,859,195		)
Inventories	(2,514,052		)	(3,057,280		)
Advance royalties	(1,269,039		)	(386,093		)
Prepaid expenses and other assets	(819,559		)	(1,197,701		)
Accounts payable	1,074,350			(3,800,012		)
Accrued expenses and other liabilities	2,796,320			(912,790		)
Asset retirement obligations	(1,238,838		)	(6,699,516		)
Postretirement benefits	547,756			525,688
Net cash provided by operating activities	42,864,761			26,366,562
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(19,340,601		)	(21,932,926		)
Proceeds from sales of property, plant, and equipment	93,323			710,500
Principal payments received on notes receivable	1,142,183			2,313,462
Cash advances from issuance of notes receivable	(765,000		)	(2,040,000		)
Changes in restricted cash	(3,000		)	—
Acquisition of coal companies and other properties	(15,000,000		)	—
Acquisition of roof bolt manufacturing company	—			(1,821,342		)
Net cash used in investing activities	(33,873,095		)	(22,770,306		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	93,300,000			134,451,292
Repayments on line of credit	(101,996,244		)	(133,204,662		)
Payments on debt issuance costs	(782,358		)	(1,168,674		)
Proceeds from issuance of debt from related party	—			50,000
Repayments on loan payable to related party	—			(5,000,000		)
Distributions to members	—			(68,235		)
Net cash used in financing activities	(9,478,602		)	(4,940,279		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(486,936		)	(1,344,023		)
CASH AND CASH EQUIVALENTS—Beginning of period	686,537			1,937,265
CASH AND CASH EQUIVALENTS—End of period	$	199,601		$	593,242

See notes to unaudited condensed consolidated financial statements.

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RHINO ENERGY LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2010 AND DECEMBER 31, 2009 AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009

1. BASIS OF PRESENTATION AND ORGANIZATION

Basis of Presentation and Principles of Consolidation— The accompanying consolidated financial statements include the accounts of Rhino Energy LLC (the “Company”) and its subsidiaries. Significant intercompany transactions and balances have been eliminated in consolidation.

Unaudited Interim Financial Information—The accompanying unaudited interim financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. The condensed consolidated statement of financial position as of September 30, 2010, condensed statements of operations for the three and nine month periods ended September 30, 2010 and 2009 and the consolidated statements of cash flows for the nine months ended September 30, 2010 and 2009 include all adjustments (consisting of normal recurring adjustments) which the Company considers necessary for a fair presentation of the financial position, operating results and cash flows for the periods presented. The results of operations for the interim periods 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 registration statement filed with the SEC.

Organization—

Initial Public Offering

On October 5, 2010, Rhino Resource Partners LP (the “Partnership”) completed its initial public offering of 3,730,600 common units, representing limited partner interests in the Partnership, (“IPO”) at a price of $20.50 per common unit. Net proceeds from the offering were approximately $68.3 million, after deducting underwriting discounts and estimated offering expenses of $7.5 million. The Partnership used the net proceeds from this offering, and a related capital contribution by Rhino GP LLC, the Partnership’s general partner (the “General Partner”) of approximately $10.4 million, to repay approximately $69.4 million of outstanding indebtedness under the Company’s credit facility and to reimburse affiliates of the Partnership’s sponsor, Wexford Capital LP, for capital expenditures incurred with respect to the assets contributed to the Partnership in connection with the offering. In connection with the closing of the IPO, the owners of the Company contributed their membership interests in the 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 LP, and issued incentive distribution rights to the General Partner. Upon the closing of the IPO, and as required by the Company’s credit agreement by and among the 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%

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of the membership interests in the Company to the agent on behalf of itself and the other lenders to secure the Company’s obligations under the Credit Agreement.

Acquisition of Coal Property

In August 2010, the Company 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 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 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 Company is staffing the location and rehabilitating the mine and equipment and expects to begin production from these assets at one underground mine in late 2010. The coal produced and sold from these mining assets is expected be sold as steam coal.

The Company must allocate 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 (previously Statement of Financial Accounting Standards (“SFAS”) No. 141R, “Business Combinations”). The Company’s estimate of the value of the assets acquired and liabilities assumed in this transaction are as follows:

Mining and other equipment & related facilities	$	9,265,000
Asset retirement costs	703,831
Coal properties	5,735,000
Asset retirement obligation liability assumed	(703,831		)
Net assets acquired	15,000,000
Total consideration	$	15,000,000

Although the responsibility of valuation remains with the Company’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 mining and other equipment & related facilities and the coal properties 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 Company’s estimates of fair value at this time. To the extent that the purchase price of the assets may be greater than the final fair value of the net assets acquired, the Company will record goodwill and to the extent that the final fair value of the assets may be greater than the purchase price, the company will record a gain.

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The Company has not disclosed any revenue or earnings generated from the acquired assets or on a pro-forma basis prior to acquisition since production has not yet begun for this location.

Acquisition-related costs in the amount of approximately $0.4 million were expensed as of September 30, 2010 and included legal and engineering fees incurred to effect the business combination.

Acquisition of Manufacturing Company

In January 2009, the Company acquired the manufacturing operations of Triad Roof Support Systems, LLC located in Kentucky as part of a vertical integration effort. This operation produces roof control products used in underground coal mining. This acquisition included a manufacturing facility as well as a small product development shop. The Company allocated the purchase price to assets and liabilities acquired based upon their respective fair values in accordance with Accounting Standards Codification (“ASC”) Topic 805 (previously Statement of Financial Accounting Standards (“SFAS”) No. 141R, “Business Combinations”). As the purchase price of the assets was greater than the fair value of the net assets acquired, the Company recorded goodwill. The recorded value of the assets and liabilities were:

Inventory	$	21,342
Property, plant and equipment	792,500
Intangible assets	806,000
Goodwill	201,500
Net assets acquired	$	1,821,342
Total consideration	$	1,821,342

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 Company’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Company is determined to be the primary beneficiary. Equity investments are recorded at original cost and adjusted periodically to recognize the Company’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 Company resumes accounting for the investment under the equity method when the entity subsequently reports net income and the Company’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 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 Company contributed approximately $16.1 million for a 51% ownership interest in the joint venture, and accounts for the investment in the joint venture

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and its results of operations under the equity method. The joint venture was formed for the purpose of mining certain coal reserves that the joint venture controls. The Company’s exposure to potential losses the joint venture may incur is in proportion to the Company’s ownership interest in the joint venture. The joint venture is expected to produce approximately 0.25 million to 0.5 million tons in 2010 which would be approximately 12% of total Company tons. The Company considers the operations of this entity to comprise a separate reporting segment and has provided supplemental detail related to this operation in the “Segment Information” footnote.

3. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of September 30, 2010 and December 31, 2009 consisted of the following:

	September 30, 2010		December 31, 2009
Notes receivable	$	—	$	377,183
Deferred offering costs	2,346,468		—
Other prepaid expenses	751,324		571,834
Prepaid insurance	1,736,590		2,918,607
Prepaid leases	53,429		53,646
Supply inventory	529,666		480,458
Deposits	170,813		167,736
Total	$	5,588,290	$	4,569,464

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of September 30, 2010 and December 31, 2009 are summarized by major classification as follows:

	Useful Lives	September 30, 2010			December 31, 2009
Land and Land Improvements		$	25,812,872		$	21,413,003
Mining and other equipment and related facilities	2 - 20 Years	219,724,526			203,725,387
Mine development costs	1 - 15 Years	50,252,055			47,135,311
Coal properties	1 - 15 Years	127,147,868			119,764,966
Construction work in process		10,577,007			6,864,844
Total		433,514,328			398,903,511
Less accumulated depreciation, depletion and amortization		(151,913,553		)	(128,223,914		)
Net		$	281,600,775		$	270,679,597

Depreciation expense for mining and other equipment and related facilities for the three months ended September 30, 2010 and 2009 was $6,803,526 and $7,318,417, respectively. Depreciation expense for mining and other equipment and related facilities for the nine months

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ended September 30, 2010 and 2009 was $20,238,041 and $22,781,056, respectively. Depletion expense for coal properties for the three months ended September 30, 2010 and 2009 was $470,034 and $467,810 respectively. Depletion expense for coal properties for the nine months ended September 30, 2010 and 2009 was $1,441,385 and $1,845,241 respectively. Amortization expense for mine development costs for the three months ended September 30, 2010 and 2009 was $639,166 and $495,682, respectively. Amortization expense for mine development costs for the nine months ended September 30, 2010 and 2009 was $1,473,177 and $2,292,041, respectively. Amortization expense for asset retirement costs for the three months ended September 30, 2010 and 2009 was $418,779 and $351,666, respectively. Amortization expense for asset retirement costs for the nine months ended September 30, 2010 and 2009 was $918,572 and $1,586,981, respectively. Amortization expense for intangible assets for the three months ended September 30, 2010 and 2009 was $11,852 and $0, respectively. Amortization expense for intangible assets for the nine months ended September 30, 2010 and 2009 was $75,069 and $0, respectively.

5. GOODWILL AND INTANGIBLE ASSETS

ASC Topic 350 (previously SFAS No. 142, “Goodwill and Other Intangible Assets”) addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under the provisions of ASC Topic 350, goodwill and other intangible assets with indefinite useful lives are no longer amortized but instead tested for impairment at least annually.

Goodwill as included in the Other reporting segment as of September 30, 2010 and December 31, 2009 consisted of the following:

	September 30, 2010		December 31, 2009
Goodwill from the acquisition of Triad	$	201,500	$	201,500

Intangible assets as of September 30, 2010 consisted of the following:

Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Patent	$	728,000	$	67,804	$	660,196
Developed Technology	78,000		7,265		70,735
Total	$	806,000	$	75,069	$	730,931

Intangible assets as of December 31, 2009 consisted of the following:

Intangible Asset	Gross Carrying Amount		Accumulated Amortization	Net Carrying Amount
Patent	$	728,000	—	$	728,000
Developed Technology	78,000		—	78,000
Total	$	806,000	—	$	806,000

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The Company 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. Amortization for the three and nine month periods ended September 30, 2009 was not material.

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, 2010:

	Patent	Developed Technology	Total
2010	10,706	1,147	11,853
2011	42,824	4,588	47,412
2012	42,824	4,588	47,412
2013	42,824	4,588	47,412
2014	42,824	4,588	47,412

6. OTHER NON-CURRENT ASSETS

Other non-current assets as of September 30, 2010 and December 31, 2009 consisted of the following:

	September 30, 2010		December 31, 2009
Deposits and other	$	409,637	$	321,531
Debt issuance costs—net	2,465,573		2,271,728
Deferred expenses	60,498		133,541
Total	$	2,935,708	$	2,726,800

Debt issuance costs were $5,091,860 and $4,309,502 as of September 30, 2010 and December 31, 2009, respectively. Accumulated amortization of debt issuance costs were $2,626,287 and $2,037,774 as of September 30, 2010 and December 31, 2009, respectively.

7. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of September 30, 2010 and December 31, 2009 consisted of the following:

	September 30, 2010		December 31, 2009
Payroll, bonus and vacation expense	$	4,702,507	$	3,667,804
Non income taxes	4,814,079		3,641,636
Royalty expenses	2,692,986		2,549,714
Accrued interest	306,673		325,508
Health claims	1,833,971		1,618,611
Workers’ compensation & pneumoconiosis	3,594,150		3,090,227
Other	135,668		181,919
Total	$	18,080,034	$	15,075,419

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8. DEBT

Debt as of September 30, 2010 and December 31, 2009 consisted of the following:

	September 30, 2010			December 31, 2009
Line of credit with PNC Bank, N.A.	$	107,390,000		$	114,000,000
Note payable to H&L Construction Co., Inc.	3,139,496			3,627,709
Other notes payable	3,060,231			4,509,716
Total	113,589,727			122,137,425
Less current portion	(729,944		)	(2,241,634		)
Long-term debt	$	112,859,783		$	119,895,791

Line of credit with PNC Bank, N.A.—Borrowings under the line of credit bear interest which varies depending upon the grouping of the borrowings within the line of credit. At September 30, 2010, the Company had borrowed $39,000,000 at a variable interest rate of LIBOR plus 3.00% (3.26% at September 30, 2010) and an additional $68,390,000 under a revolving credit arrangement at a variable interest rate of PRIME plus 1.00% (4.75% at September 30, 2010). The Company also had outstanding letters of credit of $24,097,118 at a fixed interest rate of 3.00% at September 30, 2010. The Credit Agreement is to expire in February 2013. At September 30, 2010, the Company had not used $68,512,882 of the borrowing availability. As part of the agreement, the Company is required to pay a commitment fee of 0.500% on the unused portion of the borrowing availability. Borrowings on the line of credit are collateralized by all of the assets of the Company.

The revolving credit commitment requires the Company to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, selling or assigning stock.

In April 2009, the Company amended the Credit Agreement to revise certain restrictive provisions and extend the agreement expiration date to February 2013. The restrictive provisions of the Credit Agreement were effective as of March 31, 2009 and the Company was in compliance with all the financial restrictive provisions of the Credit Agreement as of September 30, 2010 and December 31, 2009.

In June 2010, the Company further amended the Credit Agreement to revise certain restrictive provisions, allow for the equity transfer of the Company to the Partnership in the event of a successful IPO and provide for quarterly cash distributions of available cash, as that term is defined in the Partnership’s limited partnership agreement. The IPO was completed on October 5, 2010 as described in the “Basis of Presentation and Organization” note.

Note payable to H&L Construction Co., Inc.—In September 2009, the Company amended and restated the note payable to H&L Construction Co., Inc. This note payable is a non-interest bearing note. The Company has recorded a discount for imputed interest at a rate of 5.0% on this note. The Company is amortizing this discount over the life of the note using the effective interest method. The note payable matures in January 2015. The note is secured by

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mineral rights purchased by the Company from H&L Construction Co., Inc. with a carrying amount of $11,882,658 at September 30, 2010 and $12,388,127 at December 31, 2009.

9. ASSET RETIREMENT OBLIGATIONS

The changes in the Company’s asset retirement obligations for the nine months ended September 30, 2010 and the year ended December 31, 2009 are:

	Nine months Ended September 30, 2010			Year Ended December 31, 2009
Balance at beginning of period (including current portion)	$	45,101,310		$	55,760,291
Accretion expense	1,627,497			2,752,665
Adjustment resulting from addition of property	703,831			—
Adjustment resulting from disposal of property	—			(2,038,433		)
Adjustments to the liability from annual recosting and other	—			(6,595,947		)
Liabilities settled	(1,238,838		)	(4,777,266		)
Balance at end of period	46,193,800			45,101,310
Current portion of asset retirement obligation	(5,427,614		)	(5,427,614		)
Long-term portion of asset retirement obligation	$	40,766,186		$	39,673,696

10. EMPLOYEE BENEFITS

Net periodic benefit cost for the three and nine months ended September 30, 2010 and 2009 are as follows:

	Three months Ended September 30, 2010		Three months Ended September 30 2009
*Net periodic benefit cost:*
Service costs	$	122,536	$	107,153
Interest cost	82,640		68,077
Amortization of (gain)	—		—
Benefit cost	$	205,176	$	175,230

	Nine months Ended September 30, 2010		Nine months Ended September 30 2009
*Net periodic benefit cost:*
Service costs	$	336,841	$	321,458
Interest cost	218,791		204,231
Amortization of (gain)	—		—
Benefit cost	$	555,632	$	525,689

401(k) Plans—The Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Company matches voluntary contributions of participants up to a maximum contribution based upon a

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percentage of a participant’s salary with an additional matching contribution possible at the Company’s discretion. The expense under these plans for the three months ended September 30, 2010 and 2009 was approximately $454,000 and $530,000, respectively. The expense under these plans for the nine months ended September 30, 2010 and 2009 was approximately $1,430,000 and $1,784,000, respectively.

11. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of September 30, 2010, the Company had commitments under sales contracts to deliver annually scheduled base quantities of 1.1 million, 3.1 million, 2.2 million and 1.4 million tons of coal to 20 customers for the remainder of 2010, 10 customers in 2011, 5 customers in 2012, and 3 customers in 2013, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

As of December 31, 2009, the Company had commitments under sales contracts to deliver annually scheduled base quantities of 4.2 million, 2.4 million, 2.2 million, 1.8 million and 1.0 million tons of coal to 19 customers in 2010, 5 customers in 2011, 4 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, 2010, the Company had 0.8 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2010 for $1.8 million. As of December 31, 2009, the Company had 3.1 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2010 for $7.3 million.

Purchased Coal Expenses—The Company incurred purchased coal expense of approximately $1.3 million and $1.7 million for the three months ended September 30, 2010 and 2009, respectively, related to coal purchase contracts. The Company incurred purchased coal expense of approximately $3.1 million and $8.8 million for the nine months ended September 30, 2010 and 2009, respectively, related to coal purchase contracts. In addition, the Company incurred purchased coal expense of approximately $0.8 million and $25.0 million for coal purchased on the over-the-counter (“OTC”) market for the three months ended September 30, 2010 and 2009, respectively. The Company incurred purchased coal expense of approximately $2.9 million and $76.6 million for coal purchased on the OTC market for the nine months ended September 30, 2010 and 2009, respectively. There were no outstanding coal purchase commitments as of September 30, 2010.

Leases—The Company leases various mining, transportation and other equipment under operating leases. Lease expense for the three months ended September 30, 2010 and 2009 was approximately $1.3 million and $2.0 million, respectively. Lease expense for the nine months ended September 30, 2010 and 2009 was approximately $4.4 million and $6.3 million, respectively.

The Company also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Total royalty expense for the three months ended September 30, 2010 and

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2009 was approximately $3.1 million and $1.0 million, respectively. Total royalty expense for the nine months ended September 30, 2010 and 2009 was approximately $9.3 million and $8.5 million, respectively.

Joint Venture—Pursuant to the joint venture agreement with Patriot, the Company 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, 2010 and 2009, the Company did not make any capital contributions. The Company may be required to contribute additional capital to the joint venture in subsequent periods.

12. MAJOR CUSTOMERS

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

	September 30, 2010 Receivable Balance		Nine months Ended September 30, 2010 Sales		Nine months Ended September 30, 2009 Sales
Indiana Harbor Coke Company, L.P	$	3,935,501	$	40,351,078	$	34,945,198
Mirant Energy Trading, LLC	2,960,211		31,530,346		n/a
American Electric Power Company, Inc.	2,987,911		25,800,310		75,004,456
Constellation Energy Group, Inc.	n/a		n/a		50,876,633

13. 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 Company’s debt instruments and notes receivable approximate fair value since effective rates for these instruments are comparable to market at September 30, 2010.

14. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash payments for interest were $3.5 million and $4.1 million for the nine months ended September 30, 2010 and 2009, respectively. In September 2009, the Company realized a settlement on the outstanding debt balance with H&L Construction Company, Inc., resulting in a non-cash debt reduction of $1,772,535. The Unaudited Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2010 is exclusive of $703,831 of non-cash additions to asset retirement obligations and mineral rights. The Unaudited Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 2009 is exclusive of $118,157 of property additions which are recorded in accounts payable.

15. SEGMENT INFORMATION

The Company produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Colorado. The Company sells primarily to electric utilities in the United States. The Company has four reportable business segments: Central Appalachia (comprised of both surface and underground mines located in Eastern Kentucky and Southern

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West Virginia), Northern Appalachia (comprised of both surface underground mines located in Ohio), Eastern Met (comprised solely of the joint venture with Patriot Coal) and the Other segment. For 2010, the Other segment includes the Company’s Colorado and Utah operations and its ancillary businesses that do not meet the aggregation criteria and that do not exceed the quantitative thresholds requiring separate disclosure as a reportable segment. For 2009, the Other segment does not include the Utah operations since this was recently acquired. The Company has not provided disclosure of total expenditures by segment for long-lived assets, as the Company does not maintain discrete financial information concerning segment expenditures for long-lived assets, and accordingly such information is not provided to the Company’s chief operating decision maker.

The Company accounts for the Eastern Met segment under the equity method. Under the equity method of accounting, only limited information is presented. The Company considers this operation to comprise a separate reporting segment and as a result supplemental operating detail is presented for comparability.

Reportable segment results of operations for the three months ended September 30, 2010 are as follows:

					Eastern Met
	Central Appalachia		Northern Appalachia		Complete Basis		Equity Method Eliminations			Equity Method Presentation		Other			Total Segments
Total revenues	$	56,949,109	$	24,314,290	$	11,173,247	$	(11,173,247	)	$	—	$	3,965,638		$	85,229,037
Depreciation, depletion and amortization	5,073,138		2,102,860		789,717		(789,717		)	—		1,167,359			8,343,357
Interest expense	609,753		556,616		11,225		(11,225		)	—		303,228			1,469,597
Net Income (loss)	$	7,820,693	$	2,585,874	$	3,134,216	$	(1,535,766	)	$	1,598,450	$	(985,964	)	$	11,019,053

Reportable segment results of operations for the three months ended September 30, 2009 are as follows:

					Eastern Met
	Central Appalachia		Northern Appalachia		Complete Basis		Equity Method Eliminations			Equity Method Presentation		Other		Total Segments
Total revenues	$	67,320,226	$	25,937,347	$	7,267,227	$	(7,267,227	)	$	—	$	3,780,490	$	97,038,063
Depreciation, depletion and amortization	5,590,891		1,943,433		719,337		(719,337		)	—		1,099,251		8,633,575
Interest expense	956,950		569,804		141,199		(141,199		)	—		264,492		1,791,246
Net Income (loss)	$	1,266,836	$	4,323,635	$	1,516,486	$	(743,078	)	$	773,408	$	39,722	$	6,403,601

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Reportable segment results of operations for the nine months ended September 30, 2010 are as follows:

					Eastern Met
	Central Appalachia		Northern Appalachia		Complete Basis		Equity Method Eliminations			Equity Method Presentation		Other			Total Segments
Total revenues	$	147,207,146	$	70,995,064	$	24,849,591	$	(24,849,591	)	$	—	$	12,057,607		$	230,259,817
Depreciation, depletion and amortization	14,586,785		6,077,340		2,331,154		(2,331,154		)	—		3,482,119			24,146,244
Interest expense	1,831,604		1,621,889		50,010		(50,010		)	—		797,111			4,250,604
Net Income (loss)	$	18,023,831	$	7,211,797	$	3,945,875	$	(1,933,479	)	$	2,012,396	$	(2,543,138	)	$	24,704,886

Reportable segment results of operations for the nine months ended September 30, 2009 are as follows:

						Eastern Met
	Central Appalachia			Northern Appalachia		Complete Basis		Equity Method Eliminations			Equity Method Presentation		Other		Total Segments
Total revenues	$	230,076,667		$	81,036,178	$	21,979,907	$	(21,979,907	)	$	—	$	12,020,272	$	323,133,117
Depreciation, depletion and amortization	19,231,730			5,920,518		2,135,452		(2,135,452		)	—		3,353,130		28,505,378
Interest expense	2,695,415			1,324,850		406,989		(406,989		)	—		661,816		4,682,081
Net Income (loss)	$	(2,480,949	)	$	14,154,903	$	991,651	$	(485,909	)	$	505,742	$	1,586,293	$	13,765,989

16. SUBSEQUENT EVENTS

Management has evaluated the accompanying consolidated financial statements and notes for subsequent events up through November 11, 2010 which is the date the financial statements were available for issue. Management is not aware of any changes that would have a material effect on the financial statements except for the events disclosed in the “Basis of Presentation and Organization” note.

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RHINO RESOURCE PARTNERS LP

UNAUDITED STATEMENTS OF FINANCIAL POSITION

AS OF SEPTEMBER 30, 2010 AND JUNE 30, 2010

	September 30, 2010			June 30, 2010
Assets	$	—		$	—
Liabilities	$	—		$	—
Partners’ Equity:
Limited partner’s equity	$	980		$	980
General partner’s equity	20			20
Receivables from partners	(1,000		)	(1,000		)
Total partners’ equity	$	—		$	—
TOTAL LIABILITIES AND PARTNERS’ EQUITY	$	—		$	—

See notes to unaudited statements of financial position

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

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

The historical unaudited condensed consolidated financial statements included elsewhere in this document reflect the assets, liabilities and operations of Rhino Predecessor. The following discussion of the historical financial condition and results of operations should be read in conjunction with the historical unaudited condensed consolidated financial statements and accompanying notes of Rhino Predecessor included elsewhere in this Quarterly Report on Form 10-Q and the historical audited consolidated financial statements and accompanying notes of Rhino Predecessor for the year ended December 31, 2009 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2009 included in the final prospectus dated September 29, 2010 (the “Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-166550). 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 “Cautionary Note Regarding Forward-Looking Statements.” Factors that could cause actual results to differ include those risks and uncertainties discussed in “Risk Factors.”

Overview

We are a growth-oriented Delaware limited partnership formed to control and operate coal properties and related 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.

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 March 31, 2010, we controlled an estimated 285.4 million tons of proven and probable coal reserves, consisting of an estimated 272.9 million tons of steam coal and an estimated 12.5 million tons of metallurgical coal. In addition, as of March 31, 2010, we controlled an estimated 122.2 million tons of non-reserve coal deposits. As of March 31, 2010, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 22.4 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 34.3 million tons of non-reserve coal deposits. Our and the joint venture’s proven and probable coal reserves and non-reserve coal deposits were

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the same in all material respects as of December 31, 2009. As of September 30, 2010, we operated eleven mines, including six underground and five surface mines, located in Kentucky, Ohio, Colorado, and West Virginia. In addition, the joint venture operated one underground mine in West Virginia. The number of mines that we operate may vary from time to time depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

Our principal business strategy is to safely, efficiently and profitably produce and sell 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 non-coal 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 nine months ended September 30, 2010, we generated revenues of approximately $230.3 million and net income of approximately $24.7 million. Excluding results from the joint venture, for the nine months ended September 30, 2010, we produced approximately 3.2 million tons of coal and sold approximately 3.2 million tons of coal, approximately 96% of which were pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.2 million tons of premium mid-vol metallurgical coal for the nine months ended September 30, 2010.

Recent Developments

Initial Public Offering

On October 5, 2010, we completed our IPO, in which we sold an aggregate of 3,730,600 common units to the public at a price of $20.50 per common unit. Net proceeds from the offering were approximately $68.3 million, after deducting underwriting discounts and estimated offering expenses of $7.5 million. We used the net proceeds from this offering, 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 and to reimburse affiliates of our sponsor, Wexford Capital LP (“Wexford”), for capital expenditures incurred with respect to the assets contributed to us in connection with the offering.

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 and issued incentive distribution rights to our general partner.

Credit Facility

In connection with our IPO, we amended our credit agreement to revise certain restrictive provisions, allow for the equity transfer of Rhino Energy LLC to us in the event of a successful IPO and provide for quarterly cash distributions of available cash, as that term is defined in our

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partnership agreement. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement.”

Utah Acquisition

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. We expect to begin production from these assets at one underground mine in late 2010, and expect the type of coal produced will be steam coal.

Factors That Impact Our Business

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

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

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, 2010, we had commitments under supply contracts to deliver annually scheduled base quantities of 1.1 million, 3.1 million, 2.2 million and 1.4 million tons of coal to 20 customers in the remainder of 2010, 10 customers in 2011, 5 customers in 2012 and 3 customers in 2013, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

During the year ended December 31, 2008, we entered into certain long-term sales contracts at favorable prices. Sales under these contracts are included in the sales and commitments discussed in the previous paragraph and had a significant impact on revenues for nine months ended September 30, 2010. We have remaining commitments under these contracts of approximately 0.3 million tons of coal at an average price of approximately $89 per ton for the remainder of the year ended December 31, 2010 and 0.4 million tons at an average price of $92 per ton for each of the years ended December 31, 2011, 2012 and 2013.

Results of Operations

Segment Information

We conduct business through four reportable business segments: Central Appalachia, Northern Appalachia, Eastern Met and Other. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which, as of September 30, 2010, together included four underground mines, three surface mines and three preparation plants and loadout

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facilities in eastern Kentucky and southern West Virginia. 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, 2010. Our Sands Hill mining complex, located in northern Ohio, included two surface mines, a preparation plant and a river terminal as of September 30, 2010. 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, 2010, this complex was comprised of one underground mine and a preparation plant and loadout facility (owned by our joint venture partner). For the nine months ended September 30, 2010, the Other segment included the results of our operations of two underground mines in the Western Bituminous region (including the newly-acquired Castle Valley mine), our coal reserves in the Illinois Basin and our ancillary businesses. These ancillary businesses include a roof bolt manufacturing operation and various businesses that provide support services such as reclamation, maintenance and transportation, the cost of which is reflected in our cost of operations.

Evaluating Our Results of Operations

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

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

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

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

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, 2010:

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	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2010			2009			2010
	(in millions)
Statement of Operations Data:
Total revenues	$	97.0		$	85.2		$	323.1		$	230.3
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	76.2			61.0			259.7			165.2
Freight and handling costs	1.1			0.9			3.1			2.4
Depreciation, depletion and amortization	8.6			8.3			28.5			24.1
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	3.3			4.1			12.3			11.7
(Gain) loss on sale of assets	0.4			—			1.7			—
Income from operations	7.4			10.9			17.8			26.9
Interest and other income (expense):
Interest expense	(1.8		)	(1.5		)	(4.6		)	(4.2		)
Interest income	—			—			0.1			—
Equity in net income (loss) of unconsolidated affiliate	0.8			1.6			0.5			2.0
Total interest and other income (expense)	(1.0		)	0.1			(4.0		)	(2.2		)
Income tax benefit	—			—			—			—
Net income	$	6.4		$	11.0		$	13.8		$	24.7

Other Financial Data
EBITDA	16.8			20.8			47.0			53.1

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Summary. In the early part of 2009, we experienced eroding margins at certain operations in our Central Appalachia segment due to increased cost of operations when compared to committed sales prices. We made a strategic decision at that time to reduce production at those mines and purchase coal on the open market at prices that allowed us to sustain acceptable margins on these sales.

For the three months ended September 30, 2010, our total revenues decreased to $85.2 million from $97.0 million for the three months ended September 30, 2009. We sold 1.2 million tons of coal for the three months ended September 30, 2010, which is 0.3 million fewer tons, or 22.9% less, than the 1.5 million tons of coal sold for the three months ended September 30, 2009. These decreases were the result of a strategic decision made in 2010 to only sell tons that were contracted at acceptable margins based on current market conditions and increased cost of operations.

For the three months ended September 30, 2010, we reduced our coal inventories by approximately 0.1 million tons while our coal inventories were approximately unchanged for the three months ended September 30, 2009.

Despite the decrease in the volume of tons sold, both net income and EBITDA increased for the three months ended September 30, 2010 from the three months ended September 30, 2009. Net income increased to $11.0 million for the three months ended September 30, 2010 from $6.4 million for the three months ended September 30, 2009, and EBITDA increased to $20.8 million for the three months ended September 30, 2010 from $16.8 million for the three months ended September 30, 2009. The increases in net income and EBITDA were primarily due

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to increased revenue on a per ton basis and a reduction in the amount of coal purchased offset by higher costs of operations in our Central Appalachia and Other segments.

Tons Sold. The following table presents tons of coal sold by reportable segment for the three months ended September 30, 2009 and 2010:

	Three months Ended	Three months Ended	Increase (Decrease)
Segment	September 30, 2009	September 30, 2010	Tons		% *
	(in millions, except %)
Central Appalachia	0.9	0.6	(0.3	)	(34.1	)%
Northern Appalachia	0.5	0.5	—		(3.1	)%
Other	0.1	0.1	—		(17.6	)%
Total *†	1.5	1.2	(0.3	)	(22.9	)%

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

† 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 1.2 million tons of coal in the three months ended September 30, 2010 as compared to 1.5 million tons sold in the three months ended September 30, 2009. This decrease in tons sold was primarily due to management decisions made to match cost of operations with supply contracts that provided acceptable margins in our Central Appalachia segment. Tons of coal sold in our Central Appalachia segment decreased by 0.3 million, or 34.1%, to 0.6 million tons for the three months ended September 30, 2010 from 0.9 million tons for the three months ended September 30, 2009. For our Northern Appalachia segment, tons of coal sold remained constant at 0.5 million tons for both the three months ended September 30, 2009 and the three months ended September 30, 2010. Coal sales from our Other segment also remained constant at approximately 0.1 million tons for the three months ended September 30, 2009 and the three months ended September 30, 2010.

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Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the three months ended September 30, 2009 and 2010:

	Three months ended September		Three months ended September		Increase (Decrease)
Segment	30, 2009		30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	67.2	$	56.8	$	(10.4	)	(15.5	)%
Freight and handling revenues	—		—		—			—
Other revenues	0.1		0.2		0.1			51.6	%
Total revenues	$	67.3	$	57.0	$	(10.3	)	(15.4	)%
Coal revenues per ton*	$	71.90	$	92.18	$	20.28		28.2	%

Northern Appalachia
Coal revenues	$	22.5	$	21.9	$	(0.6	)	(2.8	)%
Freight and handling revenues	1.4		1.2		(0.2		)	(15.2	)%
Other revenues	2.0		1.2		(0.8		)	(38.9	)%
Total revenues	$	25.9	$	24.3	$	(1.6	)	(6.3	)%
Coal revenues per ton*	$	43.70	$	43.87	$	0.16		0.4	%

Other
Coal revenues	$	2.8	$	2.3	$	(0.5	)	(15.2	)%
Freight and handling revenues	—		—		—			—
Other revenues	1.0		1.6		0.6			57.8	%
Total revenues	$	3.8	$	3.9	$	0.1		4.9	%
Coal revenues per ton*	$	42.38	$	43.65	$	1.27		3.0	%

Total
Coal revenues	$	92.5	$	81.0	$	(11.5	)	(12.4	)%
Freight and handling revenues	1.4		1.2		(0.2		)	(15.2	)%
Other revenues	3.1		3.0		(0.1		)	(3.8	)%
Total revenues	$	97.0	$	85.2	$	(11.8	)	(12.2	)%
Coal revenues per ton*	$	61.05	$	69.32	$	8.28		13.6	%

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

Our total revenues for the three months ended September 30, 2010 decreased by $11.8 million, or 12.2%, to $85.2 million from $97.0 million for the three months ended September 30, 2009. The decrease in total revenues was due to the strategic decision to sell only tons that provided an acceptable margin as discussed in the summary. Coal revenues per ton were $69.32 for the three months ended September 30, 2010, an increase of $8.28, or 13.6%, from $61.05 per ton for the three months ended September 30, 2009. This increase in coal revenues per ton was primarily the result of the sale of a higher percentage of metallurgical coal being sold and higher contracted prices for the steam coal.

For our Central Appalachia segment, coal revenues decreased by $10.4 million, or 15.5%, to $56.8 million for the three months ended September 30, 2010 from $67.2 million for the three months ended September 30, 2009 due to strategic decisions made to match cost of

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Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the three months ended September 30, 2009 and 2010:

	Three months ended September		Three months ended September		Increase (Decrease)
Segment	30, 2009		30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	55.6	$	38.9	$	(16.7	)	(30.0	)%
Freight and handling costs	—		—		—			—
Depreciation, depletion and amortization	5.6		5.1		(0.5		)	(9.3	)%
Selling, general and administrative	2.9		3.8		0.9			28.8	%
Cost of operations per ton*	$	59.46	$	63.21	$	3.75		6.3	%

Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	17.1	$	16.8	$	(0.3	)	(1.7	)%
Freight and handling costs	1.2		0.9		(0.3		)	(21.3	)%
Depreciation, depletion and amortization	1.9		2.1		0.2			8.2	%
Selling, general and administrative	0.1		0.1		—			(1.2	)%
Cost of operations per ton*	$	33.24	$	33.74	$	0.50		1.5	%

Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	3.5	$	5.3	$	1.8		51.2	%
Freight and handling costs	—		—		—			—
Depreciation, depletion and amortization	1.1		1.1		—			6.2	%
Selling, general and administrative	0.3		0.2		(0.1		)	(34.1	)%
Cost of operations per ton**	n/a		n/a		n/a			n/a

Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	76.2	$	61.0	$	(15.2	)	(19.9	)%
Freight and handling costs	1.2		0.9		(0.3		)	(21.3	)%
Depreciation, depletion and amortization	8.6		8.3		(0.3		)	(3.4	)%
Selling, general and administrative	3.3		4.1		0.8			22.8	%
Cost of operations per ton*	$	50.29	$	52.23	$	1.94		3.9	%

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

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

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Cost of Operations. Total cost of operations was $61.0 million for the three months ended September 30, 2010 as compared to $76.2 million for the three months ended September 30, 2009, primarily as a result of a decrease in the amount of purchased coal offset by increased costs in our Central Appalachia and Other segments. Our cost of operations per ton was $52.23 for the three months ended September 30, 2010, an increase of $1.94, or 3.9%, from the three months ended September 30, 2009. This overall increase in the cost of operations on a per ton basis was impacted by a decrease in tons of coal purchased for the three months ended September 30, 2010 as compared to the three months ended September 30, 2009. For the three months ended September 30, 2009, we purchased coal at prices per ton that were lower than our cost of operations per ton. Per ton costs were also affected by increases in cost of operations per ton for our Central Appalachia segment as described below.

Our cost of operations for the Central Appalachia segment decreased by $16.7 million, or 30.0%, to $38.9 million for the three months ended September 30, 2010 from $55.6 million for the three months ended September 30, 2009, primarily due to purchasing fewer tons at a lower cost offset by increases in cost of operations associated with labor, contract services, royalties and maintenance. Our cost of operations per ton increased to $63.21 per ton for the three months ended September 30, 2010 from $59.46 per ton for three months ended September 30, 2009. This increase in cost of operations per ton was primarily due to purchasing fewer tons at a lower cost offset by higher cost of operations incurred in our Central Appalachia operations.

In our Northern Appalachia segment, our cost of operations decreased by $0.3 million, or 1.7%, to $16.8 million for the three months ended September 30, 2010 from $17.1 million for the three months ended September 30, 2009, primarily due to decreased expenditures for operating supplies offset by increases in costs such as maintenance and outside services. Our cost of operations per ton increased to $33.74 for the three months ended September 30, 2010 from $33.24 for the three months ended September 30, 2009, an increase of $0.50 per ton, or 1.5%. This increase in cost of operations per ton was primarily due to the application of the cost of operations to a smaller number of tons sold.

Cost of operations in our Other segment increased by $1.8 million for the three months ended September 30, 2010 as compared to the three months ended September 30, 2009. This increase was primarily due to an increase in amounts spent for outside services.

Freight and Handling. Total freight and handling cost for the three months ended September 30, 2010 decreased by $0.3 million, or 21.3%, to $0.9 million from $1.2 million for the three months ended September 30, 2009. This decrease was primarily due to a 0.3 million decrease in the number of tons sold for the period ended September 30, 2010 as compared to the period ended September 30, 2009.

Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization, or DD&A, expense for the three months ended September 30, 2010 was $8.3 million as compared to $8.6 million for the three months ended September 30, 2009.

For the three months ended September 30, 2010, our depreciation cost was $6.8 million as compared to $7.3 million for the three months ended September 30, 2009. The decrease in

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depreciation cost in 2010 was primarily due to the disposal and idling of assets at certain less profitable surface mining operations.

For the three months ended September 30, 2010, our depletion cost was $0.5 million and was equal to the cost for the three months ended September 30, 2009.

For the three months ended September 30, 2010, our amortization cost was $1.1 million as compared to $0.8 million for the three months ended September 30, 2009. 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. Selling, general and administrative, or SG&A, expense for the three months ended September 30, 2010 was $4.1 million as compared to $3.3 million for the three months ended September 30, 2009. This increase in SG&A expense was primarily due to an increase in expenditures for legal fees associated with the Castle Valley Acquisition and other professional fees.

Interest Expense. Interest expense for the three months ended September 30, 2010 was $1.5 million as compared to $1.8 million for the three months ended September 30, 2009, a decrease of $0.3 million, or 18.0%. This decrease was primarily the result of a reduction in the balance due under our credit facility.

Net Income (Loss). The following table presents net income (loss) by reportable segment for the three months ended September 30, 2009 and 2010:

Segment	Three months Ended September 30, 2009		Three months Ended September 30, 2010			Increase (Decrease)
	(in millions)
Central Appalachia	$	1.2	$	7.8		$	6.6
Northern Appalachia	4.3		2.6			(1.7		)
Eastern Met *	0.8		1.6			0.8
Other	0.1		(1.0		)	(1.1		)
Total	$	6.4	$	11.0		$	4.6

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

For the three months ended September 30, 2010, total net income increased to $11.0 million from $6.4 million for the three months ended September 30, 2009. This increase was primarily due to the sale of a higher percentage of metallurgical coal, higher contracted prices for the steam coal and a reduction in the amount of coal purchased that was sold near breakeven in 2009. For our Central Appalachia segment, net income increased to $7.8 million for the three months ended September 30, 2010, an improvement of $6.6 million as compared to the three months ended September 30, 2009, primarily due the sale of a higher percentage of metallurgical coal, higher contracted prices for the steam coal and a reduction in the amount of coal purchased that was sold at near breakeven in 2009. Net income in our Northern Appalachia segment decreased by $1.7 million to $2.6 million for the three months ended September 30, 2010, from $4.3 million for the three months ended September 30, 2009. This decrease was primarily the

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result of a decrease in sales. Our Eastern Met segment recorded net income of $1.6 million for the three months ended September 30, 2010, an increase of $0.8 million from $0.8 million recorded for the three months ended September 30, 2009. For the Other segment, we had a net loss of $1.0 million for the three months ended September 30, 2010, a decrease of $1.1 million as compared to net income of $0.1 million recorded for the three months ended September 30, 2009. This decrease was primarily due to decreases in sales and a concurrent increase in costs of operations.

EBITDA. The following table presents EBITDA by reportable segment for the three months ended September 30, 2009 and 2010:

Segment	Three months Ended September 30, 2009		Three months Ended September 30, 2010		Increase (Decrease)
	(in millions)
Central Appalachia	$	7.8	$	13.5	$	5.7
Northern Appalachia	6.8		5.2		(1.6		)
Eastern Met *	0.8		1.6		0.8
Other	1.4		0.5		(0.9		)
Total	$	16.8	$	20.8	$	4.0

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

Total EBITDA for the three months ended September 30, 2010 was $20.8 million, an increase of $4.0 million from the three months ended September 30, 2009 primarily due to an increase in net income of $4.6 million offset by a decrease in depreciation expense of $0.3 million and a decrease in interest expense of $0.3 million. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, DD&A and interest expense are not presented separately for our Eastern Met segment. Please read “—Reconciliation of EBITDA to Net Income by Segment” for reconciliations of EBITDA to net income on a segment basis.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Summary. For the nine months ended September 30, 2010, our total revenues decreased to $230.3 million from $323.1 million for the nine months ended September 30, 2009. The decrease was primarily due to a decrease in our production of coal. We reduced our overall production of coal by 0.7 million tons to 3.2 million tons for the nine months ended September 30, 2010. In addition, we purchased 0.1 million tons of coal for the nine months ended September 30, 2010 as compared to 1.6 million tons of coal purchased for the nine months ended September 30, 2009.

As a result of these changes, we sold 3.2 million tons of coal for the nine months ended September 30, 2010, which is 2.0 million fewer or 38.4% less, than the 5.2 million tons of coal sold for the nine months ended September 30, 2009. Despite the decrease in the number of tons that we produced and sold, both net income and EBITDA increased for the nine months ended September 30, 2010 from the nine months ended September 30, 2009. Net income increased to

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$24.7 million for the nine months ended September 30, 2010 from $13.8 million for the nine months ended September 30, 2009, and EBITDA increased to $53.1 million for the nine months ended September 30, 2010 from $47.0 million for the nine months ended September 30, 2009. These increases in net income and EBITDA were due to the sale of a higher percentage of metallurgical coal being sold and higher contracted prices for the steam coal which was partially offset by higher cost of operations.

Tons Sold. The following table presents tons of coal sold by reportable segment for the nine months ended September 30, 2009 and 2010:

	Nine months ended	Nine months ended	Increase (Decrease)
Segment	September 30, 2009	September 30, 2010	Tons		% *
	(in millions, except %)
Central Appalachia	3.4	1.6	(1.8	)	(52.7	)%
Northern Appalachia	1.6	1.5	(0.1	)	(10.9	)%
Other	0.2	0.2	—		—
Total *†	5.2	3.2	(2.0	)	(38.4	)%

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

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

We sold 3.2 million tons of coal in the nine months ended September 30, 2010 as compared to 5.2 million tons sold in the nine months ended September 30, 2009. This decrease in tons sold was primarily due to management decisions made to match cost of operations with coal supply contracts that provided acceptable margins. Tons of coal sold in our Central Appalachia segment decreased by 1.8 million, or 52.7%, to 1.6 million tons for the nine months ended September 30, 2010 from 3.4 million tons for the nine months ended September 30, 2009. For our Northern Appalachia segment, tons of coal sold decreased from 1.6 million tons for the nine months ended September 30, 2009 to 1.5 million tons for the nine months ended September 30, 2010. This decrease was also the result of management decisions made to match cost of operations with supply contracts that provided acceptable margins. Coal sales from the Other segment remained constant at approximately 0.2 million tons for the nine months ended September 30, 2009 and for the nine months ended September 30, 2010.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the nine months ended September 30, 2009 and 2010:

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	Nine months ended September		Nine months ended September		Increase (Decrease)
Segment	30, 2009		30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	229.5	$	146.6	$	(82.9	)	(36.1	)%
Freight and handling revenues	—		—		—			—
Other revenues	0.5		0.6		0.1			8.8	%
Total revenues	$	230.0	$	147.2	$	(82.8	)	(36.0	)%
Coal revenues per ton*	$	68.33	$	92.34	$	24.00		35.1	%

Northern Appalachia
Coal revenues	$	72.1	$	64.0	$	(8.1	)	(11.3	)%
Freight and handling revenues	3.9		3.1		(0.8		)	(19.6	)%
Other revenues	5.0		3.9		(1.1		)	(22.1	)%
Total revenues	$	81.0	$	71.0	$	(10.0	)	(12.4	)%
Coal revenues per ton*	$	44.04	$	43.84	$	(0.20	)	(0.5	)%

Other
Coal revenues	$	9.1	$	7.1	$	(2.0	)	(21.2	)%
Freight and handling revenues	—		—		—			—
Other revenues	3.0		5.0		2.0			65.6	%
Total revenues	$	12.1	$	12.1	$	—		0.3	%
Coal revenues per ton*	$	42.42	$	43.66	$	1.24		2.9	%

Total
Coal revenues	$	310.7	$	217.7	$	(93.0	)	(29.9	)%
Freight and handling revenues	3.9		3.1		(0.8		)	(19.6	)%
Other revenues	8.5		9.5		1.0			10.6	%
Total revenues	$	323.1	$	230.3	$	(92.8	)	(28.7	)%
Coal revenues per ton*	$	59.64	$	67.82	$	8.18		13.7	%

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

Our total revenues for the nine months ended September 30, 2010 decreased by $92.8 million, or 28.7%, to $230.3 million from $323.1 million for the nine months ended September 30, 2009. The decline in total revenues was due to management decisions made to match cost of operations with coal supply contracts that provided acceptable margins. Coal revenues per ton were $67.82 for the nine months ended September 30, 2010, an increase of $8.18, or 13.7%, from $59.64 per ton for the nine months ended September 30, 2009. This increase in coal revenues per ton was primarily the result of a higher percentage of metallurgical tons being sold and higher contracted prices for steam coal.

For our Central Appalachia segment, coal revenues decreased by $82.9 million, or 36.1%, to $146.6 million for the nine months ended September 30, 2010 from $229.5 million for the nine months ended September 30, 2009 due to fewer tons of coal sold in the first nine months of 2010. Coal revenues per ton for our Central Appalachia segment increased by $24.00, or 35.1%, to $92.34 per ton for the nine months ended September 30, 2010 as compared to $68.33 for the nine months ended September 30, 2009, due to the sale of higher quality coal at a higher price per ton.

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Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the nine months ended September 30, 2009 and 2010:

	Nine months ended September		Nine months ended September		Increase (Decrease)
Segment	30, 2009		30, 2010		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	195.2	$	99.8	$	(95.4	)	(48.9	)%
Freight and handling costs	—		—		—			—
Depreciation, depletion and amortization	19.2		14.6		(4.6		)	(24.2	)%
Selling, general and administrative	11.4		10.9		(0.5		)	(4.5	)%
Cost of operations per ton*	$	58.11	$	62.86	$	4.75		8.2	%

Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	53.7	$	50.0	$	(3.7	)	(6.9	)%
Freight and handling costs	3.1		2.4		(0.7		)	(24.8	)%
Depreciation, depletion and amortization	5.9		6.0		0.1			2.6	%
Selling, general and administrative	0.3		0.2		(0.1		)	(5.9	)%
Cost of operations per ton*	$	32.79	$	34.26	$	1.47		4.5	%

Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	10.8	$	15.4	$	4.6		42.9	%
Freight and handling costs	—		—		—			—
Depreciation, depletion and amortization	3.4		3.5		0.1			3.8	%
Selling, general and administrative	0.6		0.5		(0.1		)	(16.3	)%
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)	$	259.7	$	165.2	$	(94.5	)	(36.4	)%
Freight and handling costs	3.1		2.4		(0.7		)	(24.8	)%
Depreciation, depletion and amortization	28.5		24.1		(4.4		)	(15.3	)%
Selling, general and administrative	12.3		11.6		(0.7		)	(5.1	)%
Cost of operations per ton*	$	49.84	$	51.46	$	1.62		3.3	%

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

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Cost of Operations. Total cost of operations was $165.2 million for the nine months ended September 30, 2010 as compared to $259.7 million for the nine months ended September 30, 2009. This decrease was primarily the result of a 0.7 million ton reduction in the amount of coal produced. Our cost of operations per ton was $51.46 for the nine months ended September 30, 2010, an increase of $1.62, or 3.3%, from the nine months ended September 30, 2009. This overall increase in the cost of operations on a per ton basis was due to increased “per ton” costs in our Central Appalachia and Northern Appalachia segments described below for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009.

Our cost of operations for the Central Appalachia segment decreased by $95.4 million, or 48.9%, to $99.8 million for the nine months ended September 30, 2010 from $195.2 million for the nine months ended September 30, 2009, primarily resulting from decreases in coal production and fewer tons purchased. Our cost of operations per ton however increased to $62.86 per ton for the nine months ended September 30, 2010 from $58.11 per ton for nine months ended September 30, 2009. This increase in cost of operations per ton was primarily due to higher costs of labor, outside services, taxes, royalties and maintenance on a “per ton” basis, partially offset by purchasing fewer tons in 2010 as compared to 2009 when tons were purchased at lower costs than our cost to produce.

In our Northern Appalachia segment, our cost of operations decreased by $3.7 million, or 6.9%, to $50.0 million for the nine months ended September 30, 2010 from $53.7 million for the nine months ended September 30, 2009, primarily due to a decrease in the number of tons produced for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. Our cost of operations per ton increased to $34.26 for the nine months ended September 30, 2010 from $32.79 for the nine months ended September 30, 2009, an increase of $1.47 per ton, or 4.5%. This increase in cost of operations per ton was primarily due to higher costs of labor, outside services and maintenance costs allocated across fewer tons of coal sold.

Cost of operations in the Other segment increased by $4.6 million for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. This increase was primarily due to additional costs incurred by our ancillary service companies, in particular our roof bolt manufacturing company.

Freight and Handling. Total freight and handling cost for the nine months ended September 30, 2010 decreased by $0.7 million, or 24.8%, to $2.4 million from $3.1 million for the nine months ended September 30, 2009. This decrease was primarily due to a 2.0 million ton reduction in the number of tons sold for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009.

Depreciation, Depletion and Amortization. Total DD&A expense for the nine months ended September 30, 2010 was $24.1 million as compared to $28.5 million for the nine months ended September 30, 2009.

For the nine months ended September 30, 2010, our depreciation cost was $20.2 million as compared to $22.8 million for the nine months ended September 30, 2009. The decrease in

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depreciation cost was primarily due to the disposal and idling of assets at certain less profitable surface mining operations.

For the nine months ended September 30, 2010, our depletion cost was $1.4 million as compared to $1.8 million for the nine months ended September 30, 2009. The decrease in depletion cost was primarily a result of the decrease in the number of tons of coal produced for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009. Depletion is applied on a per ton basis as coal is produced and decreases as production decreases.

For the nine months ended September 30, 2010, our amortization cost was $2.5 million as compared to $3.9 million for the nine months ended September 30, 2009. This decrease is primarily attributable to an overall decrease in production and a concurrent reduction in the amortization of certain mine development and asset retirement costs based on the lower number of tons of coal produced.

Selling, General and Administrative. SG&A expense for the nine months ended September 30, 2010 was $11.6 million as compared to $12.3 million for the nine months ended September 30, 2009. This decrease in SG&A expense was primarily due to increases in legal and other professional fees.

Interest Expense. Interest expense for the nine months ended September 30, 2010 was $4.3 million as compared to $4.7 million for the nine months ended September 30, 2009, a decrease of $0.4 million, or 9.2%. This decrease was primarily the result of a reduction in the balance due under our credit facility.

Net Income (Loss). The following table presents net income (loss) by reportable segment for the nine months ended September 30, 2009 and 2010:

Segment	Nine months ended September 30, 2009			Nine months ended September 30, 2010			Increase (Decrease)
	(in millions)
Central Appalachia	$	(2.5	)	$	18.0		$	20.5
Northern Appalachia	14.2			7.2			(7.0		)
Eastern Met *	0.5			2.0			1.5
Other	1.6			(2.5		)	(4.1		)
Total	$	13.8		$	24.7		$	10.9

* 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, 2010, total net income increased to $24.7 million from $13.8 million for the nine months ended September 30, 2009. This increase was primarily due to a higher percentage of metallurgical tons being sold and higher contracted prices for steam coal. For our Central Appalachia segment, net income increased to $18.0 million for the nine months ended September 30, 2010, an improvement of $20.5 million as compared to the nine months ended September 30, 2009, primarily due to a higher percentage of metallurgical tons being sold and higher contracted prices for steam coal. Net income in our Northern

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Appalachia segment decreased by $7.0 million to $7.2 million for the nine months ended September 30, 2010, from $14.2 million for the nine months ended September 30, 2009. This decrease was primarily the result of challenging geological conditions that resulted in an increase in operational costs such as roof support, labor and repairs on a per ton basis. For the Other segment, we had a net loss of $2.5 million for the nine months ended September 30, 2010, a decrease of $4.1 million as compared to net income of $1.6 million recorded for the nine months ended September 30, 2009. This decrease was the result of a $1.3 million decrease in income generated by our McClane Canyon mine primarily due to lower revenue and a $2.7 million decrease in revenue from our ancillary service companies. Our Eastern Met segment recorded net income of $2.0 million for the nine months ended September 30, 2010, an increase of $1.5 million from $0.5 million recorded for the nine months ended September 30, 2009.

EBITDA. The following table presents EBITDA by reportable segment for the nine months ended September 30, 2009 and 2010:

Segment	Nine months ended September 30, 2009		Nine months ended September 30, 2010		Increase (Decrease)
	(in millions)
Central Appalachia	$	19.4	$	34.4	$	15.0
Northern Appalachia	21.4		14.9		(6.5		)
Eastern Met *	0.5		2.0		1.5
Other	5.7		1.8		(3.9		)
Total	$	47.0	$	53.1	$	6.1

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

Total EBITDA for the nine months ended September 30, 2010 was $53.1 million, an increase of $6.1 million from the nine months ended September 30, 2009 due to an increase in net income of $10.9 million offset by decreases in DD&A and interest expense of $4.4 million and $0.4 million respectively. Results of operations from our Eastern Met segment are recorded using the equity method and DD&A and interest expense are not presented separately for this segment. Please read “—Reconciliation of EBITDA to Net Income by Segment” for reconciliations of EBITDA to net income on a segment basis.

Reconciliation of EBITDA to Net Income by Segment

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

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Three months ended September 30, 2009	Central Appalachia		Northern Appalachia		Eastern Met *		Other		Total
	(in millions)
Net income	$	1.3	$	4.3	$	0.8	$	—	$	6.4
Plus:
Depreciation, depletion and amortization	5.6		1.9		—		1.1		8.6
Interest expense	0.9		0.6		—		0.3		1.8
EBITDA†	$	7.8	$	6.8	$	0.8	$	1.4	$	16.8

Three months ended September 30, 2010	Central Appalachia		Northern Appalachia		Eastern Met *		Other			Total
	(in millions)
Net income (loss)	$	7.8	$	2.6	$	1.6	$	(1.0	)	$	11.0
Plus:
Depreciation, depletion and amortization	5.1		2.1		—		1.1			8.3
Interest expense	0.6		0.6		—		0.3			1.5
EBITDA	$	13.5	$	5.3	$	1.6	$	0.4		$	20.8

Nine months ended September 30, 2009	Central Appalachia			Northern Appalachia		Eastern Met *		Other		Total
	(in millions)
Net income (loss)	$	(2.5	)	$	14.2	$	0.5	$	1.6	$	13.8
Plus:
Depreciation, depletion and amortization	19.2			5.9		—		3.4		28.5
Interest expense	2.7			1.3		—		0.7		4.7
EBITDA†	$	19.4		$	21.4	$	0.5	$	5.7	$	47.0

Nine months ended September 30, 2010	Central Appalachia		Northern Appalachia		Eastern Met *		Other			Total
	(in millions)
Net income (loss)	$	18.0	$	7.2	$	2.0	$	(2.5	)	$	24.7
Plus:
Depreciation, depletion and amortization	14.6		6.1		—		3.5			24.2
Interest expense	1.8		1.6		—		0.8			4.2
EBITDA†	$	34.4	$	14.9	$	2.0	$	1.8		$	53.1

* 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.

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

Liquidity and Capital Resources

Liquidity

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

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cash generated by our operations, borrowings under our credit agreement and further 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, 2010, our available liquidity was $68.7 million, including cash on hand of $0.2 million and $68.5 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 $42.9 million for the nine months ended September 30, 2010 as compared to $26.4 million for the nine months ended September 30, 2009. This increase in cash provided by operating activities was primarily the result of an increase in net income due to favorable sales prices and a decrease in the use of net working capital related to accrued expenses and other liabilities.

Net cash used in investing activities was $33.9 million for the nine months ended September 30, 2010 as compared to $22.8 million for the nine months ended September 30, 2009. The increase in cash used in investing activities was primarily due to the Castle Valley Acquisition offset by a reduction in amounts expended for the purchase of mining equipment and other asset acquisitions.

Net cash used in financing activities for the nine months ended September 30, 2010 was $9.5 million, which was primarily attributable to repayment of borrowings under our credit agreement. Net cash used for financing activities for the nine months ended September 30, 2009 was $4.9 million, which primarily represented the repayment of a loan from Wexford and the payment of debt issuance costs.

Capital Expenditures

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

Actual maintenance capital expenditures for the nine months ended September 30, 2010 was approximately $8.7 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the nine months ended September 30, 2010 was approximately $25.6 million. These amounts were primarily spent for the Castle

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Valley Acquisition as well as our internal development projects. For the year ending December 31, 2010, we have budgeted $37.4 million for capital expenditures.

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

Credit Agreement

Rhino Energy LLC, our wholly owned subsidiary, as borrower, and we and our operating subsidiaries, as guarantors, are parties to our $200.0 million credit agreement, which is available for general partnership purposes, including working capital and capital expenditures, and may be increased by up to $75.0 million with the consent of the lenders, so long as there is no event of default. Of the $200.0 million, $50.0 million is available for letters of credit. As of September 30, 2010, we had borrowings outstanding under our credit agreement of approximately $107.4 million and $24.1 million of letters of credit in place, leaving approximately $68.5 million of availability under our credit agreement. During the three month period ended September 30, 2010, we had average borrowings outstanding of approximately $108.0 million in relation to this credit agreement.

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

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

Our credit agreement requires us to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. As of September 30, 2010, we are in compliance with respect to all covenants contained in the 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

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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, 2010, we had $24.1 million in letters of credit outstanding, of which $21.2 million served as collateral for surety bonds.

Critical Accounting Policies and Estimates

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

The accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are fully described in our Prospectus. There have been no significant changes in these policies and estimates as of September 30, 2010.

Recent Accounting Pronouncements

Effective January 1, 2008, we adopted the new guidance codified in ASC Topic 820 (previously SFAS No. 157, “Fair Value Measurements”), which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. ASC Topic 820 applies whenever other statements require or permit assets or liabilities to be measured at fair value. ASC Topic 820 requirements for certain non-financial assets and liabilities were permitted to be deferred until the first quarter of 2009 in accordance with Financial Accounting Standards Board, or FASB, Staff Position 157-2, Effective Date of ASC Topic 820. We adopted this new guidance effective January 1, 2009, and at the time of the adoption, there were no nonfinancial assets or nonfinancial liabilities that were measured at fair value on a nonrecurring basis. ASC Topic 820 establishes the following fair value hierarchy that prioritizes the inputs used to measure fair value:

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· Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.

· Level 2—Inputs other than Level 1 that are based on observable market data, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets, quoted prices for identical assets or liabilities in inactive markets, inputs that are observable that are not prices and inputs that are derived from or corroborated by observable markets.

· Level 3—Developed from unobservable data, reflecting an entity’s own assumptions.

ASC Topic 805 (previously SFAS No. 141, “Business Combinations”), among other things, provides guidance for the way companies account for business combinations. This guidance requires transaction-related costs to be expensed as incurred, which were previously accounted for as a cost of acquisition. ASC Topic 805 also requires acquirers to estimate the acquisition-date fair value of any contingent consideration and recognize any subsequent changes in the fair value of contingent consideration in earnings. In addition, restructuring costs the acquirer was not obligated to incur shall be recognized separately from the business acquisition. We adopted this guidance on a prospective basis as of January 1, 2009. The adoption of this guidance did not require remeasurement of any prior balances but will impact accounting for business combinations after date of adoption. This guidance was applied to the purchase accounting of Triad Roof Support Systems LLC and C.W. Mining Company.

ASC Topic 810 (previously SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, An Amendment of ARB No. 51”) requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated financial statements. A single method of accounting has been established for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. Companies no longer recognize a gain or loss on partial disposals of a subsidiary where control is retained. In addition, in partial acquisitions where control is obtained, the acquiring company will recognize and measure at fair value 100% of the assets and liabilities, including goodwill, as if the entire target company had been acquired. We adopted this guidance as of January 1, 2009.

In May 2009, the FASB issued guidance under ASC Topic 855 (previously SFAS No. 165, “Subsequent Events”), which provided general accounting standards for the disclosure of events that occur after the balance sheet date but before the financial statements are issued or available for issue. This guidance does not apply to subsequent events or transactions that are within the scope of other generally accepted accounting principles that provide different guidance on the accounting treatment of subsequent events. ASC Topic 855 includes a new required disclosure of the date through which an entity, other than a public filer, has evaluated subsequent events and the basis for that date. Such disclosures are required for financial statements issued after June 15, 2009 and are included in our condensed consolidated financial statements.

In June 2009, the FASB issued guidance under ASC Topic 810 (previously SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”), which amended the consolidation guidance for variable interest entities, or VIEs. The new guidance requires a company to perform an analysis to determine whether its variable interest gives it a controlling financial interest in a VIE. The amendment, which requires ongoing reassessments, redefines the primary beneficiary

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as the party that (1) has the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and (2) has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The guidance includes enhanced disclosures about a company’s involvement in a VIE and also eliminates the exemption for qualifying special purpose entities. We evaluated this guidance and determined that certain criteria is not met for consolidation of the VIE and will continue to report the results of the VIE using the equity method of accounting.

In June 2009, the FASB adopted ASC Topic 105 (previously SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162”), which is effective for periods after September 15, 2009. The ASC became the source of authoritative GAAP applied to nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. All other non-grandfathered non-SEC accounting literature not included in the ASC is considered non-authoritative. We adopted the ASC as the single source of authoritative nongovernmental generally accepted accounting principles.

ASC 260 (previously SFAS No. 128, “Earnings Per Share”) affects how a master limited partnership, or MLP, allocates income between its general partner, which typically holds incentive distribution rights, along with the general partner interest, and the limited partners. It is not uncommon for MLPs to experience timing differences between the recognition of income and partnership distributions. The amount of incentive distributions is typically calculated based on the amount of distributions paid to the MLP’s partners. The issue is whether current period earnings of an MLP should be allocated to the holders of incentive distribution rights as well as the holders of the general and limited partner interests when applying the two-class method. The conclusion was that when current period earnings are in excess of cash distributions, the undistributed earnings should be allocated to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders based upon the terms of the partnership agreement. Under this model, contractual limitations on distributions to holders of incentive distribution rights would be considered when determining the amount of earnings to allocate to them. That is, undistributed earnings would not be considered available cash for purposes of allocating earnings to incentive distribution rights holders. Conversely, when cash distributions are in excess of earnings, net income (or loss) should be reduced (increased) by the distributions made to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders. The resulting net loss would then be allocated to the holders of the general partner interest and the holders of the limited partner interest based on their respective sharing of the losses based upon the terms of the partnership agreement. This guidance is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The accounting treatment is effective for all financial statements presented. We do not expect the impact of the adoption of this item on our presentation of earnings per unit to be significant.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

We manage our commodity price risk for coal sales through the use of supply contracts and the use of forward contracts.

Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward purchases to manage the exposure related to this volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income by $0.6 million for the nine months ended September 30, 2010. A hypothetical increase of 10% in steel prices would have reduced net income by $1.0 million for the nine months ended September 30, 2010. A hypothetical increase of 10% in explosives prices would have reduced net income by $0.4 million for the nine months ended September 30, 2010.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. During the past year, we have been operating in a period of declining interest rates, and we have managed to take advantage of the trend to reduce our interest expense. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $0.9 million for the nine months ended September 30, 2010.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2010 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. This report does not include a report of management’s assessment regarding internal control over financial reporting

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

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

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

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

Item 3. Defaults upon Senior Securities.

None.

Item 4. [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 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 that differs from the following.

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 which 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 below information 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

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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 three months ended September 30, 2010, none of our operating subsidiaries received written notice from MSHA of (a) a violation under section 110(b)(2) of the Mine Act for failure to make reasonable efforts to eliminate a known violation of a mandatory safety or health standard that substantially proximately caused, or reasonably could have been expected to cause, death or serious bodily injury, (b) a pattern of violations of mandatory health or safety standards under section 104(e) of the Mine Act, or (c) the potential to have such a pattern. We have 42 legal proceedings before the Federal Mine Safety and Health Review Commission (the “Commission”) that were pending during the quarter and that involve all types of citations. All of these legal proceedings constitute appeals by us of citations issued by MSHA. There were no mining-related fatalities during the period covered by this report.

The following table sets out additional information required by to the Dodd-Frank Act as of September 30, 2010.

	104(a)(1)					Total Proposed		Contested
Operator	S & S	104(b)(2)	104(d)(3)	107(a)(4)	110(b)(2)(5)	Assessments(6)		Enforcements(7)
CAM Mining LLC	66	0	1	1	0	$	147,511	56
Deane Mining LLC	5	0	0	0	0	$	9,635	0
Hopedale Mining LLC	21	0	0	0	0	$	16,831	8
McClane Canyon Mining LLC	10	0	0	0	0	$	40,541	0
Rhino Eastern LLC(8)	29	0	6	0	0	$	49,109	4
Rhino Trucking & Oil Field Services	3	0	0	0	0	$	—	0

Total	134	0	7	1	0	$	263,627	68

(1) Mine Act section 104 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.

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

(3) 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.

(4) 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.

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

(6) Amounts shown include MSHA assessments proposed as of September 30, 2010, on the citations and orders reflected in this table. Citations and orders which have not yet been assessed are not included.

(7) These enforcements are being contested through MSHA in the administrative process, but are not yet before the Commission or an administrative law judge.

(8) Rhino Eastern LLC is owned 51% by a subsidiary of Rhino Energy LLC and 49% by a subsidiary of Patriot Coal Corporation.

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Item 6. Exhibits.

Exhibit Number		Description

3.1		Certificate of Limited Partnership of Rhino Resource Partners LP, incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on May 5, 2010

3.2		First Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated as of October 5, 2010, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 8, 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		Contribution, Assignment and Assumption Agreement, dated as of September 29, 2010, by and among Rhino GP LLC, Rhino Resource Partners LP, Rhino Energy LLC, Rhino Energy Holdings LLC, Artis Investors LLC, Solitair LLC, Valentis Investors LLC, Taurus Investors LLC, Callidus Investors LLC, Wexford Spectrum Fund, L.P., Wexford Spectrum Fund Liquidating LLC, Wexford Offshore CAM Preferred Corp., Wexford Offshore CAM Common Corp., Wexford Partners Investment Co. LLC, Peter Savitz and Wexford Capital LP, incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 2010

10.2		Equity Commitment Agreement, dated September 29, 2010, by and among Rhino GP LLC, CD Holding Company, LLC, Jacobs Holdings LLC, Robert H. Holtz, Mark D. Zand, Jay L. Maymudes, Arthur H. Amron, Kenneth A. Rubin, Frederick B. Simon, Kitty Capital LLC, John V. Doyle and John C. Sites, Jr., incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 2010

10.3		Rhino Long-Term Incentive Plan incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 1, 2010

10.4		Form of Long-Term Incentive Plan Grant Agreement—Phantom Units with DERs incorporated by reference to Exhibit 10.12 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010

10.5		Form of Long-Term Incentive Plan Grant Agreement—Unit Awards and Restricted Units (Directors who are not Principals of Wexford) incorporated by reference to Exhibit 10.22 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010

Exhibit Number		Description

10.6		Form of Long-Term Incentive Plan Grant Agreement— Unit Awards and Restricted Units (Directors who are Principals of Wexford) incorporated by reference to Exhibit 10.23 of Amendment No. 3 to the Registration Statement on Form S-1 (File No. 333-166550) filed on July 23, 2010

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)

	RHINO RESOURCE PARTNERS LP

	By: Rhino GP LLC, its General Partner


Date: November 12, 2010	By:	/s/ David G. Zatezalo
		David G. Zatezalo
		President and Chief Executive Officer
		(Principal Executive Officer)


Date: November 12, 2010	By:	/s/ Richard A. Boone
		Richard A. Boone
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

Cautionary Note Regarding Forward-Looking Statements		1

Part I.—Financial Information (Unaudited)		2

ITEM 1.	FINANCIAL STATEMENTS	2

	Rhino Energy LLC	2

	Condensed Consolidated Statements of Financial Position as of September 30, 2010 and December 31, 2009	2

	Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2010 and 2009	3

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009	4

	Notes to Condensed Consolidated Financial Statements	5

	Rhino Resource Partners LP

	Unaudited Statements of Financial Position	17

	Notes to Unaudited Statements of Financial Position	18

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantatative and Qualitative Disclosures About Market Risk	44

Item 4.	Controls and Procedures	44

PART II—Other Information		46

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 3.	Defaults upon Senior Securities	46

Item 4.	[Removed and Reserved]	46

Item 5.	Other Information	46

Item 6.	Exhibits	48

SIGNATURES		50