10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

OR

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

For the transition period from                  to                 

Commission file number 001-34892

RHINO RESOURCE PARTNERS LP

(Exact name of registrant as specified in its charter)

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

(859) 389-6500

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o	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 2, 2012, 15,346,683 common units and 12,397,000 subordinated units were outstanding.

TABLE OF CONTENTS

Cautionary Note Regarding Forward-Looking Statements		1
Part I.—Financial Information (Unaudited)		2
ITEM 1.	FINANCIAL STATEMENTS	2
	Condensed Consolidated Statements of Financial Position as of September 30, 2012 and December 31, 2011	2
	Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 4.	Controls and Procedures	66
PART II—Other Information		67
Item 1.	Legal Proceedings	67
Item 1A.	Risk Factors	67
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 3.	Defaults upon Senior Securities	67
Item 4.	Mine Safety Disclosure	67
Item 5.	Other Information	67
Item 6.	Exhibits	68
SIGNATURES		70

Cautionary Note Regarding Forward-Looking Statements

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

Any differences could be caused by a number of factors, including, but not limited to: changes in governmental regulation of the mining industry or the electric utility industry; adverse weather conditions and natural disasters; weakness in global economic conditions; decreases in demand for electricity and changes in demand for coal; poor mining conditions resulting from geological conditions or the effects of prior mining; equipment problems at mining locations; the availability of transportation for coal shipments; the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives; the availability and prices of competing electricity generation fuels; our ability to secure or acquire high-quality coal reserves; and our ability to find buyers for coal under favorable supply contracts. Other factors that could cause our actual results to differ from our projected results are described in (1) Part II, “Item 1A. Risk Factors” and elsewhere in this Form 10-Q, (2) our Annual Report on Form 10-K for the year ended December 31, 2011, (3) our reports and registration statements filed from time to time with the Securities and Exchange Commission and (4) other announcements we make from time to time. In addition, we may be subject to unforeseen risks that may have a materially adverse effect on us.  Accordingly no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements.

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

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PART I.—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands)

	September 30,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	540		$	449
Accounts receivable, net of allowance for doubtful accounts ($0 as of September 30, 2012 and December 31, 2011)	37,227			37,242
Inventories	18,878			15,629
Advance royalties, current portion	471			1,428
Prepaid expenses and other	4,768			4,327
Total current assets	61,884			59,075
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	676,370			637,563
Less accumulated depreciation, depletion and amortization	(209,932		)	(187,447		)
Net property, plant and equipment	466,438			450,116
Advance royalties, net of current portion	3,361			1,924
Investment in unconsolidated affiliates	22,098			18,736
Goodwill	—			202
Intangible assets	1,248			1,308
Other non-current assets	6,608			7,433
TOTAL	$	561,637		$	538,794
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	19,761		$	23,145
Accrued expenses and other	19,974			19,691
Current portion of long-term debt	2,829			1,334
Current portion of asset retirement obligations	3,409			3,192
Current portion of postretirement benefits	157			157
Total current liabilities	46,130			47,519
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion	167,635			141,764
Asset retirement obligations, net of current portion	30,469			30,921
Other non-current liabilities	7,746			6,000
Postretirement benefits, net of current portion	5,842			5,492
Total non-current liabilities	211,692			184,177
Total liabilities	257,822			231,696
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners	290,210			293,100
General partner	11,478			11,650
Accumulated other comprehensive income	2,127			2,348
Total partners’ capital	303,815			307,098
TOTAL	$	561,637		$	538,794

See notes to unaudited condensed consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands)

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2012			2011			2012			2011
REVENUES:
Coal sales	$	83,902		$	81,988		$	225,683		$	244,367
Freight and handling revenues	1,610			1,548			4,923			4,118
Other revenues	8,063			10,028			34,849			17,710
Total revenues	93,575			93,564			265,455			266,195
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	69,369			69,004			186,659			197,477
Freight and handling costs	1,521			1,331			4,583			3,271
Depreciation, depletion and amortization	10,065			9,157			30,912			26,513
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	4,654			6,350			15,039			15,345
(Gain)/loss on sale of assets—net	(1,185		)	(2,702		)	(2,176		)	(2,836		)
Total costs and expenses	84,424			83,140			235,017			239,770
INCOME FROM OPERATIONS	9,151			10,424			30,438			26,425
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense	(2,105		)	(1,850		)	(5,889		)	(4,274		)
Interest income and other	15			14			91			50
Equity in net income of unconsolidated affiliate	1,815			1,258			6,206			3,158
Total interest and other income (expense)	(275		)	(578		)	408			(1,066		)
INCOME BEFORE INCOME TAXES	8,876			9,846			30,846			25,359
INCOME TAXES	—			—			—			—
NET INCOME	8,876			9,846			30,846			25,359
Other comprehensive income:
Amortization of actuarial gain under ASC Topic 715	(73		)	—			(221		)	—
COMPREHENSIVE INCOME	$	8,803		$	9,846		$	30,625		$	25,359
General partner’s interest in net income	$	177		$	197		$	617		$	507
Common unitholders’ interest in net income	$	4,806		$	5,240		$	16,709		$	12,718
Subordinated unitholders’ interest in net income	$	3,893		$	4,409		$	13,520		$	12,134
Net income per limited partner unit, basic:
Common units	$	0.31		$	0.36		$	1.09		$	0.98
Subordinated units	$	0.31		$	0.36		$	1.09		$	0.98
Net income per limited partner unit, diluted:
Common units	$	0.31		$	0.36		$	1.09		$	0.98
Subordinated units	$	0.31		$	0.36		$	1.09		$	0.98
Distributions paid per limited partner unit	$	0.445		$	0.455		$	1.405		$	1.3308
Weighted average number of limited partner units outstanding, basic:
Common units	15,332			14,732			15,322			12,993
Subordinated units	12,397			12,397			12,397			12,397
Weighted average number of limited partner units outstanding, diluted:
Common units	15,333			14,747			15,327			13,014
Subordinated units	12,397			12,397			12,397			12,397

See notes to unaudited condensed consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	30,846		$	25,359
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	30,912			26,513
Accretion on asset retirement obligations	1,305			1,469
Accretion on interest-free debt	165			157
Amortization of deferred revenue	(910		)	(361		)
Amortization of advance royalties	161			906
Amortization of debt issuance costs	806			774
Provision (reversal) for doubtful accounts	—			(19		)
Amortization of actuarial gain	(221		)	—
Equity in net (income) of unconsolidated affiliate	(6,206		)	(3,158		)
Distribution from unconsolidated affiliate	2,958			—
Loss on retirement of advance royalties	86			79
(Gain) on sale of assets—net	(1,764		)	(2,836		)
Equity-based compensation	683			643
Changes in assets and liabilities:
Accounts receivable	15			(4,913		)
Inventories	(3,249		)	1,621
Advance royalties	(728		)	(981		)
Prepaid expenses and other assets	(416		)	1,074
Accounts payable	(3,384		)	5,657
Accrued expenses and other liabilities	7,888			779
Asset retirement obligations	(1,269		)	(1,967		)
Postretirement benefits	350			521
Net cash provided by operating activities	58,028			51,317
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(53,347		)	(64,606		)
Proceeds from sales of property, plant, and equipment	2,684			1,841
Proceeds from sale of coal properties and related assets and liabilities	—			20,000
Principal payments received on notes receivable	11,945			5,270
Cash paid from issuance of notes receivable	(11,945		)	(5,270		)
Changes in restricted cash	—			34
Acquisition of coal companies and other properties	—			(119,299		)
Return of capital from unconsolidated affiliate	—			1,311
Investment in unconsolidated affiliate	(114		)	—
Net cash used in investing activities	(50,777		)	(160,719		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	173,300			276,350
Repayments on line of credit	(146,770		)	(194,450		)
Proceeds from issuance of long-term debt	2,603			1,379
Repayments on long-term debt	(1,932		)	(2,700		)
Net settlement of employee withholding taxes on unit awards vested	(85		)	(164		)
Debt issuance costs	—			(3,758		)
Distributions to unitholders	(34,276		)	(35,038		)
General partner’s contributions	7			1,444
Proceeds from issuance of common units, net of issuance costs	—			66,916
Payment of offering costs	(7		)	(357		)
Net cash (used in) provided by financing activities	(7,160		)	109,622
NET INCREASE IN CASH AND CASH EQUIVALENTS	91			220
CASH AND CASH EQUIVALENTS—Beginning of period	449			76
CASH AND CASH EQUIVALENTS—End of period	$	540		$	296

See notes to unaudited condensed consolidated financial statements.

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RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012 AND DECEMBER 31, 2011 AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

1. BASIS OF PRESENTATION AND ORGANIZATION

Basis of Presentation and Principles of Consolidation— The accompanying unaudited interim financial statements include the accounts of Rhino Resource Partners LP (the “Partnership”) and its subsidiaries. Intercompany transactions and balances have been eliminated in consolidation.

Unaudited Interim Financial Information—The accompanying unaudited interim financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. The condensed consolidated statement of financial position as of September 30, 2012, condensed consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011 and the condensed consolidated statements of cash flows for the nine months ended September 30, 2012 and 2011 include all adjustments (consisting of normal recurring adjustments) which the Partnership considers necessary for a fair presentation of the financial position, operating results and cash flows for the periods presented. The condensed consolidated statement of financial position as of December 31, 2011 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America (“U.S.”). The Partnership filed its Annual Report on Form 10-K for the year ended December 31, 2011 with the Securities and Exchange Commission (“SEC”), which included all information and notes necessary for such presentation. The results of operations for the interim period are not necessarily indicative of the results to be expected for the year or any future period. These unaudited interim financial statements should be read in conjunction with the audited financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Organization—The Partnership is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor” or the “Operating Company”). The Partnership had no operations during the period from April 19, 2010 (date of inception) to October 5, 2010 (the consummation of the IPO of the Partnership). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Kentucky, Ohio, West Virginia, and Utah and also have one underground mine located in Colorado that remained temporarily idled at September 30, 2012. The majority of sales are made to domestic utilities and other coal-related organizations in the United States. In addition to operating coal properties, the Operating Company manages and leases coal properties and collects royalties from such management and leasing activities. The Operating Company was formed in April 2003 and has been built primarily via acquisitions.

In addition to its coal operations, the Partnership has invested in oil and gas mineral rights that began to generate royalty revenues in early 2012.

5

Follow-on Offering

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Investment in Joint Venture.  Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Partnership is determined to be the primary beneficiary of a variable interest entity. Equity investments are recorded at original cost and adjusted periodically to recognize the Partnership’s proportionate share of the investees’ net income or losses after the date of investment. Any losses from the Partnership’s equity method investment are absorbed by the Partnership based upon its proportionate ownership percentage. If losses are incurred that exceed the Partnership’s investment in the equity method entity, then the Partnership must continue to record its proportionate share of losses in excess of its investment. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.

In May 2008, the Operating Company entered into a joint venture, Rhino Eastern LLC (“Rhino Eastern”), with an affiliate of Patriot Coal Corporation (“Patriot”) to acquire the Eagle mining complex. To initially capitalize the joint venture, the Operating Company contributed approximately $16.1 million for a 51% ownership interest in the joint venture and accounts for the investment in the joint venture and its results of operations under the equity method. The Partnership considers the operations of this entity to comprise a reporting segment (“Eastern Met”) and has provided additional detail related to this operation in Note 18, “Segment Information.” As of September 30, 2012 and December 31, 2011, the Partnership has recorded its Rhino Eastern equity method investment of $22.0 million and $18.7 million, respectively, as a long-term asset. During the nine months ended September 30, 2012, the Partnership provided loans to the Rhino Eastern joint venture in the amount of $11.9 million, which were fully repaid as of September 30, 2012.

On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

6

In March 2012, the Partnership made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf, with affiliates of Wexford Capital LP (“Wexford Capital”).  Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio.  The initial investment was the Partnership’s proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during the nine months ended September 30, 2012 and the Partnership will initially include any operating activities of Timber Wolf in its Other category.

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

In June 2011, the FASB published ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income”. Under the amendments in this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In a single continuous statement, the entity is required to present the components of net income and total net income, the components of other comprehensive income and a total for other comprehensive income, along with the total of comprehensive income in that statement. In the two-statement approach, an entity is required to present components of net income and total net income in the statement of net income. The statement of other comprehensive income should immediately follow the statement of net income and include the components of other comprehensive income and a total for other comprehensive income, along with a total for comprehensive income. Regardless of whether an entity chooses to present comprehensive income in a single continuous statement or in two separate but consecutive statements, the entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive

7

income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. The amendments in this ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments do not change the option for an entity to present components of other comprehensive income either net of related tax effects or before related tax effects, with one amount shown for the aggregate income tax expense or benefit related to the total of other comprehensive income items. In both cases, the tax effect for each component must be disclosed in the notes to the financial statements or presented in the statement in which other comprehensive income is presented. The amendments do not affect how earnings per share is calculated or presented. For public entities, the amendments of this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

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

3. BUSINESS COMBINATIONS AND OTHER ACQUISITIONS

Acquisition of The Elk Horn Coal Company, LLC

In June 2011, the Partnership completed the acquisition of 100% of the ownership interests in The Elk Horn Coal Company, LLC (“Elk Horn”) for approximately $119.7 million in cash consideration, or approximately $119.6 million net of cash acquired (referred to as the “Elk Horn Acquisition”). Elk Horn is primarily a coal leasing company that owns or controls coal reserves and non-reserve coal deposits and surface acreage in eastern Kentucky. The Elk Horn

8

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

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

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

The following table presents selected unaudited pro forma financial information for the three and nine months ended September 30, 2011, as if the acquisition had occurred on January 1, 2011. The pro forma information was prepared using Elk Horn’s historical financial data and also reflects adjustments based upon assumptions by the Partnership’s management to give effect for certain pro forma items that are directly attributable to the acquisition. These pro forma adjustment items include increased depletion expense related to the step-up in basis for the mineral assets acquired and increased interest expense from borrowings incurred to fund the acquisition. The pro forma adjustments for interest expense and earnings per unit reflect the net amount of the additional borrowings incurred by the Partnership in June 2011 to initially fund the acquisition that were partially offset by proceeds from common units issued in a public offering completed in July 2011. Supplemental pro forma revenue, net earnings and earnings per unit disclosures are as follows.

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	Three months ended			Nine months ended
	September 30, 2011			September 30, 2011
	(in thousands)
Revenues:
As reported	$	93,564		$	266,195
Pro forma adjustments	—			9,477
Pro forma revenues	$	93,564		$	275,672
Net Income:
As reported	$	9,846		$	25,359
Pro forma adjustments	(26		)	3,076
Pro forma net income	$	9,820		$	28,435
Net income per limited partner unit, diluted:
As reported	$	0.36		$	0.98
Pro forma adjustments	$	(0.01	)	$	0.03
Pro forma net income per limited partner unit	$	0.35		$	1.01

Acquisition of Oil and Gas Mineral Rights

During the year ended December 31, 2011, the Partnership completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. The Partnership began to receive royalty revenues from these mineral rights in early 2012.

The Partnership and an affiliate of Wexford Capital have participated with Gulfport Energy (“Gulfport”), a publicly traded company, to acquire interests in a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately 9.5% of the common stock of Gulfport as of March 13, 2012. During the year ended December 31, 2011, the Partnership completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio, which consisted of a 10.8% interest in approximately 80,000 acres. During the third quarter of 2012, the board of directors of the General Partner approved and the Partnership completed an exchange of its initial 10.8% position for a pro rata interest in 125,000 acres under lease by Gulfport and an affiliate of Wexford Capital. The non-cash transaction was an exchange of the Partnership’s operating interest for the operating interest owned by another party in order to diversify the Partnership’s risk in its oil and gas investment. Thus, the Partnership determined that the non-cash exchange of the Partnership’s ownership interest in the Utica acreage did not result in any gain or loss. Also during the third quarter of 2012, the Partnership’s position was adjusted to a 5% net interest in the 125,000 acres, or approximately 6,250 net acres. As of September 30, 2012, the Partnership had invested approximately $22.8 million for its pro rata interest in the Utica Shale portfolio of oil and gas leases. In addition, per the joint operating agreement completed between the Partnership, Gulfport and an affiliate of Wexford Capital, the Partnership has funded its proportionate share of drilling costs to Gulfport for wells being drilled on the Partnership’s acreage. For the three and nine months ended September 30, 2012, the Partnership has funded approximately $3.2 million of drilling costs that are included in Oil and gas properties in the unaudited condensed consolidated statements of financial position as of September 30, 2012. No revenues have been recognized by the Partnership on its Utica Shale investment for the three and nine months ended September 30, 2012.

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On March 6, 2012, the Partnership completed a lease agreement with a third party for an estimated 1,500 acres that the Partnership previously owned in the Utica Shale region in Harrison County, Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the third party to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay the Partnership the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232 acres. The Partnership is working to resolve title issues on approximately 250 remaining acres to be included in the lease. In addition, the lease agreement stipulates that the third party shall pay the Partnership a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

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

Acquisition of Coal Properties

In May 2012, the Partnership completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for approximately $1.5 million. In addition, the Partnership could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was recorded in the Partnership’s unaudited condensed consolidated statements of financial position as of June 30, 2012 in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount are currently not probable.

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

The coal leases and property are estimated to contain approximately 30 million tons of non-reserve coal deposits that are contiguous to the Green River. The property is undeveloped,

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but fully permitted, and provides the Partnership with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers.

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

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

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

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

	September 30,		December 31,
	2012		2011
	(in thousands)
Other prepaid expenses	$	672	$	577
Prepaid insurance	2,360		1,526
Prepaid leases	150		103
Supply inventory	1,265		1,951
Deposits	321		170
Total Prepaid expenses and other	$	4,768	$	4,327

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5. PROPERTY, PLANT AND EQUIPMENT

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

	Useful Lives	September 30, 2012			December 31, 2011
		(in thousands)
Land and land improvements		$	36,924		$	33,298
Mining and other equipment and related facilities	2 - 20 Years	285,855			244,819
Mine development costs	1 - 15 Years	65,571			65,824
Coal properties	1 - 15 Years	239,140			238,355
Oil and gas properties		31,164			27,964
Construction work in process		17,716			27,303
Total		676,370			637,563
Less accumulated depreciation, depletion and amortization		(209,932		)	(187,447		)
Net		$	466,438		$	450,116

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties, amortization expense for mine development costs, amortization expense for intangible assets and amortization expense for asset retirement costs for the three and nine months ended September 30, 2012 and 2011 were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	7,950	$	6,488	$	24,414	$	19,769
Depletion expense for coal properties	1,440		1,510		4,361		3,358
Amortization expense for mine development costs	526		809		1,650		2,358
Amortization expense for intangible assets	20		12		60		36
Amortization expense for asset retirement costs	129		338		427		992
Total depreciation, depletion and amortization	$	10,065	$	9,157	$	30,912	$	26,513

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Sale of Mining Assets

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

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

Sale of Triad Operations

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

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6. GOODWILL AND INTANGIBLE ASSETS

ASC Topic 350 addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under the provisions of ASC Topic 350, goodwill and other intangible assets with indefinite useful lives are no longer amortized but instead tested for impairment at least annually.

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

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

As discussed in Note 5, the Partnership’s goodwill balance was reduced to zero since it was included in the disposal of the Partnership’s Triad operations that were sold during the third quarter of 2012.

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

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Patent	$	728	$	153	$	575
Developed Technology	78		16		62
Trade Name	184		12		172
Customer List	470		31		439
Total	$	1,460	$	212	$	1,248

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

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

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

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

Amortization expense for the three and nine months ended September 30, 2012 and 2011 is included in the depreciation, depletion and amortization table included in Note 5. The future total amortization expense for each of the five succeeding years related to intangible assets that are currently recorded in the unaudited condensed consolidated statement of financial position is estimated to be as follows at September 30, 2012:

			Developed				Customer
	Patent		Technology		Trade Name		List		Total
	(in thousands)
2012 (from Oct 1 to Dec 31)	$	11	$	1	$	2	$	6	$	20
2013	43		5		9		23		80
2014	43		5		9		23		80
2015	43		5		9		23		80
2016	43		5		9		23		80

7. OTHER NON-CURRENT ASSETS

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

	September 30,		December 31,
	2012		2011
	(in thousands)
Deposits and other	$	2,470	$	2,481
Debt issuance costs—net	4,119		4,925
Deferred expenses	19		27
Total	$	6,608	$	7,433

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Debt issuance costs were approximately $8.0 million as of September 30, 2012 and December 31, 2011. Accumulated amortization of debt issuance costs were approximately $3.9 million and approximately $3.1 million as of September 30, 2012 and December 31, 2011, respectively.

8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

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

	September 30,		December 31,
	2012		2011
	(in thousands)
Payroll, bonus and vacation expense	$	3,992	$	4,128
Non income taxes	4,314		3,950
Royalty expenses	2,860		2,489
Accrued interest	646		797
Health claims	1,538		1,386
Workers’ compensation & pneumoconiosis	1,690		1,690
Deferred revenues	2,490		1,967
Other	2,444		3,284
Total	$	19,974	$	19,691

9. DEBT

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

	September 30,			December 31,
	2012			2011
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$	163,530		$	137,000
Note payable to H&L Construction Co., Inc.	1,745			2,284
Other notes payable	5,189			3,814
Total	170,464			143,098
Less current portion	(2,829		)	(1,334		)
Long-term debt	$	167,635		$	141,764

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Senior Secured Credit Facility with PNC Bank, N.A.—The original maximum availability under the credit facility by and among the Operating Company, the guarantors (including the Partnership) and lenders which are parties thereto, and PNC Bank, N.A. as administrative agent was $200.0 million. On June 8, 2011, with the consent of the lenders, the Operating Company exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn acquisition. As part of exercising this option to increase the available amount under the credit agreement, the Operating Company paid a fee of $1.0 million to the lenders, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position.

On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit. Borrowings under the facility bear interest, which varies depending upon the levels of certain financial ratios. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability that also varies depending upon the levels of certain financial ratios. Borrowings on the amended and restated senior secured credit facility are collateralized by all of the unsecured assets of the Partnership. The amended and restated senior secured credit facility requires the Partnership to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Partnership was in compliance with all covenants contained in the amended and restated senior secured credit facility as of and for the twelve months ended September 30, 2012. The amended and restated senior secured credit facility expires in July 2016.

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

At September 30, 2012, the Operating Company had borrowed $162.0 million at a variable interest rate of LIBOR plus 2.75% (2.98% at September 30, 2012) and an additional $1.5 million at a variable interest rate of PRIME plus 1.75% (5.00% at September 30, 2012). In addition, the Operating Company had outstanding letters of credit of approximately $23.2 million at a fixed interest rate of 2.75% at September 30, 2012. Based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $78.0 million of the borrowing availability at September 30, 2012.

Note payable to H&L Construction Co., Inc.— The note payable to H&L Construction Co., Inc. was originally a non-interest bearing note and the Partnership has recorded a discount

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for imputed interest at a rate of 5.0% on this note that is being amortized over the life of the note using the effective interest method. The note payable matures in January 2015. The note is secured by mineral rights purchased by the Partnership from H&L Construction Co., Inc. with a carrying amount of approximately $11.4 million and approximately $11.6 million at September 30, 2012 and December 31, 2011, respectively.

10. ASSET RETIREMENT OBLIGATIONS

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

	Nine months ended September 30, 2012			Year ended December 31, 2011
	(in thousands)
Balance at beginning of period (including current portion)	$	34,113		$	35,691
Accretion expense	1,305			1,956
Adjustment resulting from addition of property	—			2,707
Adjustment resulting from disposal of property	(271		)	(3,588		)
Adjustments to the liability from annual recosting and other	—			(617		)
Liabilities settled	(1,269		)	(2,036		)
Balance at end of period	33,878			34,113
Current portion of asset retirement obligation	3,409			3,192
Long-term portion of asset retirement obligation	$	30,469		$	30,921

11. EMPLOYEE BENEFITS

In conjunction with the acquisition of the coal operations of American Electric Power on April 16, 2004, the Operating Company acquired a postretirement benefit plan providing healthcare to eligible employees. The Partnership has no other postretirement plans.

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

	Three months ended September 30,					Nine months ended September 30,
	2012			2011		2012			2011
	(in thousands)
Service costs	$	86		$	116	$	291		$	349
Interest cost	52			74		179			222
Amortization of (gain)	(73		)	—		(221		)	—
Total	$	65		$	190	$	249		$	571

401(k) Plans—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Operating Company’s discretion. The expense under these plans for the three and nine months ended September 30, 2012 and 2011 was as follows:

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(in thousands)
401(k) plan expense	$	580	$	583	$	1,743	$	1,652

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12. EQUITY-BASED COMPENSATION

In October 2010, the General Partner established the Rhino Long-Term Incentive Plan (the “Plan” or “LTIP”). The Plan is intended to promote the interests of the Partnership by providing to employees, consultants and directors of the General Partner, the Partnership or affiliates of either incentive compensation awards to encourage superior performance. The LTIP provides for grants of restricted units, unit options, unit appreciation rights, phantom units, unit awards, and other unit-based awards.

As of September 30, 2012, the General Partner granted phantom units to certain employees and restricted units and unit awards to its directors. A portion of these grants were made in connection with the IPO completed during October 2010, as well as annual restricted unit awards to directors and phantom unit awards granted in the first quarter of 2012 to certain employees in connection with fiscal year 2011 performance. A total of 20,664 phantom units were granted in the first quarter of 2012 and these awards vest in equal annual installments over a three year period from the date of grant. The remaining terms and conditions of these phantom unit awards are similar to the phantom units awarded in connection with the Partnership’s IPO. The total fair value of the awards granted in the first quarter of 2012 was approximately $0.4 million at the grant date and the fair value of these awards was approximately $0.3 million as of September 30, 2012. The expense related to these awards will be recognized ratably over the three year vesting period, plus any mark-to-market expense or income, and the amount of expense recognized in the three and nine months ended September 30, 2012 related to these awards was immaterial.

With the vesting of the first portion of the employees’ IPO awards in early April 2011, the Compensation Committee of the board of directors of the General Partner elected to pay some of the awards in cash or a combination of cash and common units. This election was a change in policy since management had previously planned to settle all employee awards with units upon vesting as per the grant agreements. This policy change resulted in a modification of all employee awards from equity to liability classification as of March 31, 2011 and all new awards granted thereafter. For the nine months ended September 30, 2011, the Partnership recorded approximately $0.2 million in incremental compensation expense due to the modification of the employees’ IPO awards. For the three months ended September 30, 2011 and the three and nine months ended September 30, 2012, the Partnership did not record any incremental compensation expense due to the modification of the employees’ IPO awards since the market price of the Partnership’s common units was below the IPO grant price.

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13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of September 30, 2012, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of approximately 1.1 million, 3.6 million, 2.4 million, 0.8 million and 0.3 million tons of coal to 18 customers in 2012, 12 customers in 2013, 7 customer in 2014, 3 customer in 2015, and 1 customer in 2016, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

The Partnership received a notice from one of its major customers in early April 2012 announcing it would be delaying some of its contracted steam coal shipments from the Partnership’s Central Appalachia and Northern Appalachia operations for an undefined period of time due to an over-supply of coal at its locations. This customer resumed purchasing regularly scheduled contracted tons during June and purchased regularly scheduled contracted tons during the third quarter of 2012. The Partnership continues to work with this customer to deliver contracted shipments that were delayed earlier in 2012.

Purchase Commitments—As of September 30, 2012, the Partnership had approximately 1.0 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2012 for approximately $3.5 million.

Purchased Coal Expenses—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts. In addition, the Partnership incurs expense from time to time related to coal purchased on the over-the-counter market (“OTC”). Purchased coal expense from coal purchase contracts and expense from OTC purchases for the three and nine months ended September 30, 2012 and 2011 were as follows:

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(in thousands)
Purchased coal expense	$	7,460	$	1,326	$	17,622	$	6,211
OTC expense	$	—	$	771	$	—	$	785

As of September 30, 2012, the Partnership had an outstanding commitment to purchase approximately 0.1 million tons of coal from a third party for the remainder of 2012 for approximately $7.3 million.

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the three and nine months ended September 30, 2012 and 2011 was as follows:

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	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(in thousands)
Lease expense	$	873	$	607	$	2,136	$	1,924
Royalty expense	$	3,654	$	3,692	$	10,741	$	11,444

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

The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012.  The Partnership made an initial capital contribution of approximately $0.1 million during the nine months ended September 30, 2012 based upon its proportionate ownership interest.

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14. EARNINGS PER UNIT (“EPU”)

The following tables present a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended September 30, 2012 and 2011:

Three months ended September 30, 2012	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	177	$	4,806	$	3,893
Denominator:
Weighted average units used to compute basic EPU	n/a		15,332		12,397
Effect of dilutive securities — LTIP awards	n/a		1		—
Weighted average units used to compute diluted EPU	n/a		15,333		12,397
Net income per limited partner unit, basic	n/a		$	0.31	$	0.31
Net income per limited partner unit, diluted	n/a		$	0.31	$	0.31

Nine months ended September 30, 2012	General Partner		Common Unitholders		Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net income	$	617	$	16,709	$	13,520
Denominator:
Weighted average units used to compute basic EPU	n/a		15,322		12,397
Effect of dilutive securities — LTIP awards	n/a		5		—
Weighted average units used to compute diluted EPU	n/a		15,327		12,397
Net income per limited partner unit, basic	n/a		$	1.09	$	1.09
Net income per limited partner unit, diluted	n/a		$	1.09	$	1.09

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three months ended September 30, 2012, approximately 77,000 LTIP granted phantom units were anti-dilutive. There were no other anti-dilutive units for any other periods presented.

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

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

15. MAJOR CUSTOMERS

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

	September 30,		Nine months		Nine months
	2012		ended		ended
	Receivable		September 30,		September 30,
	Balance		2012 Sales		2011 Sales
	(in thousands)
GenOn Energy, Inc.	$	5,352	$	38,847	$	44,178
Indiana Harbor Coke Company, L.P	4,652		28,806		29,812
PPL Corporation	3,042		30,553		n/a
American Electric Power Company, Inc.	3,271		26,683		34,273

16. FAIR VALUE OF FINANCIAL INSTRUMENTS

The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership’s senior secured credit facility was determined based upon a market approach and approximates the carrying value at September 30, 2012. The fair value of the Partnership’s senior secured credit facility is a Level 2 measurement.

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2012 excludes approximately $2.8 million of property additions, which are recorded in accounts payable, and approximately $0.4 million related to the value of phantom and restricted units that were issued to certain employees and directors of the General Partner.

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The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2012 also excludes $0.4 million related to the amount accrued for the acquisition of the western Kentucky assets discussed in Note 3 and approximately $0.4 million related to a gain recognized on an approved insurance claim for a damaged piece of equipment, which the proceeds had not been received as of September 30, 2012. The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2011 excludes approximately $1.8 million of property additions, which are recorded in accounts payable and approximately $0.5 million related to the value of phantom and restricted units that were issued to certain employees and directors of the General Partner.

18. SEGMENT INFORMATION

The Partnership produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah and also has one underground mine located in Colorado that was temporarily idled. The Partnership sells primarily to electric utilities in the United States. In addition, with the acquisition of Elk Horn, the Partnership also leases coal reserves to third parties in exchange for royalty revenues. For the three and nine months ended September 30, 2012, the Partnership had four reportable segments: Central Appalachia (comprised of both surface and underground mines located in Eastern Kentucky and Southern West Virginia, along with the Elk Horn operations), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Rhino Western (comprised of underground mines in Colorado and Utah) and Eastern Met (comprised solely of the joint venture with Patriot). Additionally, the Partnership has an Other category that is comprised of the Partnership’s ancillary businesses and investments in oil and gas mineral rights. The Partnership has not provided disclosure of total expenditures by segment for long-lived assets, as the Partnership does not maintain discrete financial information concerning segment expenditures for long lived assets, and accordingly such information is not provided to the Partnership’s chief operating decision maker.

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

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Reportable segment results of operations for the three months ended September 30, 2012 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

								Eastern Met
										Equity			Equity
	Central			Northern		Rhino		Complete		Method			Method					Total
	Appalachia			Appalachia		Western		Basis		Eliminations			Presentation		Other			Consolidated
	(in thousands)
Total revenues	$	51,428		$	29,939	$	10,621	$	16,296	$	(16,296	)	$	—	$	1,587		$	93,575
DD&A	6,165			2,189		1,217		508		(508		)	—		494			10,065
Interest expense	1,212			221		201		16		(16		)	—		471			2,105
Net Income (loss)	$	(143	)	$	6,123	$	1,891	$	3,558	$	(1,743	)	$	1,815	$	(810	)	$	8,876

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

								Eastern Met
										Equity			Equity
	Central		Northern		Rhino			Complete		Method			Method					Total
	Appalachia		Appalachia		Western			Basis		Eliminations			Presentation		Other			Consolidated
	(in thousands)
Total revenues	$	53,443	$	32,568	$	6,044		$	14,323	$	(14,323	)	$	—	$	1,509		$	93,564
DD&A	5,550		1,992		857			754		(754		)	—		758			9,157
Interest expense	691		675		201			32		(32		)	—		283			1,850
Net Income (loss)	$	3,904	$	6,313	$	(427	)	$	2,466	$	(1,208	)	$	1,258	$	(1,202	)	$	9,846

Reportable segment results of operations for the nine months ended September 30, 2012 are as follows:

							Eastern Met
									Equity			Equity
	Central		Northern		Rhino		Complete		Method			Method					Total
	Appalachia		Appalachia		Western		Basis		Eliminations			Presentation		Other			Segments
	(in thousands)
Total revenues	$	135,607	$	94,298	$	30,767	$	49,133	$	(49,133	)	$	—	$	4,783		$	265,455
DD&A	19,801		6,154		3,323		1,630		(1,630		)	—		1,634			30,912
Interest expense	3,340		620		546		155		(155		)	—		1,383			5,889
Net Income (loss)	$	812	$	23,199	$	4,750	$	12,312	$	(6,106	)	$	6,206	$	(4,121	)	$	30,846

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

								Eastern Met
										Equity			Equity
	Central		Northern		Rhino			Complete		Method			Method					Total
	Appalachia		Appalachia		Western			Basis		Eliminations			Presentation		Other			Segments
	(in thousands)
Total revenues	$	158,092	$	90,306	$	13,065		$	37,093	$	(37,093	)	$	—	$	4,732		$	266,195
DD&A	15,948		6,177		2,117			2,328		(2,328		)	—		2,271			26,513
Interest expense	1,640		1,429		360			49		(49		)	—		845			4,274
Net Income (loss)	$	10,336	$	18,036	$	(2,327	)	$	6,193	$	(3,035	)	$	3,158	$	(3,844	)	$	25,359

During 2012, the Partnership’s management changed the method that allocates certain corporate overhead and interest charges to the Partnership’s reportable segments from a method based on production tons to a method based upon the amount invested in fixed assets. The Partnership’s management changed the allocation method as a result of additional investments that the Partnership has made in its non-coal operations. Reportable segment figures have not been re-casted for 2011. If the new allocation method had been used for the three months ended September 30, 2011, reportable segment net income would have been reduced by approximately $0.8 million for Central Appalachia and reduced by approximately $0.6 million for the Other category as compared to the reported figures above, and reportable segment net income would have been increased by approximately $1.2 million for Northern Appalachia and increased by approximately $0.2 million for Rhino Western as compared to the reported figures above. If the new allocation method had been used for the nine months ended September 30, 2011, reportable segment net income would have been reduced by approximately $1.4 million for Central Appalachia, reduced by approximately $0.1 million for Rhino Western and reduced by approximately $1.6 million for the Other category as compared to the reported figures above, and reportable segment net income would have been increased by approximately $3.1 million for Northern Appalachia from the reported figures above.

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

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(in thousands)
Total costs and expenses	$	12,733	$	11,825	$	36,676	$	30,851
Income from operations	3,563		2,498		12,457		6,242

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19.  SUBSEQUENT EVENTS

On October 22, 2012, the Partnership announced a cash distribution of $0.445 per common unit, or $1.78 per unit on an annualized basis. This distribution will be paid on November 14, 2012 to all common unit holders of record as of the close of business on November 1, 2012.

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

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or similar terms refer to Rhino Resource Partners LP and its subsidiaries. References to our “general partner” refer to Rhino GP LLC, the general partner of Rhino Resource Partners LP. The following discussion of the historical financial condition and results of operations should be read in conjunction with the historical audited consolidated financial statements and accompanying notes of our Annual Report on Form 10-K for the year ended December 31, 2011 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2011 included in this Annual Report on Form 10-K.

In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from statements we make. See the section “Cautionary Note Regarding Forward- Looking Statements”. In addition, factors that could cause actual results to differ include those risks and uncertainties discussed in Part I, Item 1A. “Risk Factors” also included in our Annual Report on Form 10-K for the year ended December 31, 2011.

Overview

We are a growth oriented Delaware limited partnership formed to control and operate coal properties and invest in other natural resource assets. We produce, process and sell high quality coal of various steam and metallurgical grades. We market our steam coal primarily to electric utility companies as fuel for their steam powered generators. Customers for our metallurgical coal are primarily steel and coke producers who use our coal to produce coke, which is used as a raw material in the steel manufacturing process. In addition to operating coal properties, we manage and lease coal properties and collect royalties from those management and leasing activities. In addition to our coal operations, we have invested in oil and gas mineral rights that began to generate royalty revenues in early 2012.

We have a geographically diverse asset base with coal reserves located in Central Appalachia, Northern Appalachia, the Illinois Basin and the Western Bituminous region. As of December 31, 2011, we controlled an estimated 437.0 million tons of proven and probable coal reserves, consisting of an estimated 415.6 million tons of steam coal and an estimated 21.4 million tons of metallurgical coal. In addition, as of December 31, 2011, we controlled an estimated 417.1 million tons of non-reserve coal deposits. As of December 31, 2011, Rhino Eastern LLC, a joint venture in which we have a 51% membership interest and for which we serve as manager, controlled an estimated 43.4 million tons of proven and probable coal reserves at the Rhino Eastern mining complex located in Central Appalachia, consisting entirely of premium mid-vol and low-vol metallurgical coal, and an estimated 17.9 million tons of non-reserve coal deposits.

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Our principal business strategy is to safely, efficiently and profitably produce, sell and lease both steam and metallurgical coal from our diverse asset base in order to maintain and, over time, increase our quarterly cash distributions. In addition, we intend to expand our operations through strategic acquisitions, including the acquisition of stable, cash generating natural resource assets. We believe that such assets would allow us to grow our cash available for distribution and enhance stability of our cash flow.

During June 2012, we idled a majority of our operations at our Central Appalachia locations in eastern Kentucky and West Virginia to decrease our inventory. The idling of these operations was taken in response to inventory levels that had grown as we experienced continuing weakness in the coal markers that saw customers delaying a portion of their contracted shipments. We resumed operations at a majority of our Central Appalachia locations on July 9, 2012. Our operations at our two surface mines and one underground mine in Ohio as well as our underground mine in Utah continued to operate during the second and third quarters of 2012. In addition, our joint venture continued to operate two underground mines in West Virginia. In addition, we have one underground mine in Colorado that has been temporarily idled. The number of mines that we operate may vary from time to time depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

For the three and nine months ended September 30, 2012, we generated revenues of approximately $93.6 million and approximately $265.5 million, respectively, and net income of approximately $8.9 million and approximately $30.8 million, respectively. Excluding results from the joint venture, for the three and nine months ended September 30, 2012, we produced and sold approximately 1.3 million tons and approximately 3.5 million tons of coal, respectively. For the three and nine months ended September 30, 2012, approximately 89% and 90% of tons sold, respectively, were sold pursuant to supply contracts. Additionally, the joint venture produced and sold approximately 0.1 million tons and 0.3 million tons, respectively, of premium mid-vol metallurgical coal for the three and nine months ended September 30, 2012.

Recent Developments

Patriot Coal Corporation Bankruptcy

We have a 51% equity interest in the Rhino Eastern joint venture, with Patriot Coal Corporation (“Patriot”) owning the remaining membership interest. On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

Joint Venture and Other Investments

In March 2012, we made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf, with affiliates of Wexford Capital. Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio. The initial investment was our proportionate minority ownership share to purchase land for the construction site of the

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condensate river terminal. Timber Wolf had no operating activities during the nine months ended September 30, 2012.

In addition, during the second quarter of 2012 we formed a services company to provide drill pad construction services in the Utica Shale for drilling operators. This services company completed the construction of two drill pads during the third quarter of 2012.

Coal Acquisitions

Acquisition of Coal Property

In May 2012, we completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for approximately $1.5 million. In addition, we could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was recorded in our unaudited condensed consolidated statements of financial position as of June 30, 2012 in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount are currently not probable.

During the three months ended September 30, 2012, we paid $1.6 million of the $2.0 million that was accrued related to the acquisition since the conditions requiring payment had been met. The remaining accrued balance of $0.4 million is recorded in our unaudited condensed consolidated statements of financial position as of September 30, 2012 since the conditions remained probable and estimable.

The coal leases and property are estimated to contain approximately 30 million tons of non-reserve coal deposits that are contiguous to the Green River. The property is undeveloped, but fully permitted, and provides us with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers.

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

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

Acquisition of The Elk Horn Coal Company, LLC

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

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Oil and Gas Investments

During the year ended 2011, we completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. We began to receive royalty revenues from these mineral rights in early 2012.

We and an affiliate of Wexford Capital have participated with Gulfport Energy (“Gulfport”), a publicly traded company, to acquire interests in a portfolio of oil and gas leases in the Utica Shale. As of March 13, 2012, an affiliate of Wexford Capital owned approximately 9.5% of the common stock of Gulfport. During the year ended December 31, 2011, we completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio for a total purchase price of approximately $19.9 million. Gulfport is actively drilling in the Utica acreage and during the third quarter, Gulfport released results from three test wells that had been drilled on our acreage, which we believe are very positive due to the amount of hydrocarbon liquids contained in these wells.

Our initial position in the Utica Shale consisted of a 10.8% interest in approximately 80,000 acres. During the third quarter of 2012, the board of directors of our general partner approved and we completed an exchange of our initial 10.8% position for a pro rata interest in 125,000 acres under lease by Gulfport and an affiliate of Wexford Capital. Also during the third quarter of 2012, our position was adjusted to a 5% net interest in the 125,000 acres, or approximately 6,250 net acres. In addition, per the joint operating agreement completed between us, Gulfport and an affiliate of Wexford Capital, we have funded our proportionate share of drilling costs to Gulfport for wells being drilled on our acreage. For the three and nine months ended September 30, 2012, we funded approximately $3.2 million of drilling costs that are included in Oil and gas properties in our unaudited condensed consolidated statements of financial position as of September 30, 2012. No revenues have been recognized by us on our Utica Shale investment for the three and nine months ended September 30, 2012.

In March 2012, we completed an out-lease agreement with a third party for an estimated 1,500 acres we own in the Utica Shale region of Harrison County Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the lessee to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay us the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232 acres. We are working to resolve title issues on approximately 250 remaining acres to be included in the lease. In addition, the lease agreement stipulates that the third party shall pay us a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

Sale of Triad Operations

In August 2012, we sold the operations and tangible assets of our roof bolt manufacturing company, Triad Roof Support Systems, LLC (“Triad”), to a third party for $0.5 million of cash consideration. As part of the sale, we retained the rights to certain intellectual property and

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entered into an exclusive license and option to purchase agreement for this intellectual property with the same third party for potential additional cash consideration. We have not recorded any portion of this additional consideration since this amount is contingent upon the third party determining the viability of the related intellectual property to their specifications. In connection with this sale, we recorded an approximate $0.2 million gain that is recorded on the (Gain) loss on sale/acquisition of assets—net line of our unaudited condensed consolidated statements of operations and comprehensive income.

Sale of Mining Assets

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

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

Follow-on Offering

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

Credit Facility

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

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Proposed Carbon Emission Rules

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

Factors That Impact Our Business

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

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

Most often our coal is sold through supply contracts and we anticipate that we will continue to do so. As of September 30, 2012, we had commitments under sales contracts to deliver annually scheduled base quantities of approximately 1.1 million, approximately 3.6 million, approximately 2.4 million, approximately 0.8 million and approximately 0.3 million tons of coal to 18 customers in 2012, 12 customers in 2013, 7 customers in 2014, 3 customers in 2015 and 1 customer in 2016, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

We received a notice from one of our major customers in early April 2012 announcing it would be delaying some of its contracted steam coal shipments from our Central Appalachia and Northern Appalachia operations for an undefined period of time due to an over-supply of coal at its locations. This customer resumed purchasing regularly scheduled contracted tons during June and purchased regularly scheduled contracted tons during the third quarter of 2012. We continue to work with this customer to deliver contracted shipments that were delayed earlier in 2012.

Results of Operations

Segment Information

We conduct business through four reportable business segments: Central Appalachia, Northern Appalachia, Eastern Met and Rhino Western. Additionally, we have an Other category that includes our ancillary businesses. Our Central Appalachia segment consists of three mining complexes: Tug River, Rob Fork and Deane, which are located in eastern Kentucky and southern West Virginia. Additionally, our Central Appalachia segment includes the Elk Horn operations. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill

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mining complex, the Leesville field and the Springdale field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of September 30, 2012. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of September 30, 2012. Our Rhino Western segment includes our two underground mines in the Western Bituminous region that consist of our McClane Canyon mine in Colorado that has been temporarily idled since the end of 2010, and remained idle at September 30, 2012, and our Castle Valley mining complex in Utah that began production in January 2011. The Eastern Met segment includes our 51% equity interest in the results of operations of the Rhino Eastern joint venture, which owns the Rhino Eastern mining complex, located in West Virginia, and for which we serve as manager. As of September 30, 2012, this complex was comprised of two underground mines and a preparation plant and loadout facility (owned by our joint venture partner). Our Other category includes our ancillary businesses that consist of limestone operations and various businesses that provide support services such as reclamation, maintenance and transportation, the cost of which is reflected in our cost of operations, and our investments in oil and gas mineral rights. Our Other category included our Triad roof bolt manufacturing operations during 2011 and the portion of 2012 until this operation was sold on August 31, 2012.

Evaluating Our Results of Operations

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

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

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

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

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Summary

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the three and nine months ended September 30, 2012 and 2011:

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(in millions)
Statement of Operations Data:
Total revenues	$	93.6		$	93.6		$	265.5		$	266.2
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	69.4			69.0			186.7			197.5
Freight and handling costs	1.5			1.3			4.6			3.3
Depreciation, depletion and amortization	10.0			9.2			30.9			26.5
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	4.7			6.4			15.1			15.4
(Gain) on sale of assets	(1.2		)	(2.7		)	(2.2		)	(2.8		)
Income from operations	9.2			10.4			30.4			26.3
Interest and other income (expense):
Interest expense	(2.1		)	(1.9		)	(5.9		)	(4.2		)
Interest income	—			—			0.1			0.1
Equity in net income (loss) of unconsolidated affiliate	1.8			1.3			6.2			3.2
Total interest and other income (expense)	(0.3		)	(0.6		)	0.4			(0.9		)
Net income	$	8.9		$	9.8		$	30.8		$	25.4
Other Financial Data
Adjusted EBITDA	$	21.3		$	21.3		$	68.6		$	57.4

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

Summary.  For the three months ended September 30, 2012, our total revenues were relatively flat period to period at $93.6 million as increased sales period to period in our Rhino Western operations were offset by decreases in sales in our Central Appalachia and Northern Appalachia operations. We sold 1.3 million tons of coal for the three months ended September 30, 2012, which is a 4.4% increase compared to the tons of coal sold for the three months ended September 30, 2011. This increase in tons sold compared to the prior year was primarily the result of increased sales from our Castle Valley mine as this operation was producing at a lower capacity in 2011 as it was being brought up to full production compared to being operated at normal capacity in the third quarter of 2012. The increased tons sold and coal revenue from

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Castle Valley year to year were partially offset by continued weak demand in the met and steam coal markets that resulted in lower coal revenues and tons sold for our Central Appalachia and Northern Appalachia segments for the three months ended September 30, 2012 compared to the same period in 2011. We believe the weak demand in the steam coal markets was primarily driven by an unseasonably mild winter along with an over-supply of low priced natural gas, both of which resulted in an increase of coal inventory supplies at electric utilities and fewer tons of steam coal being utilized in electricity generation. We believe the weak demand in the met coal markets was primarily driven by a decrease in world-wide steel production due to economic weakness in China and Europe.

Net income decreased slightly while Adjusted EBITDA was flat for the three months ended September 30, 2012 compared to the three months ended September 30, 2011.  Net income was approximately $8.9 million for the three months ended September 30, 2012 compared to approximately $9.8 million for the three months ended September 30, 2011. Net income was positively impacted period to period due to $1.8 million of income from our Rhino Eastern joint venture for the three months ended September 30, 2012 compared to income of $1.3 million for the three months ended September 30, 2011, which represents our proportionate share of income from the joint venture in which we have a 51% membership interest and for which we serve as manager.

Adjusted EBITDA was flat at $21.3 million for the three months ended September 30, 2012 compared to the three months ended September 30, 2011 as an increase in Adjusted EBITDA at our Rhino Western segment was offset by decreases in our Central Appalachia and Northern Appalachia segments. Adjusted EBITDA was also positively impacted period to period due to the net income impact from our Rhino Eastern joint venture discussed above.

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

	Three months	Three months	Increase/
	ended	ended	(Decrease)
Segment	September 30, 2012	September 30, 2011	Tons		% *
	(in thousands, except %)
Central Appalachia	519.2	558.7	(39.5	)	(7.1	)%
Northern Appalachia	483.0	552.5	(69.5	)	(12.6	)%
Rhino Western	302.1	138.4	163.7		118.3	%
Total *†	1,304.3	1,249.6	54.7		4.4	%

*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.

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We sold approximately 1,304,000 tons of coal for the three months ended September 30, 2012 compared to approximately 1,250,000 tons for the three months ended September 30, 2011. The increase in total tons sold year-to-year was primarily the result of increased sales from our Castle Valley mine as this operation was producing at a lower capacity in 2011 as it was being brought up to full production compared to being operated at normal capacity in the third quarter of 2012. The increase in tons sold from Castle Valley year to year was partially offset by continued weak demand in the met and steam coal markets that resulted in lower tons sold for our Central Appalachia and Northern Appalachia segments for the three months ended September 30, 2012 compared to the same period in 2011. Tons of coal sold in our Central Appalachia segment decreased by approximately 40,000 tons, or 7.1%, to approximately 519,000 tons for the three months ended September 30, 2012 from approximately 559,000 tons for the three months ended September 30, 2011. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the met and steam coal markets. For our Northern Appalachia segment, tons of coal sold decreased by approximately 70,000 tons, or 12.6%, to approximately 483,000 tons for the three months ended September 30, 2012 from approximately 553,000 tons for the three months ended September 30, 2011. The decrease in total tons sold year-to-year in Northern Appalachia was primarily due to weakness in the steam coal markets. Coal sales from our Rhino Western segment increased by approximately 164,000 tons, or 118.3%, for the three months ended September 30, 2012 compared to approximately 138,000 tons for the three months ended September 30, 2011 as our Castle Valley location was still being prepared for full operation in the 2011 period compared to operating at a greater capacity in the 2012 period.

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Revenues.  The following table presents revenues and coal revenues per ton by reportable segment for the three months ended September 30, 2012 and 2011:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	September 30, 2012		September 30, 2011		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	46.6	$	46.4	$	0.2		0.6	%
Freight and handling revenues	—		—		—			n/a
Other revenues	4.8		7.1		(2.3		)	(32.3	)%
Total revenues	$	51.4	$	53.5	$	(2.1	)	(3.8	)%
Coal revenues per ton*	$	89.78	$	82.93	$	6.85		8.3	%
Northern Appalachia
Coal revenues	$	26.7	$	29.6	$	(2.9	)	(9.9	)%
Freight and handling revenues	1.6		1.6		—			4.0	%
Other revenues	1.7		1.4		0.3			17.7	%
Total revenues	$	30.0	$	32.6	$	(2.6	)	(8.1	)%
Coal revenues per ton*	$	55.22	$	53.59	$	1.63		3.0	%
Rhino Western
Coal revenues	$	10.6	$	6.0	$	4.6		75.8	%
Freight and handling revenues	—		—		—			n/a
Other revenues	—		—		—			n/a
Total revenues	$	10.6	$	6.0	$	4.6		75.7	%
Coal revenues per ton*	$	35.15	$	43.65	$	(8.50	)	(19.5	)%
Other
Coal revenues	n/a		n/a		n/a			n/a
Freight and handling revenues	n/a		n/a		n/a			n/a
Other revenues	1.6		1.5		0.1			5.2	%
Total revenues	$	1.6	$	1.5	$	0.1		5.2	%
Coal revenues per ton**	n/a		n/a		n/a			n/a
Total
Coal revenues	$	83.9	$	82.0	$	1.9		2.3	%
Freight and handling revenues	1.6		1.6		—			4.0	%
Other revenues	8.1		10.0		(1.9		)	(19.6	)%
Total revenues	$	93.6	$	93.6	$	(0.0	)	0.0	%
Coal revenues per ton*	$	64.33	$	65.61	$	(1.28	)	(2.0	)%

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

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

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Our coal revenues for the three months ended September 30, 2012 increased by approximately $1.9 million, or 2.3%, to approximately $83.9 million from approximately $82.0 million for the three months ended September 30, 2011. The increase in coal revenues was primarily due to the increase in tons sold at our Castle Valley operation in our Rhino Western segment, partially offset by a decrease in tons sold at our Northern Appalachia operations due to weakness in the steam coal markets. Coal revenues per ton were $64.33 for the three months ended September 30, 2012, a decrease of $1.28, or 2.0%, from $65.61 per ton for the three months ended September 30, 2011. This decrease in coal revenues per ton was primarily the result of a higher mix of lower priced coal from our Rhino Western operations.

For our Central Appalachia segment, coal revenues increased by approximately $0.2 million, or 0.6%, to approximately $46.6 million for the three months ended September 30, 2012 from approximately $46.4 million for the three months ended September 30, 2011 primarily due to decreased met coal production in the third quarter of 2011 as we transitioned from a contract high-wall miner to a newly purchased high-wall miner, which resulted in fewer met coal tons being produced and sold during the three months ended September 30, 2011 compared to the three months ended September 30, 2012. Coal revenues per ton for our Central Appalachia segment increased by $6.85, or 8.3%, to $89.78 per ton for the three months ended September 30, 2012 as compared to $82.93 for the three months ended September 30, 2011, due to a higher mix of metallurgical coal sold for the three months ended September 30, 2012 compared to the three months ended September 30, 2011. Other revenues decreased for our Central Appalachia segment primarily due to lower coal royalty revenue from Elk Horn due to fewer tons produced by Elk Horn’s lessees.

For our Northern Appalachia segment, coal revenues were approximately $26.7 million for the three months ended September 30, 2012, a decrease of approximately $2.9 million, or 9.9%, from approximately $29.6 million for the three months ended September 30, 2011. This decrease was due to weakness in the steam coal market, which resulted in fewer tons sold. Coal revenues per ton for our Northern Appalachia segment increased by $1.63, or 3.0%, to $55.22 per ton for the three months ended September 30, 2012 as compared to $53.59 per ton for the three months ended September 30, 2011. This increase was primarily due to higher contracted prices for steam coal.

For our Rhino Western segment, coal revenues increased by approximately $4.6 million, or 75.8%, to approximately $10.6 million for the three months ended September 30, 2012 from approximately $6.0 million for the three months ended September 30, 2011. The increase in revenue was due to an increase in tons sold for coal produced at our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $35.15 for the three months ended September 30, 2012, a decrease of $8.50, or 19.5%, from $43.65 for the three months ended September 30, 2011. The decrease in coal revenues per ton was due to a decrease in selling prices to our Castle Valley customers.

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Other revenues for our Other category were relatively flat period to period at $1.6 million for the three months ended September 30, 2012 compared to $1.5 million for the three months ended September 30, 2011.

Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal (“met coal”) and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)	Three months ended September 30, 2012		Three months ended September 30, 2011		Increase (Decrease) %*
Met coal tons sold	141.2		111.4		26.8	%
Steam coal tons sold	378.0		447.3		(15.5	)%
Total tons sold †	519.2		558.7		(7.1	)%
Met coal revenue	$	15,991	$	13,579	17.8	%
Steam coal revenue	$	30,622	$	32,758	(6.5	)%
Total coal revenue †	$	46,613	$	46,337	0.6	%
Met coal revenues per ton	$	113.23	$	121.90	(7.1	)%
Steam coal revenues per ton	$	81.02	$	73.23	10.6	%
Total coal revenues per ton †	$	89.78	$	82.93	8.3	%
Met coal tons produced	106.4		112.3		(5.3	)%
Steam coal tons produced	336.6		380.5		(11.5	)%
Total tons produced †	443.0		492.8		(10.1	)%

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

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

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Costs and Expenses.  The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the three months ended September 30, 2012 and 2011:

	Three months		Three months
	ended		ended
Segment	September 30, 2012		September 30, 2011		Increase/(Decrease) $			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	39.0	$	39.2	$	(0.2	)	(0.5	)%
Freight and handling costs	0.1		—		0.1			n/a
Depreciation, depletion and amortization	6.1		5.5		0.6			11.1	%
Selling, general and administrative	4.4		6.1		(1.7		)	(27.9	)%
Cost of operations per ton*	$	75.21	$	70.26	$	4.95		7.0	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	19.2	$	20.6	$	(1.4	)	(7.0	)%
Freight and handling costs	1.4		1.3		0.1			4.1	%
Depreciation, depletion and amortization	2.2		2.0		0.2			9.9	%
Selling, general and administrative	0.1		0.1		—			17.8	%
Cost of operations per ton*	$	39.67	$	37.30	$	2.37		6.4	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	6.8	$	4.7	$	2.1		45.2	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.2		0.9		0.3			41.9	%
Selling, general and administrative	—		—		—			(11.7	)%
Cost of operations per ton*	$	22.45	$	33.76	$	(11.31	)	(33.5	)%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	4.4	$	4.5	$	(0.1	)	(2.0	)%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	0.5		0.8		(0.3		)	(34.8	)%
Selling, general and administrative	0.2		0.2		—			(12.5	)%
Cost of operations per ton**	n/a		n/a		n/a			n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	69.4	$	69.0	$	0.4		0.5	%
Freight and handling costs	1.5		1.3		0.2			14.2	%
Depreciation, depletion and amortization	10.0		9.2		0.8			9.9	%
Selling, general and administrative	4.7		6.4		(1.7		)	(26.7	)%
Cost of operations per ton*	$	53.19	$	55.22	$	(2.03	)	(3.7	)%

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

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

Cost of Operations.  Total cost of operations was $69.4 million for the three months ended September 30, 2012 as compared to $69.0 million for the three months ended September 30, 2011. The slight increase in cost of operations was primarily due to increased production at our Castle Valley operation period to period. Our cost of operations per ton was $53.19 for the three months ended September 30, 2012, a decrease of $2.03, or 3.7%, from the three months ended September 30, 2011. The decrease in the cost of operations on a per ton basis was primarily due to a higher mix of lower cost tons from our Castle Valley mine.

Our cost of operations for the Central Appalachia segment decreased by $0.2 million, or 0.5%, to $39.0 million for the three months ended September 30, 2012 from $39.2 million for the three months ended September 30, 2011. Our cost of operations per ton increased to $75.21 per ton for the three months ended September 30, 2012 from $70.26 per ton for three months ended September 30, 2011. The decrease in total cost of operations was primarily due to decreased production in response to weakness in the met and steam coal markets. Cost of operations per ton increased since a portion of our costs are fixed in nature and these fixed costs were spread over a smaller number of tons sold in the three months ended September 30, 2012.

In our Northern Appalachia segment, our cost of operations decreased by $1.4 million, or 7.0%, to $19.2 million for the three months ended September 30, 2012 from $20.6 million for the three months ended September 30, 2011. The decrease in cost of operations was primarily due to fewer tons produced period to period due to weakness in the steam coal market. Our cost of operations per ton was $39.67 for the three months ended September 30, 2012, an increase of $2.37, or 6.4%, compared to $37.30 for the three months ended September 30, 2011. The increase cost of operations per ton was primarily due to fixed costs being spread over a smaller number of tons sold in the three months ended September 30, 2012.

Our cost of operations for the Rhino Western segment increased by $2.1 million, or 45.2%, to $6.8 million for the three months ended September 30, 2012 from $4.7 million for the three months ended September 30, 2011. Our cost of operations per ton decreased to $22.45 per ton for the three months ended September 30, 2012 from $33.76 per ton for three months ended September 30, 2011. The increase in cost of operations was primarily due to increased production at our Castle Valley mine. Cost of operations per ton decreased primarily due to our Castle Valley mine being at full production in the third quarter of 2012 compared to costs incurred in the third quarter of 2011 associated with preparing our Castle Valley mine to begin production that had a smaller amount of tons sold.

Cost of operations in our Other category decreased slightly by $0.1 million for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.

Freight and Handling.  Total freight and handling cost for the three months ended September 30, 2012 increased by $0.2 million, or 14.2%, to $1.5 million from $1.3 million for the three months ended September 30, 2011. This increase was primarily due to increased coal

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

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization, or DD&A, expense for the three months ended September 30, 2012 was $10.0 million as compared to $9.2 million for the three months ended September 30, 2011.

For the three months ended September 30, 2012, our depreciation cost was $7.9 million as compared to $6.5 million for the three months ended September 30, 2011. This increase is primarily due to an increase in machinery and equipment, including a new high-wall miner purchased in Central Appalachia.

For the three months ended September 30, 2012, our depletion cost was $1.4 million compared to $1.5 million for the three months ended September 30, 2011. This decrease is primarily attributable to fewer tons produced by lessees at our Elk Horn operations.

For the three months ended September 30, 2012, our amortization cost was $0.7 million compared to $1.2 million for the three months ended September 30, 2011. This decrease is primarily attributable to changes in asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative.  Selling, general and administrative, or SG&A, expense for the three months ended September 30, 2012 was $4.7 million as compared to $6.4 million for the three months ended September 30, 2011. This decrease in SG&A expense was primarily due to an decrease in expenditures for legal fees and other professional fees.

Interest Expense.  Interest expense for the three months ended September 30, 2012 was $2.1 million as compared to $1.9 million for the three months ended September 30, 2011, an increase of $0.2 million, or 13.8%. This increase was primarily the result of an increase in the borrowings under our credit facility.

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Eastern Met Supplemental Data.  Operational and financial data for the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager (referred to as the “Eastern Met” segment) is presented below. Our consolidated revenue and costs do not include any portion of the revenue or costs of Rhino Eastern since we account for this operation under the equity method. We only record our proportionate share of net income of Rhino Eastern as a single item in our financial statements, but we believe the presentation of these items for Rhino Eastern provides additional insight into how this operation contributes to our overall performance.

Eastern Met 100% Basis	Three months ended September 30, 2012		Three months ended September 30, 2011		Increase (Decrease) %*
	(In thousands, except per ton data and %)
Coal revenues	$	16,290	$	14,305	13.9	%
Total revenues	$	16,296	$	14,323	13.8	%
Coal revenues per ton*	$	175.72	$	207.17	(15.2	)%
Cost of operations	$	11,056	$	10,320	7.1	%
Cost of operations per ton*	$	119.26	$	149.46	(20.2	)%
Depreciation, depletion and amortization	$	508	$	754	(32.7	)%
Interest expense	$	16	$	32	(50.9	)%
Net income (loss)	$	3,558	$	2,466	44.3	%
Partnership’s portion of net income (loss)	$	1,815	$	1,258	44.3	%
Tons produced	78.1		71.8		8.8	%
Tons sold	92.7		69.1		34.3	%

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

Rhino Eastern’s Eagle #3 mine began production in the third quarter of 2012 while mining was discontinued at the Eagle #2 mine due to adverse conditions in the coal seams at this mine. The increase in tons produced and sold for the three months ended September 30, 2012 compared to 2011 was primarily due to interrupted production at the Eagle #1 mine in the third quarter of 2011 due to an accident that occurred at this mine. The increase in tons sold resulted in increased revenue and net income for the three months ended September 30, 2012 compared to the same period in 2011.

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

	Three months ended			Three months ended			Increase
Segment	September 30, 2012			September 30, 2011			(Decrease)
	(in millions)
Central Appalachia	$	(0.1	)	$	3.9		$	(4.0	)
Northern Appalachia	6.1			6.3			(0.2		)
Rhino Western	1.9			(0.5		)	2.4
Eastern Met *	1.8			1.3			0.5
Other	(0.8		)	(1.2		)	0.4
Total	$	8.9		$	9.8		$	(0.9	)

*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 three months ended September 30, 2012, total net income decreased to approximately $8.9 million compared to approximately $9.8 million the three months ended September 30, 2011. For our Central Appalachia segment, net income decreased to a loss of $0.1 million for the three months ended September 30, 2012, a decrease of $4.0 million as compared to the three months ended September 30, 2011, primarily due weakness in the steam and met coal markets that resulted in fewer tons sold. Net income in our Northern Appalachia segment decreased by $0.2 million to $6.1 million for the three months ended September 30, 2012, from $6.3 million for the three months ended September 30, 2011, primarily due to weakness in the steam coal markets. Net income in our Rhino Western segment increased by $2.4 million to income of $1.9 million for the three months ended September 30, 2012, compared to a loss of $0.5 million for the three months ended September 30, 2011. This increase was primarily the result of increased tons sold at our Castle Valley operation. Our Eastern Met segment recorded net income of $1.8 million for the three months ended September 30, 2012, an increase of $0.5 million from net income of $1.3 million for the three months ended September 30, 2011.  For the Other category, we had a net loss of $0.8 million for the three months ended September 30, 2012 compared to a net loss of $1.2 million for the three months ended September 30, 2011.

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

	Three months ended		Three months ended			Increase
Segment	September 30, 2012		September 30, 2011			(Decrease)
	(in millions)
Central Appalachia	$	7.2	$	10.1		$	(2.9	)
Northern Appalachia	8.5		9.0			(0.5		)
Rhino Western	3.3		0.6			2.7
Eastern Met *	2.1		1.7			0.4
Other	0.2		(0.1		)	0.3
Total	$	21.3	$	21.3		$	—

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

Total Adjusted EBITDA for the three months ended September 30, 2012 was flat at $21.3 million compared to the three months ended September 30, 2011, as an increase in Adjusted EBITDA at our Rhino Western segment was offset by decreases in our Central Appalachia and Northern Appalachia segments. Adjusted EBITDA was also positively impacted period to period due to the net income impact from our Rhino Eastern joint venture. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, DD&A and interest expense are not presented separately for our Eastern Met segment. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA to net income on a segment basis.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Summary.  For the nine months ended September 30, 2012, our total revenues decreased to $265.5 million from $266.2 million for the nine months ended September 30, 2011. We sold 3.5 million tons of coal for the nine months ended September 30, 2012, which is a 2.3% decrease compared to the tons of coal sold for the nine months ended September 30, 2011. This decrease in tons sold was the result of weak demand in the met and steam coal markets, which resulted in lower coal revenues for the nine months ended September 30, 2012 compared to the same period in 2011. We believe the weak demand in the steam coal markets was primarily driven by an unseasonably mild winter along with an over-supply of low priced natural gas, both of which resulted in an increase of coal inventory supplies at electric utilities and fewer tons of steam coal being utilized in electricity generation. We believe the weak demand in the met coal markets was primarily driven by a decrease in world-wide steel production due to economic weakness in China and Europe. Despite lower coal revenues, our total revenues only decreased slightly period

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to period partially due to $7.4 million in total lease bonus payments received in the nine months ended September 30, 2012 for our Utica Shale acreage, which was recorded in Other revenues.

For the nine months ended September 30, 2012, we increased our coal inventories by approximately 0.1 million tons. Our coal inventory increased in the nine months ended September 30, 2012 due to weak demand in the steam and met coal markets.

Net income and Adjusted EBITDA increased for the nine months ended September 30, 2012 from the nine months ended September 30, 2011.  Net income was approximately $30.8 million for the nine months ended September 30, 2012 compared to approximately $25.4 million for the nine months ended September 30, 2011. Net income was positively impacted by the $7.4 million lease bonus payments received in the nine months ended September 30, 2012 related to our Utica Shale acreage, which had relatively immaterial costs associated with the transaction. Net income was also positively impacted period to period due to $6.2 million of income from our Rhino Eastern joint venture for the nine months ended September 30, 2012 compared to income of $3.2 million for the nine months ended September 30, 2011, which represents our proportionate share of income from the joint venture in which we have a 51% membership interest and for which we serve as manager.

Adjusted EBITDA increased to $68.6 million for the nine months ended September 30, 2012 from $57.4 million for the nine months ended September 30, 2011. Adjusted EBITDA increased period to period due to an increase in net income, which was positively impacted by the lease bonus payments of $7.4 million. Adjusted EBITDA was also positively impacted period to period due to the net income impact from our Rhino Eastern joint venture discussed above.

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

	Nine months	Nine months	Increase/
	ended	ended	(Decrease)
Segment	September 30, 2012	September 30, 2011	Tons		% *
	(in thousands, except %)
Central Appalachia	1,284.5	1,708.7	(424.2	)	(24.8	)%
Northern Appalachia	1,406.6	1,555.0	(148.4	)	(9.5	)%
Rhino Western	797.0	308.0	489.0		158.8	%
Total *†	3,488.1	3,571.7	(83.6	)	(2.3	)%

*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.

48

We sold approximately 3,488,000 tons of coal for the nine months ended September 30, 2012 compared to approximately 3,572,000 tons for the nine months ended September 30, 2011. The decrease in total tons sold year-to-year was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia, partially offset by increased sales at our Castle Valley operation in Utah. Tons of coal sold in our Central Appalachia segment decreased by approximately 424,000 tons, or 24.8%, to approximately 1,284,000 tons for the nine months ended September 30, 2012 from approximately 1,709,000 tons for the nine months ended September 30, 2011. The decrease in total tons sold year-to-year in Central Appalachia was primarily due to weakness in the met and steam coal markets. For our Northern Appalachia segment, tons of coal sold decreased by approximately 148,000 tons, or 9.5%, to approximately 1,407,000 tons for the nine months ended September 30, 2012 from approximately 1,555,000 tons for the nine months ended September 30, 2011. The decrease in total tons sold year-to-year in Northern Appalachia was primarily due to weakness in the steam coal markets. Coal sales from our Rhino Western segment increased by approximately 489,000 tons, or 158.8%, for the nine months ended September 30, 2012 compared to approximately 308,000 tons for the nine months ended September 30, 2011 as this operation was still being prepared for full operation in the 2011 period compared to operating at a greater capacity in the 2012 period.

49

Revenues.  The following table presents revenues and coal revenues per ton by reportable segment for the nine months ended September 30, 2012 and 2011:

	Nine months		Nine months
	ended		ended		Increase/(Decrease)
Segment	September 30, 2012		September 30, 2011		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	117.8	$	148.9	$	(31.1	)	(20.9	)%
Freight and handling revenues	—		—		—			n/a
Other revenues	17.8		9.2		8.6			93.7	%
Total revenues	$	135.6	$	158.1	$	(22.5	)	(14.2	)%
Coal revenues per ton*	$	91.69	$	87.14	$	4.55		5.2	%
Northern Appalachia
Coal revenues	$	77.2	$	82.4	$	(5.2	)	(6.4	)%
Freight and handling revenues	4.9		4.1		0.8			19.6	%
Other revenues	12.2		3.8		8.4			224.6	%
Total revenues	$	94.3	$	90.3	$	4.0		4.4	%
Coal revenues per ton*	$	54.85	$	53.00	$	1.85		3.5	%
Rhino Western
Coal revenues	$	30.7	$	13.1	$	17.6		135.5	%
Freight and handling revenues	—		—		—			n/a
Other revenues	0.1		—		0.1			81.8	%
Total revenues	$	30.8	$	13.1	$	17.7		135.5	%
Coal revenues per ton*	$	38.58	$	42.38	$	(3.80	)	(9.0	)%
Other
Coal revenues	n/a		n/a		n/a			n/a
Freight and handling revenues	n/a		n/a		n/a			n/a
Other revenues	4.8		4.7		0.1			1.1	%
Total revenues	$	4.8	$	4.7	$	0.1		1.1	%
Coal revenues per ton**	n/a		n/a		n/a			n/a
Total
Coal revenues	$	225.7	$	244.4	$	(18.7	)	(7.6	)%
Freight and handling revenues	4.9		4.1		0.8			19.6	%
Other revenues	34.9		17.7		17.2			96.8	%
Total revenues	$	265.5	$	266.2	$	(0.7	)	(0.3	)%
Coal revenues per ton*	$	64.70	$	68.42	$	(3.72	)	(5.4	)%

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

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

50

Our coal revenues for the nine months ended September 30, 2012 decreased by approximately $18.7 million, or 7.6%, to approximately $225.7 million from approximately $244.4 million for the nine months ended September 30, 2011. The decrease in coal revenues was primarily due to weakness in the met and steam coal markets, primarily in Central Appalachia. Coal revenues per ton were $64.70 for the nine months ended September 30, 2012, a decrease of $3.72, or 5.4%, from $68.42 per ton for the nine months ended September 30, 2011. This decrease in coal revenues per ton was primarily the result of a higher mix of lower priced coal from our Rhino Western operations.

For our Central Appalachia segment, coal revenues decreased by approximately $31.1 million, or 20.9%, to approximately $117.8 million for the nine months ended September 30, 2012 from approximately $148.9 million for the nine months ended September 30, 2011 primarily due to weakness in the met and steam coal markets, which resulted in fewer tons sold. Coal revenues per ton for our Central Appalachia segment increased by $4.55, or 5.2%, to $91.69 per ton for the nine months ended September 30, 2012 as compared to $87.14 for the nine months ended September 30, 2011, due to higher contracted prices, primarily related to metallurgical coal sold. Other revenues increased for our Central Appalachia segment primarily due to coal royalty revenue from Elk Horn, which was not included in our results in the first six months of 2011 since we purchased Elk Horn in June 2011.

For our Northern Appalachia segment, coal revenues were approximately $77.2 million for the nine months ended September 30, 2012, a decrease of approximately $5.2 million, or 6.4%, from approximately $82.4 million for the nine months ended September 30, 2011. This decrease was due to weakness in the steam coal market, which resulted in fewer tons sold. Coal revenues per ton for our Northern Appalachia segment increased by $1.85, or 3.5%, to $54.85 per ton for the nine months ended September 30, 2012 as compared to $53.00 per ton for the nine months ended September 30, 2011. This increase was primarily due to higher contracted prices for steam coal. Other revenues increased for our Northern Appalachia segment primarily due to the $7.4 million lease bonus received for acreage owned in the Utica Shale region.

For our Rhino Western segment, coal revenues increased by approximately $17.6 million, or 135.5%, to approximately $30.7 million for the nine months ended September 30, 2012 from approximately $13.1 million for the nine months ended September 30, 2011. The increase in revenue was due to an increase in tons sold for coal produced at our Castle Valley mine. Coal revenues per ton for our Rhino Western segment were $38.58 for the nine months ended September 30, 2012, a decrease of $3.80, or 9.0%, from $42.38 for the nine months ended September 30, 2011. The decrease in coal revenues per ton was due to lower selling prices to customers for coal produced at our Castle Valley mine.

Other revenues for our Other category were relatively flat period to period with approximately $4.8 million for the nine months ended September 30, 2012 compared to approximately $4.7 million for the nine months ended September 30, 2011.

51

Central Appalachia Overview of Results by Product. Additional information for the Central Appalachia segment detailing the types of coal produced and sold, premium high-vol metallurgical coal (“met coal”) and steam coal, is presented below. Note that our Northern Appalachia and Rhino Western segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)	Nine months ended September 30, 2012		Nine months ended September 30, 2011		Increase (Decrease) %*
Met coal tons sold	345.4		481.0		(28.2	)%
Steam coal tons sold	939.1		1,227.8		(23.5	)%
Total tons sold †	1,284.5		1,708.8		(24.8	)%
Met coal revenue	$	44,276	$	57,744	(23.3	)%
Steam coal revenue	$	73,508	$	91,148	(19.4	)%
Total coal revenue †	$	117,784	$	148,892	(20.9	)%
Met coal revenues per ton	$	128.17	$	120.05	6.8	%
Steam coal revenues per ton	$	78.28	$	74.24	5.4	%
Total coal revenues per ton †	$	91.69	$	87.14	5.2	%
Met coal tons produced	389.6		472.9		(17.6	)%
Steam coal tons produced	951.7		1,147.0		(17.0	)%
Total tons produced †	1,341.3		1,619.9		(17.2	)%

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

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

52

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, 2012 and 2011:

	Nine months		Nine months
	ended		ended
Segment	September 30, 2012		September 30, 2011		Increase/(Decrease) $			%*
	(in millions, except per ton data and %)
Central Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	93.9	$	115.8	$	(21.9	)	(18.9	)%
Freight and handling costs	0.4		—		0.4			n/a
Depreciation, depletion and amortization	19.8		15.9		3.9			24.2	%
Selling, general and administrative	14.0		14.2		(0.2		)	(1.1	)%
Cost of operations per ton*	$	73.11	$	67.79	$	5.32		7.9	%
Northern Appalachia
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	57.7	$	56.3	$	1.4		2.5	%
Freight and handling costs	4.2		3.3		0.9			26.9	%
Depreciation, depletion and amortization	6.2		6.2		—			(0.4	)%
Selling, general and administrative	0.2		0.2		—			6.2	%
Cost of operations per ton*	$	40.99	$	36.19	$	4.80		13.3	%
Rhino Western
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	20.6	$	11.1	$	9.5		84.6	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	3.3		2.1		1.2			57.0	%
Selling, general and administrative	0.1		0.1		—			1.5	%
Cost of operations per ton*	$	25.78	$	36.14	$	(10.36	)	(28.7	)%
Other
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	14.5	$	14.3	$	0.2		2.0	%
Freight and handling costs	—		—		—			n/a
Depreciation, depletion and amortization	1.6		2.3		(0.7		)	(28.1	)%
Selling, general and administrative	0.8		0.9		(0.1		)	(18.5	)%
Cost of operations per ton**	n/a		n/a		n/a			n/a
Total
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	186.7	$	197.5	$	(10.8	)	(5.5	)%
Freight and handling costs	4.6		3.3		1.3			40.1	%
Depreciation, depletion and amortization	30.9		26.5		4.4			16.6	%
Selling, general and administrative	15.1		15.4		(0.3		)	(2.0	)%
Cost of operations per ton*	$	53.51	$	55.29	$	(1.78	)	(3.2	)%

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

53

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

Cost of Operations.  Total cost of operations was $186.7 million for the nine months ended September 30, 2012 as compared to $197.5 million for the nine months ended September 30, 2011. The decrease in the cost of operations was primarily due to decreased production due to weakness in the met and steam coal markets, including the idling of a majority of our Central Appalachia operations in June 2012. Our cost of operations per ton was $53.51 for the nine months ended September 30, 2012, a decrease of $1.78, or 3.2%, from the nine months ended September 30, 2011. The decrease in the cost of operations on a per ton basis was primarily due to a higher mix of lower cost tons from our Castle Valley mine.

Our cost of operations for the Central Appalachia segment decreased by $21.9 million, or 18.9%, to $93.9 million for the nine months ended September 30, 2012 from $115.8 million for the nine months ended September 30, 2011. Our cost of operations per ton increased to $73.11 per ton for the nine months ended September 30, 2012 from $67.79 per ton for nine months ended September 30, 2011. The decrease in total cost of operations was primarily due to decreased production in response to weakness in the met and steam coal markets, including the temporary idling of a majority of our Central Appalachia operations during the month of June 2012. Cost of operations per ton increased since a portion of our costs are fixed in nature and these fixed costs were spread over a smaller number of tons sold in the nine months ended September 30, 2012.

In our Northern Appalachia segment, our cost of operations increased by $1.4 million, or 2.5%, to $57.7 million for the nine months ended September 30, 2012 from $56.3 million for the nine months ended September 30, 2011. Our cost of operations per ton was $40.99 for the nine months ended September 30, 2012, an increase of $4.80, or 13.3%, compared to $36.19 for the nine months ended September 30, 2011. The increases in cost of operations and cost of operations per ton were primarily due to geology issues of mining thinner coal seams at our Hopedale mine and an equipment issue that resulted in the need to replace a mining shovel at one of our Sands Hill surface mines in the second quarter of 2012.

Our cost of operations for the Rhino Western segment increased by $9.5 million, or 84.6%, to $20.6 million for the nine months ended September 30, 2012 from $11.1 million for the nine months ended September 30, 2011. Our cost of operations per ton decreased to $25.78 per ton for the nine months ended September 30, 2012 from $36.14 per ton for nine months ended September 30, 2011. The increase in cost of operations was primarily due to increased production at our Castle Valley mine. Cost of operations per ton decreased primarily due to our Castle Valley mine being at full production in 2012 compared to costs incurred in the first nine months of 2011 associated with preparing our Castle Valley mine to begin production that had a small amount of tons sold.

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

54

Freight and Handling.  Total freight and handling cost for the nine months ended September 30, 2012 increased by $1.3 million, or 40.1%, to $4.6 million from $3.3 million for the nine months ended September 30, 2011. This increase was primarily due to an increase in the tons of limestone sold for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011, along with increased coal freight and handling costs in Central Appalachia due to a new customer contract that required coal to be trucked to the customer’s location.

Depreciation, Depletion and Amortization.  Total depreciation, depletion and amortization, or DD&A, expense for the nine months ended September 30, 2012 was $30.9 million as compared to $26.5 million for the nine months ended September 30, 2011.

For the nine months ended September 30, 2012, our depreciation cost was $24.4 million as compared to $19.8 million for the nine months ended September 30, 2011. This increase is primarily due to an increase in machinery and equipment, including a new high-wall miner purchased in Central Appalachia.

For the nine months ended September 30, 2012, our depletion cost was $4.4 million compared to $3.3 million for the nine months ended September 30, 2011. This increase is primarily attributable to depletion expense incurred at our Elk Horn operations that was not present in the entire 2011 comparable period since Elk Horn was acquired in June 2011.

For the nine months ended September 30, 2012, our amortization cost was $2.1 million as compared to $3.4 million for the nine months ended September 30, 2011. This decrease is primarily attributable to changes in asset retirement costs based on revisions to reserve valuations and useful lives.

Selling, General and Administrative.  Selling, general and administrative, or SG&A, expense for the nine months ended September 30, 2012 was $15.1 million as compared to $15.4 million for the nine months ended September 30, 2011. This decrease in SG&A expense was primarily due to a decrease in expenditures for legal fees and other professional fees, primarily in the third quarter of 2012 compared to 2011.

Interest Expense.  Interest expense for the nine months ended September 30, 2012 was $5.9 million as compared to $4.2 million for the nine months ended September 30, 2011, an increase of $1.7 million, or 37.8%. This increase was primarily the result of an increase in the borrowings under our credit facility.

55

Eastern Met Supplemental Data.  Operational and financial data for the Rhino Eastern joint venture in which we have a 51% membership interest and for which we serve as manager (referred to as the “Eastern Met” segment) is presented below. Our consolidated revenue and costs do not include any portion of the revenue or costs of Rhino Eastern since we account for this operation under the equity method. We only record our proportionate share of net income of Rhino Eastern as a single item in our financial statements, but we believe the presentation of these items for Rhino Eastern provides additional insight into how this operation contributes to our overall performance.

Eastern Met 100% Basis	Nine months ended September 30, 2012		Nine months ended September 30, 2011		Increase (Decrease) %*
	(In thousands, except per ton data and %)
Coal revenues	$	49,100	$	37,046	32.5	%
Total revenues	$	49,133	$	37,093	32.5	%
Coal revenues per ton*	$	186.08	$	198.70	(6.4	)%
Cost of operations	$	31,612	$	26,501	19.3	%
Cost of operations per ton*	$	119.80	$	142.14	(15.7	)%
Depreciation, depletion and amortization	$	1,630	$	2,328	(30.0	)%
Interest expense	$	155	$	49	214.5	%
Net income (loss)	$	12,312	$	6,193	98.8	%
Partnership’s portion of net income (loss)	$	6,206	$	3,158	96.5	%
Tons produced	282.7		189.1		49.5	%
Tons sold	263.9		186.4		41.5	%

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

Rhino Eastern’s Eagle #2 mine began production in the third quarter of 2011, which was replaced by Rhino Eastern’s Eagle #3 mine that began production in the third quarter of 2012 due to adverse conditions in the coal seams at the Eagle #2 mine. The year-to-date operation of the Eagle #2 mine through a portion of the third quarter of 2012 resulted in an increase in tons produced and sold for the nine months ended September 30, 2012 compared to 2011. The increase in tons sold resulted in increased revenue and net income for the nine months ended September 30, 2012 compared to the same period in 2011.

56

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

	Nine months Ended			Nine months Ended			Increase
Segment	September 30, 2012			September 30, 2011			(Decrease)
	(in millions)
Central Appalachia	$	0.8		$	10.3		$	(9.5	)
Northern Appalachia	23.2			18.0			5.2
Rhino Western	4.7			(2.3		)	7.0
Eastern Met *	6.2			3.2			3.0
Other	(4.1		)	(3.8		)	(0.3		)
Total	$	30.8		$	25.4		$	5.4

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

For the nine months ended September 30, 2012, total net income increased to approximately $30.8 million compared to approximately $25.4 million the nine months ended September 30, 2011. Net income was positively impacted by $7.4 million received as a lease bonus payment in the nine months ended September 30, 2012 related to acreage we own in the Utica Shale region of eastern Ohio, which was recorded in Other revenue and had relatively immaterial costs associated with the transaction. For our Central Appalachia segment, net income decreased to $0.8 million for the nine months ended September 30, 2012, a decrease of $9.5 million as compared to the nine months ended September 30, 2011, primarily due weakness in the steam and met coal markets that resulted in fewer tons sold. Net income in our Northern Appalachia segment increased by $5.2 million to $23.2 million for the nine months ended September 30, 2012, from $18.0 million for the nine months ended September 30, 2011. This increase was primarily the result of the $7.4 million lease bonus payment partially offset by a decrease in tons of coal sold due to weakness in the steam coal markets. Net income in our Rhino Western segment increased by $7.0 million to income of $4.7 million for the nine months ended September 30, 2012, compared to a loss of $2.3 million for the nine months ended September 30, 2011. This increase was primarily the result of increased tons sold at our Castle Valley operation. Our Eastern Met segment recorded net income of $6.2 million for the nine months ended September 30, 2012, an increase of $3.0 million from net income of $3.2 million for the nine months ended September 30, 2011.  For the Other category, we had a net loss of $4.1 million for the nine months ended September 30, 2012, as compared to a net loss of $3.8 million for the nine months ended September 30, 2011.

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

	Nine months Ended			Nine months Ended			Increase
Segment	September 30, 2012			September 30, 2011			(Decrease)
	(in millions)
Central Appalachia	$	24.0		$	27.8		$	(3.8	)
Northern Appalachia	30.0			25.6			4.4
Rhino Western	8.6			0.2			8.4
Eastern Met *	7.1			4.5			2.6
Other	(1.1		)	(0.7		)	(0.4		)
Total	$	68.6		$	57.4		$	11.2

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

Total Adjusted EBITDA for the nine months ended September 30, 2012 was $68.6 million, an increase of $11.2 million from the nine months ended September 30, 2011. Adjusted EBITDA increased as a result of an increase in net income, which was positively impacted by the lease bonus payment of $7.4 million. Results of operations from our Eastern Met segment are recorded using the equity method and are reflected as a single line item in our financial statements. Therefore, DD&A and interest expense are not presented separately for our Eastern Met segment. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA to net income on a segment basis.

Reconciliations of Adjusted EBITDA

The following tables present reconciliations of Adjusted EBITDA to the most directly comparable GAAP financial measures for each of the periods indicated:

	Central			Northern		Rhino		Eastern
Three months ended September 30, 2012	Appalachia			Appalachia		Western		Met *		Other			Total
	(in millions)
Net income	$	(0.1	)	$	6.1	$	1.9	$	1.8	$	(0.8	)	$	8.9
Plus:
DD&A	6.1			2.2		1.2		—		0.5			10.0
Interest expense	1.2			0.2		0.2		—		0.5			2.1
EBITDA†	$	7.2		$	8.5	$	3.3	$	1.8	$	0.2		$	21.0
Plus: Rhino Eastern DD&A-51%	—			—		—		0.3		—			0.3
Plus: Rhino Eastern interest expense-51%	—			—		—		—		—			—
Adjusted EBITDA†	$	7.2		$	8.5	$	3.3	$	2.1	$	0.2		$	21.3

58

	Central		Northern		Rhino			Eastern
Three months ended September 30, 2011	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	3.9	$	6.3	$	(0.5	)	$	1.3	$	(1.2	)	$	9.8
Plus:
DD&A	5.5		2.0		0.9			—		0.8			9.2
Interest expense	0.7		0.7		0.2			—		0.3			1.9
EBITDA†	$	10.1	$	9.0	$	0.6		$	1.3	$	(0.1	)	$	20.9
Plus: Rhino Eastern DD&A-51%	—		—		—			0.4		—			0.4
Plus: Rhino Eastern interest expense-51%	—		—		—			—		—			—
Adjusted EBITDA†	$	10.1	$	9.0	$	0.6		$	1.7	$	(0.1	)	$	21.3

	Central		Northern		Rhino		Eastern
Nine months ended September 30, 2012	Appalachia		Appalachia		Western		Met *		Other			Total**
	(in millions)
Net income	$	0.8	$	23.2	$	4.7	$	6.2	$	(4.1	)	$	30.8
Plus:
DD&A	19.8		6.2		3.3		—		1.6			30.9
Interest expense	3.4		0.6		0.6		—		1.4			5.9
EBITDA†	$	24.0	$	30.0	$	8.6	$	6.2	$	(1.1	)	$	67.7
Plus: Rhino Eastern DD&A-51%	—		—		—		0.8		—			0.8
Plus: Rhino Eastern interest expense-51%	—		—		—		0.1		—			0.1
Adjusted EBITDA†	$	24.0	$	30.0	$	8.6	$	7.1	$	(1.1	)	$	68.6

	Central		Northern		Rhino			Eastern
Nine months ended September 30, 2011	Appalachia		Appalachia		Western			Met *		Other			Total
	(in millions)
Net income	$	10.3	$	18.0	$	(2.3	)	$	3.2	$	(3.8	)	$	25.4
Plus:
DD&A	15.9		6.2		2.1			—		2.3			26.5
Interest expense	1.6		1.4		0.4			—		0.8			4.2
EBITDA†	$	27.8	$	25.6	$	0.2		$	3.2	$	(0.7	)	$	56.1
Plus: Rhino Eastern DD&A-51%	—		—		—			1.2		—			1.2
Plus: Rhino Eastern interest expense-51%	—		—		—			0.1		—			0.1
Adjusted EBITDA†	$	27.8	$	25.6	$	0.2		$	4.5	$	(0.7	)	$	57.4

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

**Totals may not foot due to rounding.

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

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	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(in millions)
Net cash provided by operating activities	$	24.7	$	17.3	$	58.0	$	51.3
Plus:
Increase in net operating assets	—		—		0.9		—
Gain on sale of assets	0.8		2.7		1.8		2.8
Amortization of deferred revenue	0.3		0.4		0.9		0.4
Amortization of actuarial gain	0.1		—		0.2		—
Interest expense	2.1		1.9		5.9		4.2
Equity in net income of unconsolidated affiliate	1.8		1.3		6.2		3.2
Less:
Decrease in net operating assets	7.7		1.5		—		1.8
Accretion on interest-free debt	0.1		—		0.2		0.1
Amortization of advance royalties	—		0.2		0.1		0.9
Amortization of debt issuance costs	0.3		0.3		0.8		0.8
Equity-based compensation	0.2		0.2		0.7		0.6
Loss on sale of assets	—		—		—		—
Loss on retirement of advance royalties	0.1		—		0.1		0.1
Accretion on asset retirement obligations	0.4		0.5		1.3		1.5
Distributions from unconsolidated affiliate	—		—		3.0		—
Equity in net loss of unconsolidated affiliate	—		—		—		—
EBITDA†	$	21.0	$	20.9	$	67.7	$	56.1
Plus: Rhino Eastern DD&A-51%	0.3		0.4		0.8		1.2
Plus: Rhino Eastern interest expense-51%	—		—		0.1		0.1
Adjusted EBITDA†	$	21.3	$	21.3	$	68.6	$	57.4

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

Liquidity and Capital Resources

Liquidity

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

The principal indicators of our liquidity are our cash on hand and availability under our credit agreement. Our maximum borrowing capacity under our credit agreement is three times a trailing twelve-month EBITDA calculation, as defined in the credit agreement. As of September 30, 2012, our available liquidity was $78.5 million, including cash on hand of $0.5 million and $78.0 million available under our credit agreement.

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

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Cash Flows

Net cash provided by operating activities was $58.0 million for the nine months ended September 30, 2012 as compared to $51.3 million for the nine months ended September 30, 2011. Net cash provided by operating activities for the nine months ended September 30, 2012 was positively impacted by the $7.4 million lease bonus received for our Utica acreage. This benefit was partially offset by an unfavorable change in inventories that resulted from an increase in coal inventories in the nine months ended September 30, 2012 due to weakness in the coal markets.

Net cash used in investing activities was $50.8 million for the nine months ended September 30, 2012 as compared to $160.7 million for the nine months ended September 30, 2011. Net cash used in investing activities for the nine months ended September 30, 2011 included $119.3 million paid for the Elk Horn acquisition completed in June 2011. Net cash used in investing activities for the nine months ended September 30, 2012 included increased amounts expended for the purchase of mining equipment and other asset acquisitions compared to the same period in 2011, primarily related to the new preparation plant in our Tug River mining complex. However, total capital expenditures for the nine months ended September 30, 2012 was approximately $11.3 million less than the same period in 2011 primarily due to the purchase of oil and gas mineral rights in the Utica and Cana Woodford regions completed in 2011. In addition, net cash used in investing activities for the nine months ended September 30, 2011 included $20.0 million of proceeds from the sale of certain mining assets completed in the third quarter of 2011.

Net cash used in financing activities for the nine months ended September 30, 2012 was $7.2 million, which was primarily attributable to our distributions to unitholders in the nine months ended September 30, 2012, partially offset by borrowings under our credit agreement. Net cash provided by financing activities for the nine months ended September 30, 2011 was $109.6 million, which were primarily attributable to borrowings under our credit agreement and our follow-on offering of common units in July 2011 that were used to fund the Elk Horn acquisition, partially offset by our distributions to unitholders in 2011.

Capital Expenditures

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

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Actual maintenance capital expenditures for the nine months ended September 30, 2012 were approximately $14.3 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the nine months ended September 30, 2012 were approximately $39.0 million, which were primarily related to the new preparation plant in our Tug River mining complex. The remaining amount was primarily spent on our internal development projects.

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

Credit Agreement

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

On July 29, 2011, we executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of participating lenders. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit.

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

Our credit agreement requires us to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. As of and for the twelve months ended September 30, 2012, we were in compliance with respect to all covenants contained in the credit agreement. The credit agreement expires in July 2016.

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At September 30, 2012, we had borrowed $162.0 million at a variable interest rate of LIBOR plus 2.75% (2.98% at September 30, 2012) and an additional $1.5 million at a variable interest rate of PRIME plus 1.75% (5.00% at September 30, 2012). In addition, we had outstanding letters of credit of approximately $23.2 million at a fixed interest rate of 2.75% at September 30, 2012. Based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), we had not used $78.0 million of the borrowing availability at September 30, 2012. During the three months ended September 30, 2012, we had average borrowings outstanding of approximately $167.1 million in relation to this credit agreement.

Off-Balance Sheet Arrangements

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

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

As of September 30, 2012, we had $23.2 million in letters of credit outstanding, of which $18.2 million served as collateral for surety bonds.

Critical Accounting Policies and Estimates

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

The accounting policies and estimates that we have adopted and followed in the preparation of our consolidated financial statements are fully described in our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no significant changes in these policies and estimates as of September 30, 2012.

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Recent Accounting Pronouncements

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

In June 2011, the FASB published ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income”. Under the amendments in this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In a single continuous statement, the entity is required to present the components of net income and total net income, the components of other comprehensive income and a total for other comprehensive income, along with the total of comprehensive income in that statement. In the two-statement approach, an entity is required to present components of net income and total net income in the statement of net income. The statement of other comprehensive income should immediately follow the statement of net income and include the components of other comprehensive income and a total for other comprehensive income, along with a total for comprehensive income. Regardless of whether an entity chooses to present comprehensive income in a single continuous statement or in two separate but consecutive statements, the entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. The amendments in this ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments do not change the option for an entity to present components of other comprehensive income either net of related tax effects or before related tax effects, with one amount shown for the aggregate income tax

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expense or benefit related to the total of other comprehensive income items. In both cases, the tax effect for each component must be disclosed in the notes to the financial statements or presented in the statement in which other comprehensive income is presented. The amendments do not affect how earnings per share is calculated or presented. For public entities, the amendments of this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

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

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

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

Some of the products used in our mining activities, such as diesel fuel, explosives and steel products for roof support used in our underground mining, are subject to price volatility. Through our suppliers, we utilize forward purchases to manage the exposure related to this volatility. A hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income by $0.1 million for the three months ended September 30, 2012 and would have reduced net income by $0.5 million for the nine months ended September 30, 2012. A hypothetical increase of 10% in steel prices would have reduced net income by $0.2 million for the three months ended September 30, 2012 and would have reduced net income by $0.9 million for the nine months ended September 30, 2012. A hypothetical increase of 10% in explosives prices

65

would have reduced net income by $0.2 million for the three months ended September 30, 2012 and would have reduced net income by $0.5 million for the nine months ended September 30, 2012.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our credit agreement. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by $0.4 million for the three months ended September 30, 2012 and would have changed our interest expense by $1.2 million for the nine months ended September 30, 2012.

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, 2012 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting.  There was no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2012, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1.    Legal Proceedings.

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

Item 1A.  Risk Factors.

In addition to the other information set forth in this Report, you should carefully consider the risks under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011, which risks could materially affect our business, financial condition or future results. There has been no material change in our risk factors from those described in the Annual Report on Form 10-K for the year ended December 31, 2011. These risks are not the only risks that we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

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

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

Item 3.    Defaults upon Senior Securities.

None.

Item 4.    Mine Safety Disclosure

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the three months ended September 30, 2012 is included in Exhibit 95.1 to this report.

Item 5.    Other Information.

None.

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Item 6.    Exhibits.

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Rhino Resource Partners LP, incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-166550) filed on May 5, 2010
3.2	Second Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated as of October 26, 2010, incorporated by reference to Exhibit 3.1 to the  Current Report on Form 8-K (File No. 001-34892) filed on November 1, 2010
4.1	Registration Rights Agreement, dated as of October 5, 2010, by and between Rhino Resource Partners LP and Rhino Energy Holdings LLC, incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on October 8, 2010
10.1	Amended and Restated Employment Agreement of Christopher I. Walton dated April 2, 2012, incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-34892) filed on August 9, 2012
10.2*	Model Form Operating Agreement dated May 6, 2011 by and between Rhino Exploration, Gulfport Energy Corporation, and Windsor Ohio LLC
31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)
32.1*	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
32.2*	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)
95.1*	Mine Health and Safety Disclosure pursuant to §1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act for the three months ended September 30, 2012
101.INS§	XBRL Instance Document
101.SCH§	XBRL Taxonomy Extension Schema Document
101.CAL§	XBRL Taxonomy Extension Calculation Linkbase Document

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Exhibit Number	Description
101.DEF§	XBRL Taxonomy Definition Linkbase Document
101.LAB§	XBRL Taxonomy Extension Label Linkbase Document
101.PRE§	XBRL Taxonomy Extension Presentation Linkbase Document

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

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

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SIGNATURES

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

	RHINO RESOURCE PARTNERS LP
	By: Rhino GP LLC, its General Partner
Date: November 9, 2012	By:	/s/ David G. Zatezalo
		David G. Zatezalo
		President and Chief Executive Officer
		(Principal Executive Officer)
Date: November 9, 2012	By:	/s/ Richard A. Boone
		Richard A. Boone
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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EX-10.2

Exhibit 10.2

EXHIBIT “C”

Attached to and made part of that certain Development Agreement, dated effective May 6, 2011 by and between Gulfport Energy Corporation, Windsor Ohio, LLC and Rhino Exploration, LLC

A.A.P.L. FORM 610-1982

MODEL FORM OPERATING AGREEMENT

OPERATING AGREEMENT

DATED

May 6, 2011,

year

OPERATOR Gulfport Energy Corporation

CONTRACT AREA See Exhibit “A”

COUNTY OR PARISH OF	Belmont, Carroll, Columbiana, Guernsey, Harrison, Jefferson, Mahoning, Monroe, Noble, Portage, Stark, Summit and Tuscarawas	STATE OF	Ohio
	COPYRIGHT 1982 — ALL RIGHTS RESERVED AMERICAN ASSOCIATION OF PETROLEUM LANDMEN, 4100 FOSSIL CREEK BLVD., FORT WORTH, TEXAS, 76137-2791, APPROVED FORM. A.A.P.L. NO. 610 — 1982 REVISED

TABLE OF CONTENTS

Article	Title			Page
I.	DEFINITIONS			1
II.	EXHIBITS			1
III.	INTERESTS OF PARTIES			2
	A.	OIL AND GAS INTERESTS		2
	B.	INTERESTS OF PARTIES IN COSTS AND PRODUCTION		2
	C.	EXCESS ROYALTIES, OVERRIDING ROYALTIES AND OTHER PAYMENTS		2
	D.	SUBSEQUENTLY CREATED INTERESTS		2
IV.	TITLES			2
	A.	TITLE EXAMINATION		2-3
	B.	LOSS OF TITLE		3
		1.	Failure of Title	3
		2.	Loss by Non-Payment or Erroneous Payment of Amount Due	3
		3.	Other Losses	3
V.	OPERATOR			4
	A.	DESIGNATION AND RESPONSIBILITIES OF OPERATOR		4
	B.	RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR		4
		1.	Resignation or Removal of Operator	4
		2.	Selection of Successor Operator	4
	C.	EMPLOYEES		4
	D.	DRILLING CONTRACTS		4
VI.	DRILLING AND DEVELOPMENT			4
	A.	INITIAL WELL		4-5
	B.	SUBSEQUENT OPERATIONS		5
		1.	Proposed Operations	5
		2.	Operations by Less than All Parties	5-6-7
		3.	Stand-By Time	7
		4.	Sidetracking	7
	C.	TAKING PRODUCTION IN KIND		7
	D.	ACCESS TO CONTRACT AREA AND INFORMATION		8
	E.	ABANDONMENT OF WELLS		8
		1.	Abandonment of Dry Holes	8
		2.	Abandonment of Wells that have Produced	8-9
		3.	Abandonment of Non-Consent Operations	10
VII.	EXPENDITURES AND LIABILITY OF PARTIES			10
	A.	LIABILITY OF PARTIES		10
	B.	LIENS AND PAYMENT DEFAULTS		10
	C.	PAYMENTS AND ACCOUNTING		10
	D.	LIMITATION OF EXPENDITURES		10-11
		1.	Drill or Deepen	10-11
		2.	Rework or Plug Back	11
		3.	Other Operations	11
	E.	RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES		11
	F.	TAXES		11
	G.	INSURANCE		12
VIII.	ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST			12
	A.	SURRENDER OF LEASES		12
	B.	RENEWAL OR EXTENSION OF LEASES		12
	C.	ACREAGE OR CASH CONTRIBUTIONS		12-13
	D.	MAINTENANCE OF UNIFORM INTEREST		13
	E.	WAIVER OF RIGHTS TO PARTITION		13
	F.	PREFERENTIAL RIGHT TO PURCHASE		13
IX.	INTERNAL REVENUE CODE ELECTION			13
X.	CLAIMS AND LAWSUITS			14
XI.	FORCE MAJEURE			14
XII.	NOTICES			14
XIII.	TERM OF AGREEMENT			14
XIV.	COMPLIANCE WITH LAWS AND REGULATIONS			15
	A.	LAWS, REGULATIONS AND ORDERS		15
	B.	GOVERNING LAW		15
	C.	REGULATORY AGENCIES		15
XV.	OTHER PROVISIONS			16
XVI.	MISCELLANEOUS			20

OPERATING AGREEMENT

THIS AGREEMENT, entered into by and between Gulfport Energy Corporation, hereinafter designated and referred to as “Operator”, and the signatory party or parties other than Operator, sometimes hereinafter referred to individually herein as “Non-Operator”, and collectively as “Non-Operators”.

WITNESSETH:

WHEREAS, the parties to this agreement are owners of oil and gas leases and/or oil and gas interests in the land identified in Exhibit “A”, and the parties hereto have reached an agreement to explore and develop these leases and/or oil and gas interests for the production of oil and gas to the extent and as hereinafter provided,

NOW, THEREFORE, it is agreed as follows:

ARTICLE I.

DEFINITIONS

As used in this agreement, the following words and terms shall have the meanings here ascribed to them:

A. The term “oil and gas” shall mean oil, gas, casinghead gas, gas condensate, and all other liquid or gaseous hydrocarbons and other marketable substances produced therewith, unless an intent to limit the inclusiveness of this term is specifically stated.

B. The terms “oil and gas lease”, “lease” and “leasehold” shall mean the oil and gas leases covering tracts of land lying within the Contract Area which are owned by the parties to this agreement.

C. The term “oil and gas interests” shall mean unleased fee and mineral interests in tracts of land lying within the Contract Area which are owned by parties to this agreement.

D. The term “Contract Area” shall mean all of the lands, oil and gas leasehold interests and oil and gas interests intended to be developed and operated for oil and gas purposes under this agreement. Such lands, oil and gas leasehold interests and oil and gas interests are described in Exhibit “A”.

E. The term “drilling unit” shall mean the area fixed for the drilling of one well by order or rule of any state or federal body having authority. If a drilling unit is not fixed by any such rule or order, a drilling unit shall be the drilling unit as established by the pattern of drilling in the Contract Area or as fixed by express agreement of the Drilling Parties.

F. The term “drillsite” shall mean the oil and gas lease or interest on which a proposed well is to be located.

G. The terms “Drilling Party” and “Consenting Party” shall mean a party who agrees to join in and pay its share of the cost of any operation conducted under the provisions of this agreement.

H. The terms “Non-Drilling Party” and “Non-Consenting Party” shall mean a party who elects not to participate in a proposed operation.

Unless the context otherwise clearly indicates, words used in the singular include the plural, the plural includes the singular, and the neuter gender includes the masculine and the feminine.

ARTICLE II.

EXHIBITS

The following exhibits, as indicated below and attached hereto, are incorporated in and made a part hereof:

x     A. Exhibit “A”, shall include the following information: Plat Only

(1)  Identification of lands subject to this agreement,

(2)  Restrictions, if any, as to depths, formations, or substances,

(3)  Percentages or fractional interests of parties to this agreement,

(4)  Oil and gas leases and/or oil and gas interests subject to this agreement,

(5)  Addresses of parties for notice purposes.

x     B. Exhibit “B”, Form of Lease.

x     C. Exhibit “C”, Accounting Procedure.

x     D. Exhibit “D”, Insurance.

x     E. Exhibit “E”, Gas Balancing Agreement.

x     F. Exhibit “F”, Non-Discrimination and Certification of Non-Segregated Facilities.

o      G. Exhibit “G”, Tax Partnership.

If any provision of any exhibit, except Exhibits “E” and “G”, is inconsistent with any provision contained in the body of this agreement, the provisions in the body of this agreement shall prevail.

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ARTICLE III.

INTERESTS OF PARTIES

A.      Oil and Gas Interests:

If any party owns an oil and gas interest in the Contract Area, that interest shall be treated for all purposes of this agreement and during the term hereof as if it were covered by the form of oil and gas lease attached hereto as Exhibit “B”, and the owner thereof shall be deemed to own both the royalty interest reserved in such lease and the interest of the lessee thereunder.

B.      Interests of Parties in Costs and Production:

Unless changed by other provisions, all costs and liabilities incurred in operations under this agreement shall be borne and paid, and all equipment and materials acquired in operations on the Contract Area shall be owned, by the parties as their interests are set forth in Exhibit “A”. In the same manner, the parties shall also own all production of oil and gas from the Contract Area subject to the payment of royalties as provided by law to the extent of the owners interest which shall be borne as hereinafter set forth.

Regardless of which party has contributed the lease(s) and/or oil and gas interest(s) hereto on which royalty is due and payable, each party entitled to receive a share of production of oil and gas from the Contract Area shall bear and shall pay or deliver, or cause to be paid or delivered, to the extent of its interest in such production, the royalty amount stipulated hereinabove and shall hold the other parties free from any liability therefor. No party shall ever be responsible, however, on a price basis higher than the price received by such party, to any other party’s lessor or royalty owner, and if any such other party’s lessor or royalty owner should demand and receive settlement on a higher price basis, the party contributing the affected lease shall bear the additional royalty burden attributable to such higher price.

Nothing contained in this Article III.B. shall be deemed an assignment or cross-assignment of interests covered hereby.

C.      Excess Royalties, Overriding Royalties and Other Payments:

Unless changed by other provisions, if the interest of any party in any lease covered hereby is subject to any royalty, overriding royalty, production payment or other burden on production in excess of the amount stipulated in Article III.B., such party so burdened shall assume and alone bear all such excess obligations and shall indemnify and hold the other parties hereto harmless from any and all claims and demands for payment asserted by owners of such excess burden.

D.      Subsequently Created Interests:

If any party should hereafter create an overriding royalty, production payment or other burden payable out of production attributable to its working interest hereunder, or if such a burden existed prior to this agreement and is not set forth in Exhibit “A”, or was not disclosed in writing to all other parties prior to the execution of this agreement by all parties, or is not a jointly acknowledged and accepted obligation of all parties (any such interest being hereinafter referred to as “subsequently created interest” irrespective of the timing of its creation and the party out of whose working interest the subsequently created interest is derived being hereinafter referred to as “burdened party”), and:

1.If the burdened party is required under this agreement to assign or relinquish to any other party, or parties, all or a portion of its working interest and/or the production attributable thereto, said other party, or parties, shall receive said assignment and/or production free and clear of said subsequently created interest and the burdened party shall indemnify and save said other party, or parties, harmless from any and all claims and demands for payment asserted by owners of the subsequently created interest; and,

2.If the burdened party fails to pay, when due, its share of expenses chargeable hereunder, all provisions of Article VII.B. shall be enforceable against the subsequently created interest in the same manner as they are enforceable against the working interest of the burdened party.

ARTICLE IV.

TITLES

A.      Title Examination:

Title examination shall be made on the drillsite and laterals of any proposed well prior to commencement of drilling operations or, if the Drilling Parties so request, title examination shall be made on the leases and/or oil and gas interests included, or planned to be included, in the drilling unit around such well. The opinion will include the ownership of the working interest, minerals, royalty, overriding royalty and production payments under the applicable leases. At the time a well is proposed, each party contributing leases and/or oil and gas interests to the drillsite, or to be included in such drilling unit, shall furnish to Operator all abstracts (including federal lease status reports), title opinions, title papers and curative material in its possession free of charge. All such information not in the possession of or made available to Operator by the parties, but necessary for the examination of the title, shall be obtained by Operator. Operator shall cause title to be examined by attorneys on its staff or by outside attorneys. Copies of all title opinions shall be furnished to each party hereto. The cost incurred by Operator in this title program shall be borne as follows:

o      Option No. 1:  Costs incurred by Operator in procuring abstracts and title examination (including preliminary, supplemental, shut-in gas royalty opinions and division order title opinions) shall be a part of the administrative overhead as provided in Exhibit “C”, and shall not be a direct charge, whether performed by Operator’s staff attorneys or by outside attorneys.

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x     Option No. 2:  Costs incurred by Operator in procuring abstracts and fees paid outside attorneys and lease brokers for title examination (including preliminary, supplemental, shut-in gas royalty opinions and division order title opinions) shall be borne by the Drilling Parties in the proportion that the interest of each Drilling Party bears to the total interest of all Drilling Parties as such interests appear in Exhibit “A”. Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions.

Each party shall be responsible for securing curative matter and pooling amendments or agreements required in connection with leases or oil and gas interests contributed by such party. Operator shall be responsible for the preparation and recording of pooling designations or declarations as well as the conduct of hearings before governmental agencies for the securing of spacing or pooling orders. This shall not prevent any party from appearing on its own behalf at any such hearing.

No well shall be drilled on the Contract Area until after (1) the title to the drillsite or drilling unit has been examined as above provided, and (2) the title has been approved by the examining attorney or title has been accepted by all of the parties who are to participate in the drilling of the well.

B.      Loss of Title:

1. Failure of Title:  Should any oil and gas interest or lease, or interest therein, be lost through failure of title, which loss results in a reduction of interest from that shown on Exhibit “A”, the party contributing the affected lease or interest shall have ninety (90) days from final determination of title failure to acquire a new lease or other instrument curing the entirety of the title failure, which acquisition will not be subject to Article VIII.B., and failing to do so, this agreement, nevertheless, shall continue in force as to all remaining oil and gas leases and interests: and,

(a)  The party whose oil and gas lease or interest is affected by the title failure shall bear alone the entire loss and it shall not be entitled to recover from Operator or the other parties any development or operating costs which it may have theretofore paid or incurred, but there shall be no additional liability on its part to the other parties hereto by reason of such title failure;

(b)  There shall be no retroactive adjustment of expenses incurred or revenues received from the operation of the interest which has been lost, but the interests of the parties shall be revised on an acreage basis, as of the time it is determined finally that title failure has occurred, so that the interest of the party whose lease or interest is affected by the title failure will thereafter be reduced in the Contract Area by the amount of the interest lost;

(c)  If the proportionate interest of the other parties hereto in any producing well theretofore drilled on the Contract Area is increased by reason of the title failure, the party whose title has failed shall receive the proceeds attributable to the increase in such interest (less costs and burdens attributable thereto) until it has been reimbursed for unrecovered costs paid by it in connection with such well;

(d)  Should any person not a party to this agreement, who is determined to be the owner of any interest in the title which has failed, pay in any manner any part of the cost of operation, development, or equipment, such amount shall be paid to the party or parties who bore the costs which are so refunded;

(e)  Any liability to account to a third party for prior production of oil and gas which arises by reason of title failure shall be borne by the party or parties whose title failed in the same proportions in which they shared in such prior production; and,

(f)  No charge shall be made to the joint account for legal expenses, fees or salaries, in connection with the defense of the interest claimed by any party hereto, it being the intention of the parties hereto that each shall defend title to its interest and bear all expenses in connection therewith.

2. Loss by Non-Payment or Erroneous Payment of Amount Due:  If, through mistake or oversight, any rental, shut-in well payment, minimum royalty or royalty payment, is not paid or is erroneously paid, and as a result a lease or interest therein terminates, there shall be no monetary liability against the party who failed to make such payment. Unless the party who failed to make the required payment secures a new lease covering the same interest within ninety (90) days from the discovery of the failure to make proper payment, which acquisition will not be subject to Article VIII.B., the interests of the parties shall be revised on an acreage basis, effective as of the date of termination of the lease involved, and the party who failed to make proper payment will no longer be credited with an interest in the Contract Area on account of ownership of the lease or interest which has terminated. In the event the party who failed to make the required payment shall not have been fully reimbursed, at the time of the loss, from the proceeds of the sale of oil and gas attributable to the lost interest, calculated on an acreage basis, for the development and operating costs theretofore paid on account of such interest, it shall be reimbursed for unrecovered actual costs theretofore paid by it (but not for its share of the cost of any dry hole previously drilled or wells previously abandoned) from so much of the following as is necessary to effect reimbursement:

(a)  Proceeds of oil and gas, less operating expenses, theretofore accrued to the credit of the lost interest, on an acreage basis, up to the amount of unrecovered costs;

(b)  Proceeds, less operating expenses, thereafter accrued attributable to the lost interest on an acreage basis, of that portion of oil and gas thereafter produced and marketed (excluding production from any wells thereafter drilled) which, in the absence of such lease termination, would be attributable to the lost interest on an acreage basis, up to the amount of unrecovered costs, the proceeds of said portion of the oil and gas to be contributed by the other parties in proportion to their respective interest; and,

(c)  Any monies, up to the amount of unrecovered costs, that may be paid by any party who is, or becomes, the owner of the interest lost, for the privilege of participating in the Contract Area or becoming a party to this agreement.

3. Other Losses:  All losses incurred, other than those set forth in Articles IV.B.1. and IV.B.2. above, shall be joint losses and shall be borne by all parties in proportion to their interests. There shall be no readjustment of interests in the remaining portion of the Contract Area.

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ARTICLE V.

OPERATOR

A.      Designation and Responsibilities of Operator:

Gulfport Energy Corporation shall be the Operator of the Contract Area, and shall conduct and direct and have full control of all operations on the Contract Area as permitted and required by, and within the limits of this agreement. It shall conduct all such operations in a good and workmanlike manner, but it shall have no liability as Operator to the other parties for losses sustained or liabilities incurred, except such as may result from gross negligence or willful misconduct.

B.      Resignation or Removal of Operator and Selection of Successor:

1. Resignation or Removal of Operator:  Operator may resign at any time by giving written notice thereof to Non-Operators. If Operator terminates its legal existence, no longer owns an interest hereunder in the Contract Area, or is no longer capable of serving as Operator, Operator shall be deemed to have resigned without any action by Non-Operators, except the selection of a successor. Operator may be removed if it fails or refuses to carry out its duties hereunder, or becomes insolvent, bankrupt or is placed in receivership, by the affirmative vote of two (2) or more Non-Operators owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding the voting interest of Operator. Such resignation or removal shall not become effective until 7:00 o’clock A.M. on the first day of the calendar month following the expiration of ninety (90) days after the giving of notice of resignation by Operator or action by the Non-Operators to remove Operator, unless a successor Operator has been selected and assumes the duties of Operator at an earlier date. Operator, after effective date of resignation or removal, shall be bound by the terms hereof as a Non-Operator. A change of a corporate name or structure of Operator or transfer of Operator’s interest to any single subsidiary, parent or successor corporation shall not be the basis for removal of Operator.

2. Selection of Successor Operator:  Upon the resignation or removal of Operator, a successor Operator shall be selected by the parties. The successor Operator shall be selected from the parties owning an interest in the Contract Area at the time such successor Operator is selected. The successor Operator shall be selected by the affirmative vote of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit “A”; provided, however, if an Operator which has been removed fails to vote or votes only to succeed itself, the successor Operator shall be selected by the affirmative vote of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding the voting interest of the Operator that was removed.

C.      Employees:

The number of employees used by Operator in conducting operations hereunder, their selection, and the hours of labor and the compensation for services performed shall be determined by Operator, and all such employees shall be the employees of Operator.

D.      Drilling Contracts:

All wells drilled on the Contract Area shall be drilled on a competitive contract basis at the usual rates prevailing in the area. If it so desires, Operator may employ its own tools and equipment in the drilling of wells, but its charges therefor shall not exceed the prevailing rates in the area and the rate of such charges shall be agreed upon by the parties in writing before drilling operations are commenced, and such work shall be performed by Operator under the same terms and conditions as are customary and usual in the area in contracts of independent contractors who are doing work of a similar nature.

ARTICLE VI.

DRILLING AND DEVELOPMENT

A.      Initial Well:

On or before the 1st day of March, (year) 2012, Operator shall commence the drilling of a well for oil and gas at the following location:

As proposed pursuant to the terms of this Agreement.

and shall thereafter continue the drilling of the well with due diligence to

Test the Utica/Point Pleasant Formation

unless granite or other practically impenetrable substance or condition in the hole, which renders further drilling impractical, is encountered at a lesser depth, or unless all parties agree to complete or abandon the well at a lesser depth.

Operator shall make reasonable tests of all formations encountered during drilling which give indication of containing oil and gas in quantities sufficient to test, unless this agreement shall be limited in its application to a specific formation or formations, in which event Operator shall be required to test only the formation or formations to which this agreement may apply.

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If, in Operator’s judgment, the well will not produce oil or gas in paying quantities, and it wishes to plug and abandon the well as a dry hole, the provisions of Article VI.E.1. shall thereafter apply.

B.      Subsequent Operations:

1. Proposed Operations:  Should any party hereto desire to drill any well on the Contract Area other than the well provided for in Article VI.A., or to rework, deepen or plug back a dry hole drilled at the joint expense of all parties or a well jointly owned by all

the parties and not then producing in paying quantities, the party desiring to drill, rework, deepen or plug back such a well shall give the other parties written notice of the proposed operation, specifying the work to be performed, the location, proposed depth, objective formation and the estimated cost of the operation. The parties receiving such a notice shall have thirty (30) days after receipt of the notice within which to notify the party wishing to do the work whether they elect to participate in the cost of the proposed operation. If a drilling rig is on location, notice of a proposal to rework, plug back or drill deeper may be given by telephone and the response period shall be limited to twenty-four (24) forty-eight (48) hours, exclusive of Saturday, Sunday, and legal holidays. Failure of a party receiving such notice to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the proposed operation. Any notice or response given by telephone shall be promptly confirmed in writing.

If all parties elect to participate in such a proposed operation, Operator shall, within ninety (90) days after expiration of the notice period of thirty (30) days (or as promptly as possible after the expiration of the twenty-four (24) forty-eight (48) hour period when a drilling rig is on location, as the case may be), actually commence the proposed operation and complete it with due diligence at the risk and expense of all parties hereto; provided, however, said commencement date may be extended upon written notice of same by Operator to the other parties, for a period of up to thirty (30) additional days if, in the sole opinion of Operator, such additional time is reasonably necessary to obtain permits from governmental authorities, surface rights (including rights-of-way) or appropriate drilling equipment, or to complete title examination or curative matter required for title approval or acceptance. Notwithstanding the force majeure provisions of Article XI, if the actual operation has not been commenced within the time provided (including any extension thereof as specifically permitted herein) and if any party hereto still desires to conduct said operation, written notice proposing same must be resubmitted to the other parties in accordance with the provisions hereof as if no prior proposal had been made.

2. Operations by Less than All Parties:  If any party receiving such notice as provided in Article VI.B.1. or VII.D.1. (Option No. 2) elects not to participate in the proposed operation, then, in order to be entitled to the benefits of this Article, the party or parties giving the notice and such other parties as shall elect to participate in the operation shall, within ninety (90) days after the expiration of the notice period of thirty (30) days (or as promptly as possible after the expiration of the twenty-four (24) forty-eight (48) hour period when a drilling rig is on location, as the case may be) actually commence the proposed operation and complete it with due diligence. Operator shall perform all work for the account of the Consenting Parties; provided, however, if no drilling rig or other equipment is on location, and if Operator is a Non-Consenting Party, the Consenting Parties shall either: (a) request Operator to perform the work required by such proposed operation for the account of the Consenting Parties, or (b) designate one (1) of the Consenting Parties as Operator to perform such work. Consenting Parties, when conducting operations on the Contract Area pursuant to this Article VI.B.2., shall comply with all terms and conditions of this agreement. Nothing contained herein shall prohibit Operator or the participatory parties from actually commencing the proposed operation before the expiration of the notice period, nor shall the timing of such commencement affect in any way the validity of a party’s election or deemed election.

If less than all parties approve any proposed operation, the proposing party, immediately after the expiration of the applicable notice period, shall advise the Consenting Parties of the total interest of the parties approving such operation and its recommendation as to whether the Consenting Parties should proceed with the operation as proposed. Each Consenting Party, within twenty-four (24) forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after receipt of such notice, shall advise the proposing party of its desire to (a) limit participation to such party’s interest as shown on Exhibit “A” or (b) carry its proportionate part of Non-Consenting Parties’ interests, and failure to advise the proposing party shall be deemed an election under (a). In the event a drilling rig is on location, the time permitted for such a response shall not exceed a total of twenty-four (24) forty-eight (48) hours (inclusive of Saturday, Sunday and legal holidays). The proposing party, at its election, may withdraw such proposal if there is insufficient participation and shall promptly notify all parties of such decision.

The entire cost and risk of conducting such operations shall be borne by the Consenting Parties in the proportions they have elected to bear same under the terms of the preceding paragraph. Consenting Parties shall keep the leasehold estates involved in such operations free and clear of all liens and encumbrances of every kind created by or arising from the operations of the Consenting Parties. If such an operation results in a dry hole, the Consenting Parties shall plug and abandon the well and restore the surface location at their sole cost, risk and expense. If any well drilled, reworked, deepened or plugged back under the provisions of this Article results in a producer of oil and/or gas in paying quantities, the Consenting Parties shall complete and equip the well to produce at their sole cost and risk,

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and the well shall then be turned over to Operator and shall be operated by it at the expense and for the account of the Consenting Parties. Upon commencement of operations for the drilling, reworking, deepening or plugging back of any such well by Consenting Parties in accordance with the provisions of this Article, each Non-Consenting Party shall be deemed to have relinquished to Consenting Parties, and the Consenting Parties shall own and be entitled to receive, in proportion to their respective interests, all of such Non-Consenting Party’s interest in the well and share of production therefrom until the proceeds of the sale of such share, calculated at the well, or market value thereof if such share is not sold, (after deducting production taxes, excise taxes, royalty, overriding royalty and other interests not excepted by Article III.D. payable out of or measured by the production from such well accruing with respect to such interest until it reverts) shall equal the total of the following:

(a)  100% of each such Non-Consenting Party’s share of the cost of any newly acquired surface equipment beyond the wellhead connections (including, but not limited to, stock tanks, separators, treaters, pumping equipment and piping), plus 100% of each such Non-Consenting Party’s share of the cost of operation of the well commencing with first production and continuing until each such Non-Consenting Party’s relinquished interest shall revert to it under other provisions of this Article, it being agreed that each Non-Consenting Party’s share of such costs and equipment will be that interest which would have been chargeable to such Non-Consenting Party had it participated in the well from the beginning of the operations; and

(b)  400% of that portion of the costs and expenses of drilling, reworking, deepening, plugging back, testing and completing, after deducting any cash contributions received under Article VIII.C., and 400% of that portion of the cost of newly acquired equipment in the well (to and including the wellhead connections), which would have been chargeable to such Non-Consenting Party if it had participated therein.

An election not to participate in the drilling or the deepening of a well shall be deemed an election not to participate in any reworking or plugging back operation proposed in such a well, or portion thereof, to which the initial Non-Consent election applied that is conducted at any time prior to full recovery by the Consenting Parties of the Non-Consenting Party’s recoupment account. Any such reworking or plugging back operation conducted during the recoupment period shall be deemed part of the cost of operation of said well and there shall be added to the sums to be recouped by the Consenting Parties one hundred percent (100%) of that portion of the costs of the reworking or plugging back operation which would have been chargeable to such Non-Consenting Party had it participated therein. If such a reworking or plugging back operation is proposed during such recoupment period, the provisions of this Article VI.B. shall be applicable as between said Consenting Parties in said well.

During the period of time Consenting Parties are entitled to receive Non-Consenting Party’s share of production, or the proceeds therefrom, Consenting Parties shall be responsible for the payment of all production, severance, excise, gathering and other taxes, and all royalty, overriding royalty and other burdens applicable to Non-Consenting Party’s share of production not excepted by Article III.D.

In the case of any reworking, plugging back or deeper drilling operation, the Consenting Parties shall be permitted to use, free of cost, all casing, tubing and other equipment in the well, but the ownership of all such equipment shall remain unchanged; and upon abandonment of a well after such reworking, plugging back or deeper drilling, the Consenting Parties shall account for all such equipment to the owners thereof, with each party receiving its proportionate part in kind or in value, less cost of salvage.

Within sixty (60) days after the completion of any operation under this Article, the party conducting the operations for the Consenting Parties shall furnish each Non-Consenting Party with an inventory of the equipment in and connected to the well, and an itemized statement of the cost of drilling, deepening, plugging back, testing, completing, and equipping the well for production; or, at its option, the operating party, in lieu of an itemized statement of such costs of operation, may submit a detailed statement of monthly billings. Each month thereafter, during the time the Consenting Parties are being reimbursed as provided above, the party conducting the operations for the Consenting Parties shall furnish the Non-Consenting Parties with an itemized statement of all costs and liabilities incurred in the operation of the well, together with a statement of the quantity of oil and gas produced from it and the amount of proceeds realized from the sale of the well’s working interest production during the preceding month. In determining the quantity of oil and gas produced during any month, Consenting Parties shall use industry accepted methods such as, but not limited to, metering or periodic well tests. Any amount realized from the sale or other disposition of equipment newly acquired in connection with any such operation which would have been owned by a Non-Consenting Party had it participated therein shall be credited against the total unreturned costs of the work done and of the equipment purchased in determining when the interest of such Non-Consenting Party shall revert to it as above provided; and if there is a credit balance, it shall be paid to such Non-Consenting Party.

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If and when the Consenting Parties recover from a Non-Consenting Party’s relinquished interest the amounts provided for above, the relinquished interests of such Non-Consenting Party shall automatically revert to it, and, from and after such reversion, such Non-Consenting Party shall own the same interest in such well, the material and equipment in or pertaining thereto, and the production therefrom as such Non-Consenting Party would have been entitled to had it participated in the drilling, reworking, deepening or plugging back of said well. Thereafter, such Non-Consenting Party shall be charged with and shall pay its proportionate part of the further costs of the operation of said well in accordance with the terms of this agreement and the Accounting Procedure attached hereto.

Notwithstanding the provisions of this Article VI.B.2., it is agreed that without the mutual consent of all parties, no wells shall be completed in or produced from a source of supply from which a well located elsewhere on the Contract Area is producing, unless such well conforms to the then-existing well spacing pattern for such source of supply.

The provisions of this Article shall have no application whatsoever to the drilling of the initial well described in Article VI.A. except (a) as to Article VII.D.1. (Option No. 2), if selected, or (b) as to the reworking, deepening and plugging back of such initial well after if has been drilled to the depth specified in Article VI.A. if it shall thereafter prove to be a dry hole or, if initially completed for production, ceases to produce in paying quantities.

3. Stand-By Time:  When a well which has been drilled or deepened has reached its authorized depth and all tests have been completed, and the results thereof furnished to the parties, stand-by costs incurred pending response to a party’s notice proposing a reworking, deepening, plugging back or completing operation in such a well shall be charged and borne as part of the drilling or deepening operation just completed. Stand-by costs subsequent to all parties responding, or expiration of the response time permitted, whichever first occurs, and prior to agreement as to the participating interests of all Consenting Parties pursuant to the terms of the second grammatical paragraph of Article VI.B.2., shall be charged to and borne as part of the proposed operation, but if the proposal is subsequently withdrawn because of insufficient participation, such stand-by costs shall be allocated between the Consenting Parties in the proportion each Consenting Party’s interest as shown on Exhibit “A” bears to the total interest as shown on Exhibit “A” of all Consenting Parties.

4. Sidetracking:  Except as hereinafter provided, those provisions of this agreement applicable to a “deepening” operation shall also be applicable to any proposal to directionally control and intentionally deviate a well from vertical so as to change the bottom hole location (herein call “sidetracking”), unless done to straighten the hole or to drill around junk in the hole or because of other mechanical difficulties. Any party having the right to participate in a proposed sidetracking operation that does not own an interest in the affected well bore at the time of the notice shall, upon electing to participate, tender to the well bore owners its proportionate share (equal to its interest in the sidetracking operation) of the value of that portion of the existing well bore to be utilized as follows:

(a)  If the proposal is for sidetracking an existing dry hole, reimbursement shall be on the basis of the actual costs incurred in

the initial drilling of the well down to the depth at which the sidetracking operation is initiated.

(b)  If the proposal is for sidetracking a well which has previously produced, reimbursement shall be on the basis of the well’s salvable materials and equipment down to the depth at which the sidetracking operation is initiated, determined in accordance with the provisions of Exhibit “C”, less the estimated cost of salvaging and the estimated cost of plugging and abandoning.

In the event that notice for a sidetracking operation is given while the drilling rig to be utilized is on location, the response period shall be limited to twenty-four (24) forty-eight (48) hours, exclusive of Saturday, Sunday and legal holidays; provided, however, any party may request and receive up to eight (8) additional days after expiration of the twenty-four (24) forty-eight (48) hours within which to respond by paying for all stand-by time incurred during such extended response period. If more than one party elects to take such additional time to respond to the notice, stand by costs shall be allocated between the parties taking additional time to respond on a day-to-day basis in the proportion each electing party’s interest as shown on Exhibit “A” bears to the total interest as shown on Exhibit “A” of all the electing parties. In all other instances the response period to a proposal for sidetracking shall be limited to thirty (30) days.

C.      TAKING PRODUCTION IN KIND:

Each party shall have the right to take in kind or separately dispose of its proportionate share of all oil and gas produced from the Contract Area, exclusive of production which may be used in development and producing operations and in preparing and treating oil and gas for marketing purposes and production unavoidably lost. Any extra expenditure incurred in the taking in kind or separate disposition by any party of its proportionate share of the production shall be borne by such party. Any party taking its share of production in kind shall berequired to pay for only its proportionate share of such part of Operator’s surface facilities which it uses.

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Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment directly from the purchaser thereof for its share of all production.

In the event any party shall fail to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the oil produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party owning it, but not the obligation, to purchase such oil or sell it to others at any time and from time to time, for the account of the non-taking party at the best price obtainable in the area for such production. Any such purchase or sale by Operator shall be subject always to the right of the owner of the production to exercise at any time its right to take in kind, or separately dispose of, its share of all oil not previously delivered to a purchaser. Any purchase or sale by Operator of any other party’s share of oil shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1) year.

In the event one or more parties’ separate disposition of its share of the gas causes split-stream deliveries to separate pipelines and/or deliveries which on a day-to-day basis for any reason are not exactly equal to a party’s respective proportionate share of total gas sales to be allocated to it, the balancing or accounting between the respective accounts of the parties shall be in accordance with any gas balancing agreement between the parties hereto, whether such an agreement is attached as Exhibit “E”, or is a separate agreement.

D.     Access to Contract Area and Information:

Each party shall have access to the Contract Area at all reasonable times, at its sole cost and risk to inspect or observe operations, and shall have access at reasonable times to information pertaining to the development or operation thereof, including Operator’s books and records relating thereto. Operator, upon request, shall furnish each of the other parties with copies of all forms or reports filed with governmental agencies, daily drilling reports, well logs, tank tables, daily gauge and run tickets and reports of stock on hand at the first of each month, and shall make available samples of any cores or cuttings taken from any well drilled on the Contract Area. The cost of gathering and furnishing information to Non-Operator, other than that specified above, shall be charged to the Non-Operator that requests the Information.

E.     Abandonment of Wells:

1. Abandonment of Dry Holes:  Except for any well drilled or deepened pursuant to Article VI.B.2., any well which has been drilled or deepened under the terms of this agreement and is proposed to be completed as a dry hole shall not be plugged and abandoned without the consent of all parties. Should Operator, after diligent effort, be unable to contact any party, or should any party fail to reply within twenty-four (24) forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after receipt of notice of the proposal to plug and abandon such well, such party shall be deemed to have consented to the proposed abandonment. All such wells shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of the parties who participated in the cost of drilling or deepening such well. Any party who objects to plugging and abandoning such well shall have the right to take over the well and conduct further operations in search of oil and/or gas subject to the provisions of Article VI.B.

2. Abandonment of Wells that have Produced:  Except for any well in which a Non-Consent operation has been conducted hereunder for which the Consenting Parties have not been fully reimbursed as herein provided, any well which has been completed as a producer shall not be plugged and abandoned without the consent of all parties. If all parties consent to such abandonment, the well shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of all the parties hereto. If, within thirty (30) days after receipt of notice of the proposed abandonment of any well, all parties do not agree to the abandonment of such well, those wishing to continue its operation from the interval(s) of the formation(s) then open to production shall tender to each of the other parties its proportionate share of the value of the well’s salvable material and equipment, determined in accordance with the provisions of Exhibit “C”, less the estimated cost of salvaging and the estimated cost of plugging and abandoning. Each abandoning party shall assign the non-abandoning parties, without warranty, express or implied, as to title or as to quantity, or fitness for use of the equipment and material, all of its interest in the well and related equipment, together with its interest in the leasehold estate as to, but only as to, the interval or intervals of the formation or formations then open to production. If the interest of the abandoning party is or includes an oil and gas interest, such party shall execute and deliver to the non-abandoning party or parties an oil and gas lease, limited to the interval or intervals of the formation or formations then open to production, for a term of one (1) year and so long thereafter as oil and/or gas is produced from the interval or intervals of the formation or formations covered thereby, such lease to be on the form attached as Exhibit

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required to pay for only its proportionate share of such part of Operator’s surface facilities which it uses.

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment directly from the purchaser thereof for its share of all production.

In the event any party shall fail to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the oil and gas produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party owning it, but not the obligation, to purchase such oil and gas or sell it to others at any time and from time to time, for the account of the non-taking party at the best price obtainable in the area for such production. Any such purchase or sale by Operator shall be subject always to the right of the owner of the production to exercise at any time its right to take in kind, or separately dispose of, its share of all oil and gas not previously delivered to a purchaser. Any purchase or sale by Operator of any other party’s share of oil and gas shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1) year. Notwithstanding the foregoing, Operator shall not make a sale, including one into interstate commerce, of any other party’s share of gas production without first giving such other party thirty (30) days notice of such intended sale.

D.     Access to Contract Area and Information:

Each party shall have access to the Contract Area at all reasonable times, at its sole cost and risk to inspect or observe operations, and shall have access at reasonable times to information pertaining to the development or operation thereof, including Operator’s books and records relating thereto. Operator, upon request, shall furnish each of the other parties with copies of all forms or reports filed with governmental agencies, daily drilling reports, well logs, tank tables, daily gauge and run tickets and reports of stock on hand at the first of each month, and shall make available samples of any cores or cuttings taken from any well drilled on the Contract Area. The cost of gathering and furnishing information to Non-Operator, other than that specified above, shall be charged to the Non-Operator that requests the Information.

E.     Abandonment of Wells:

1. Abandonment of Dry Holes:  Except for any well drilled or deepened pursuant to Article VI.B.2., any well which has been drilled or deepened under the terms of this agreement and is proposed to be completed as a dry hole shall not be plugged and abandoned without the consent of all parties. Should Operator, after diligent effort, be unable to contact any party, or should any party fail to reply within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after receipt of notice of the proposal to plug and abandon such well, such party shall be deemed to have consented to the proposed abandonment. All such wells shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of the parties who participated in the cost of drilling or deepening such well. Any party who objects to plugging and abandoning such well shall have the right to take over the well and conduct further operations in search of oil and/or gas subject to the provisions of Article VI.B.

2. Abandonment of Wells that have Produced:  Except for any well in which a Non-Consent operation has been conducted hereunder for which the Consenting Parties have not been fully reimbursed as herein provided, any well which has been completed as a producer shall not be plugged and abandoned without the consent of all parties. If all parties consent to such abandonment, the well shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of all the parties hereto. If, within thirty (30) days after receipt of notice of the proposed abandonment of any well, all parties do not agree to the abandonment of such well, those wishing to continue its operation from the interval(s) of the formation(s) then open to production shall tender to each of the other parties its proportionate share of the value of the well’s salvable material and equipment, determined in accordance with the provisions of Exhibit “C”, less the estimated cost of salvaging and the estimated cost of plugging and abandoning. Each abandoning party shall assign the non-abandoning parties, without warranty, express or implied, as to title or as to quantity, or fitness for use of the equipment and material, all of its interest in the well and related equipment, together with its interest in the leasehold estate as to, but only as to, the interval or intervals of the formation or formations then open to production. If the interest of the abandoning party is or includes an oil and gas interest, such party shall execute and deliver to the non-abandoning party or parties an oil and gas lease, limited to the interval or intervals of the formation or formations then open to production, for a term of one (1) year and so long thereafter as oil and/or gas is produced from the interval or intervals of the formation or formations covered thereby, such lease to be on the form attached as Exhibit

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“B”. The assignments or leases so limited shall encompass the “drilling unit” upon which the well is located. The payments by, and the assignments or leases to, the assignees shall be in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all assignees. There shall be no readjustment of interests in the remaining portion of the Contract Area.

Thereafter, abandoning parties shall have no further responsibility, liability, or interest in the operation of or production from the well in the interval or intervals then open other than the royalties retained in any lease made under the terms of this Article. Upon request, at its election, Operator shall continue to operate the assigned well for the account of the non-abandoning parties at the rates and charges contemplated by this agreement, plus any additional cost and charges which may arise as the result of the separate ownership of the assigned well. Upon proposed abandonment of the producing interval(s) assigned or leased, the assignor or lessor shall then have the option to repurchase its prior interest in the well (using the same valuation formula) and participate in further operations therein subject to the provisions hereof.

3. Abandonment of Non-Consent Operations:  The provisions of Article VI.E.1. or VI.E.2 above shall be applicable as between Consenting Parties in the event of the proposed abandonment of any well excepted from said Articles; provided, however, no well shall be permanently plugged and abandoned unless and until all parties having the right to conduct further operations therein have been notified of the proposed abandonment and afforded the opportunity to elect to take over the well in accordance with the provisions of this Article VI.E.

ARTICLE VII.

EXPENDITURES AND LIABILITY OF PARTIES

A.     Liability of Parties:

The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs of developing and operating the Contract Area. Accordingly, the liens granted among the parties in Article VII.B. are given to secure only the debts of each severally. It is not the intention of the parties to create, nor shall this agreement be construed as creating, a mining or other partnership or association, or to render the parties liable as partners.

B.     Liens and Payment Defaults:

Each Non-Operator grants to Operator a lien upon its oil and gas rights in the Contract Area, and a security interest in its share of oil and/or gas when extracted and its interest in all equipment, to secure payment of its share of expense, together with interest thereon at the rate provided in Exhibit “C”. To the extent that Operator has a security interest under the Uniform Commercial Code of the state, Operator shall be entitled to exercise the rights and remedies of a secured party under the Code. The bringing of a suit and the obtaining of judgment by Operator for the secured indebtedness shall not be deemed an election of remedies or otherwise affect the lien rights or security interest as security for the payment thereof. In addition, upon default by any Non-Operator in the payment of its share of expense, Operator shall have the right, without prejudice to other rights or remedies, to collect from the purchaser the proceeds from the sale of such Non-Operator’s share of oil and/or gas until the amount owed by such Non-Operator, plus interest, has been paid. Each purchaser shall be entitled to rely upon Operator’s written statement concerning the amount of any default. Operator grants a like lien and security interest to the Non-Operators to secure payment of Operator’s proportionate share of expense.

If any party fails or is unable to pay its share of expense within sixty (60) days after rendition of a statement therefor by Operator, the non-defaulting parties, including Operator, shall, upon request by Operator, pay the unpaid amount in the proportion that the interest of each such party bears to the interest of all such parties. Each party so paying its share of the unpaid amount shall, to obtain reimbursement thereof, be subrogated to the security rights described in the foregoing paragraph.

C.     Payments and Accounting:

Except as herein otherwise specifically provided, Operator shall promptly pay and discharge expenses incurred in the development and operation of the Contract Area pursuant to this agreement and shall charge each of the parties hereto with their respective proportionate shares upon the expense basis provided in Exhibit “C”. Operator shall keep an accurate record of the joint account hereunder, showing expenses incurred and charges and credits made and received.

Operator, at its election, shall have the right from time to time to demand and receive from the other parties payment in advance of their respective shares of the estimated amount of the expense to be incurred in operations hereunder during the next succeeding month, which right may be exercised only by submission to each such party of an itemized statement of such estimated expense, together with an invoice for its share thereof. Each such statement and invoice for the payment in advance of estimated expense shall be submitted on or before the 20th day of the next preceding month. Each party shall pay to Operator its proportionate share of such estimate within thirty (30) fifteen (15) days after such estimate and invoice is received. If any party fails to pay its share of said estimate within said time, the amount due shall bear interest as provided in Exhibit “C” until paid. Proper adjustment shall be made monthly between advances and actual expense to the end that each party shall bear and pay its proportionate share of actual expenses incurred, and no more.

D.     Limitation of Expenditures:

1. Drill or Deepen:  Without the consent of all parties, no well shall be drilled or deepened, except any well drilled or deepened pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the drilling or deepening shall include:

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x     Option No. 1:  All necessary expenditures for the drilling or deepening, testing, completing and equipping of the well, including

necessary tankage and/or surface facilities.

o      Option No. 2:  All necessary expenditures for the drilling or deepening and testing of the well. When such well has reached its authorized depth, and all tests have been completed, and the results thereof furnished to the parties, Operator shall give immediate notice to the Non-Operators who have the right to participate in the completion costs. The parties receiving such notice shall have forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) in which to elect to participate in the setting of casing and the completion attempt. Such election, when made, shall include consent to all necessary expenditures for the completing and equipping of such well, including necessary tankage and/or surface facilities. Failure of any party receiving such notice to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the completion attempt. If one or more, but less than all of the parties, elect to set pipe and to attempt a completion, the provisions of Article VI.B.2. hereof (the phrase “reworking, deepening or plugging back” as contained in Article VI.B.2. shall be deemed to include “completing”) shall apply to the operations thereafter conducted by less than all parties.

2. Rework or Plug Back:  Without the consent of all parties, no well shall be reworked or plugged back except a well reworked or plugged back pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the reworking or plugging back of a well shall include all necessary expenditures in conducting such operations and completing and equipping of said well, including necessary tankage and/or surface facilities.

3. Other Operations:  Without the consent of all parties, Operator shall not undertake any single project reasonably estimated to require an expenditure in excess of Fifty-Thousand Dollars ($50,000.00) except in connection with a well, the drilling, reworking, deepening, completing, recompleting, or plugging back of which has been previously authorized by or pursuant to this agreement; provided, however, that, in case of explosion, fire, flood or other sudden emergency, whether of the same or different nature, Operator may take such steps and incur such expenses as in its opinion are required to deal with the emergency to safeguard life and property but Operator, as promptly as possible, shall report the emergency to the other parties. If Operator prepares an authority for expenditure (AFE) for its own use, Operator shall furnish any Non-Operator so requesting an information copy thereof for any single project costing in excess of Fifty-Thousand Dollars ($50,000.00) but less than the amount first set forth above in this paragraph.

E.     Rentals, Shut-in Well Payments and Minimum Royalties:

Rentals, shut-in well payments and minimum royalties which may be required under the terms of any lease shall be paid by the party or parties who subjected such lease to this agreement at its or their expense. In the event two or more parties own and have contributed interests in the same lease to this agreement, such parties may designate one of such parties to make said payments for and on behalf of all such parties. Any party may request, and shall be entitled to receive, proper evidence of all such payments. In the event of failure to make proper payment of any rental, shut-in well payment or minimum royalty through mistake or oversight where such payment is required to continue the lease in force, any loss which results from such non-payment shall be borne in accordance with the provisions of Article IV.B.2.

Operator shall notify Non-Operator of the anticipated completion of a shut-in gas well, or the shutting in or return to production of a producing gas well, at least five (5) days (excluding Saturday, Sunday and legal holidays), or at the earliest opportunity permitted by circumstances, prior to taking such action, but assumes no liability for failure to do so. In the event of failure by Operator to so notify Non-Operator, the loss of any lease contributed hereto by Non-Operator for failure to make timely payments of any shut-in well payment shall be borne jointly by the parties hereto under the provisions of Article IV.B.3.

F.     Taxes:

Beginning with the first calendar year after the effective date hereof, Operator shall render for ad valorem taxation all property subject to this agreement which by law should be rendered for such taxes, and it shall pay all such taxes assessed thereon before they become delinquent. Prior to the rendition date, each Non-Operator shall furnish Operator information as to burdens (to include, but not be limited to, royalties, overriding royalties and production payments) on leases and oil and gas interests contributed by such Non-Operator. If the assessed valuation of any leasehold estate is reduced by reason of its being subject to outstanding excess royalties, overriding royalties or production payments, the reduction in ad valorem taxes resulting therefrom shall inure to the benefit of the owner or owners of such leasehold estate, and Operator shall adjust the charge to such owner or owners so as to reflect the benefit of such reduction. If the ad valorem taxes are based in whole or in part upon separate valuations of each party’s working interest, then notwithstanding anything to the contrary herein, charges to the joint account shall be made and paid by the parties hereto in accordance with the tax value generated by each party’s working interest. Operator shall bill the other parties for their proportionate shares of all tax payments in the manner provided in Exhibit “C”.

If Operator considers any tax assessment improper, Operator may, at its discretion, protest within the time and manner prescribed by law, and prosecute the protest to a final determination, unless all parties agree to abandon the protest prior to final determination. During the pendency of administrative or judicial proceedings, Operator may elect to pay, under protest, all such taxes and any interest and penalty. When any such protested assessment shall have been finally determined, Operator shall pay the tax for the joint account, together with any interest and penalty accrued, and the total cost shall then be assessed against the parties, and be paid by them, as provided in Exhibit “C”.

Each party shall pay or cause to be paid all production, severance, excise, gathering and other taxes imposed upon or with respect to the production or handling of such party’s share of oil and/or gas produced under the terms of this agreement.

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G.    Insurance:

At all times while operations are conducted hereunder, Operator shall comply with the workmen’s compensation law of the state where the operations are being conducted; provided, however, that Operator may be a self-insurer for liability under said compensation laws in which event the only charge that shall be made to the joint account shall be as provided in Exhibit “C”. Operator shall also carry or provide insurance for the benefit of the joint account of the parties as outlined in Exhibit “D”, attached to and made a part hereof. Operator shall require all contractors engaged in work on or for the Contract Area to comply with the workmen’s compensation law of the state where the operations are being conducted and to maintain such other insurance as Operator may require.

In the event automobile public liability insurance is specified in said Exhibit “D”, or subsequently receives the approval of the parties, no direct charge shall be made by Operator for premiums paid for such insurance for Operator’s automotive equipment.

ARTICLE VIII.

ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST

A.     Surrender of Leases:

The leases covered by this agreement, insofar as they embrace acreage in the Contract Area, shall not be surrendered in whole or in part unless all parties consent thereto.

However, should any party desire to surrender its interest in any lease or in any portion thereof, and the other parties do not agree or consent thereto, the party desiring to surrender shall assign, without express or implied warranty of title, all of its interest in such lease, or portion thereof, and any well, material and equipment which may be located thereon and any rights in production thereafter secured, to the parties not consenting to such surrender. If the interest of the assigning party is or includes an oil and gas interest, the assigning party shall execute and deliver to the party or parties not consenting to such surrender an oil and gas lease covering such oil and gas interest for a term of one (1) year and so long thereafter as oil and/or gas is produced from the land covered thereby, such lease to be on the form attached hereto as Exhibit “B”. Upon such assignment or lease, the assigning party shall be relieved from all obligations thereafter accruing, but not theretofore accrued, with respect to the interest assigned or leased and the operation of any well attributable thereto, and the assigning party shall have no further interest in the assigned or leased premises and its equipment and production other than the royalties retained in any lease made under the terms of this Article. The party assignee or lessee shall pay to the party assignor or lessor the reasonable salvage value of the latter’s interest in any wells and equipment attributable to the assigned or leased acreage. The value of all material shall be determined in accordance with the provisions of Exhibit “C”, less the estimated cost of salvaging and the estimated cost of plugging and abandoning. If the assignment or lease is in favor of more than one party, the interest shall be shared by such parties in the proportions that the interest of each bears to the total interest of all such parties.

Any assignment, lease or surrender made under this provision shall not reduce or change the assignor’s, lessor’s or surrendering party’s interest as it was immediately before the assignment, lease or surrender in the balance of the Contract Area; and the acreage assigned, leased or surrendered, and subsequent operations thereon, shall not thereafter be subject to the terms and provisions of this agreement.

B.     Renewal or Extension of Leases:

If any party secures a renewal of any oil and gas lease subject to this agreement, all other parties shall be notified promptly, and shall have the right for a period of thirty (30) days following receipt of such notice in which to elect to participate in the ownership of the renewal lease, insofar as such lease affects lands within the Contract Area, by paying to the party who acquired it their several proper proportionate shares of the acquisition cost allocated to that part of such lease within the Contract Area, which shall be in proportion to the interests held at that time by the parties in the Contract Area.

If some, but less than all, of the parties elect to participate in the purchase of a renewal lease, it shall be owned by the parties who elect to participate therein, in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all parties participating in the purchase of such renewal lease. Any renewal lease in which less than all parties elect to participate shall not be subject to this agreement.

Each party who participates in the purchase of a renewal lease shall be given an assignment of its proportionate interest therein by the acquiring party.

The provisions of this Article shall apply to renewal leases whether they are for the entire interest covered by the expiring lease or cover only a portion of its area or an interest therein. Any renewal lease taken before the expiration of its predecessor lease, or taken or contracted for within six (6) months after the expiration of the existing lease shall be subject to this provision; but any lease taken or contracted for more than six (6) months after the expiration of an existing lease shall not be deemed a renewal lease and shall not be subject to the provisions of this agreement.

The provisions in this Article shall also be applicable to extensions of oil and gas leases.

C.     Acreage or Cash Contributions:

While this agreement is in force, if any party contracts for a contribution of cash towards the drilling of a well or any other operation on the Contract Area, such contribution shall be paid to the party who conducted the drilling or other operation and shall be applied by it against the cost of such drilling or other operation. If the contribution be in the form of acreage, the party to whom the contribution is made shall promptly tender an assignment of the acreage, without warranty of title, to the Drilling Parties in the proportions

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said Drilling Parties shared the cost of drilling the well. Such acreage shall become a separate Contract Area and, to the extent possible, be governed by provisions identical to this agreement. Each party shall promptly notify all other parties of any acreage or cash contributions it may obtain in support of any well or any other operation on the Contract Area. The above provisions shall also be applicable to optional rights to earn acreage outside the Contract Area which are in support of a well drilled inside the Contract Area.

If any party contracts for any consideration relating to disposition of such party’s share of substances produced hereunder, such consideration shall not be deemed a contribution as contemplated in this Article VIII.C.

D.     Maintenance of Uniform Interests:

For the purpose of maintaining uniformity of ownership in the oil and gas leasehold interests covered by this agreement, no party shall sell, encumber, transfer or make other disposition of its interest in the leases embraced within the Contract Area and in wells, equipment and production unless such disposition covers either:

1.    the entire interest of the party in all leases and equipment and production; or

2.    an equal undivided interest in all leases and equipment and production in the Contract Area.

Every such sale, encumbrance, transfer or other disposition made by any party shall be made expressly subject to this agreement and shall be made without prejudice to the right of the other parties.

If, at any time the interest of any party is divided among and owned by four or more co-owners, Operator, at its discretion, may require such co-owners to appoint a single trustee or agent with full authority to receive notices, approve expenditures, receive billings for and approve and pay such party’s share of the joint expenses, and to deal generally with, and with power to bind, the co-owners of such party’s interest within the scope of the operations embraced in this agreement; however, all such co-owners shall have the right to enter into and execute all contracts or agreements for the disposition of their respective shares of the oil and gas produced from the Contract Area and they shall have the right to receive, separately, payment of the sale proceeds thereof.

E.     Waiver of Rights to Partition:

If permitted by the laws of the state or states in which the property covered hereby is located, each party hereto owning an undivided interest in the Contract Area waives any and all rights it may have to partition and have set aside to it in severalty its undivided interest therein.

F.     Preferential Right to Purchase:

Should any party desire to sell all or any part of its interests under this agreement, or its rights and interests in the Contract Area, it shall promptly give written notice to the other parties, with full information concerning its proposed sale, which shall include the name and address of the prospective purchaser (who must be ready, willing and able to purchase), the purchase price, and all other terms of the offer. The other parties shall then have an optional prior right, for a period of ten (10) days after receipt of the notice, to purchase on the same terms and conditions the interest which the other party proposes to sell; and, if this optional right is exercised, the purchasing parties shall share the purchased interest in the proportions that the interest of each bears to the total interest of all purchasing parties. However, there shall be no preferential right to purchase in those cases where any party wishes to mortgage its interests, or to dispose of its interests by merger, reorganization, consolidation, or sale of all or substantially all of its assets to a subsidiary or parent company or to a subsidiary of a parent company, or to any company in which any one party owns a majority of the stock.

ARTICLE IX.

INTERNAL REVENUE CODE ELECTION

This agreement is not intended to create, and shall not be construed to create, a relationship of partnership or an association for profit between or among the parties hereto. Notwithstanding any provision herein that the rights and liabilities hereunder are several and not joint or collective, or that this agreement and operations hereunder shall not constitute a partnership, if, for federal income tax purposes, this agreement and the operations hereunder are regarded as a partnership, each party hereby affected elects to be excluded from the application of all of the provisions of Subchapter “K”, Chapter 1, Subtitle “A”, of the Internal Revenue Code of 1954, as permitted and authorized by Section 761 of the Code and the regulations promulgated thereunder. Operator is authorized and directed to execute on behalf of each party hereby affected such evidence of this election as may be required by the Secretary of the Treasury of the United States or the Federal Internal Revenue Service, including specifically, but not by way of limitation, all of the returns, statements, and the data required by Federal Regulations 1.761. Should there be any requirement that each party hereby affected give further evidence of this election, each such party shall execute such documents and furnish such other evidence as may be required by the Federal Internal Revenue Service or as may be necessary to evidence this election. No such party shall give any notices or take any other action inconsistent with the election made hereby. If any present or future income tax laws of the state or states in which the Contract Area is located or any future income tax laws of the United States contain provisions similar to those in Subchapter “K”, Chapter 1, Subtitle “A”, of the Internal Revenue Code of 1954, under which an election similar to that provided by Section 761 of the Code is permitted, each party hereby affected shall make such election as may be permitted or required by such laws. In making the foregoing election, each such party states that the income derived by such party from operations hereunder can be adequately determined without the computation of partnership taxable income.

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ARTICLE X.

CLAIMS AND LAWSUITS

Operator may settle any single uninsured third party damage claim or suit arising from operations hereunder if the expenditure does not exceed Fifty-Thousand Dollars ($50,000.00) and if the payment is in complete settlement of such claim or suit. If the amount required for settlement exceeds the above amount, the parties hereto shall assume and take over the further handling of the claim or suit, unless such authority is delegated to Operator. All costs and expenses of handling, settling, or otherwise discharging such claim or suit shall be at the joint expense of the parties participating in the operation from which the claim or suit arises. If a claim is made against any party or if any party is sued on account of any matter arising from operations hereunder over which such individual has no control because of the rights given Operator by this agreement, such party shall immediately notify all other parties, and the claim or suit shall be treated as any other claim or suit involving operations hereunder. All claims or suits involving title to any interest subject to this agreement shall be treated as a claim or a suit against all parties hereto.

ARTICLE XI.

FORCE MAJEURE

If any party is rendered unable, wholly or in part, by force majeure to carry out its obligations under this agreement, other than the obligation to make money payments, that party shall give to all other parties prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, the obligations of the party giving the notice, so far as they are affected by the force majeure, shall be suspending during, but no longer than, the continuance of the force majeure. The affected party shall use all reasonable diligence to remove the force majeure situation as quickly as practicable.

The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor difficulty by the party involved, contrary to its wishes; how all such difficulties shall be handled shall be entirely within the discretion of the party concerned.

The term “force majeure”, as here employed, shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion, governmental action, governmental delay, restraint or inaction, unavailability of equipment, and any other cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of the party claiming suspension.

ARTICLE XII.

NOTICES

All notices authorized or required between the parties and required by any of the provisions of this agreement, unless otherwise specifically provided, shall be given in writing by mail or telegram, postage or charges prepaid, or by telex or telecopier and addressed to the parties to whom the notice is given at the addresses listed on Exhibit “A”. The originating notice given under any provision hereof shall be deemed given only when received by the party to whom such notice is directed, and the time for such party to give any notice in response thereto shall run from the date the originating notice is received. The second or any responsive notice shall be deemed given when deposited in the mail or with the telegraph company, with postage or charges prepaid, or sent by telex or telecopier. Each party shall have the right to change its address at any time, and from time to time, by giving written notice thereof to all other parties.

ARTICLE XIII.

TERM OF AGREEMENT

This agreement shall remain in full force and effect as to the oil and gas leases and/or oil and gas interests subject hereto for the period of time selected below; provided, however, no party hereto shall ever be construed as having any right, title or interest in or to any lease or oil and gas interest contributed by any other party beyond the term of this agreement.

x     Option No. 1: So long as any of the oil and gas leases subject to this agreement remain or are continued in force as to any part of the Contract Area, whether by production, extension, renewal, or otherwise.

o      Option No. 2: In the event the well described in Article VI.A., or any subsequent well drilled under any provision of this agreement, results in production of oil and/or gas in paying quantities, this agreement shall continue in force so long as any such well or wells produce, or are capable of production, and for an additional period of           days from cessation of all production; provided, however, if, prior to the expiration of such additional period, one or more of the parties hereto are engaged in drilling, reworking, deepening, plugging back, testing or attempting to complete a well or wells hereunder, this agreement shall continue in force until such operations have been completed and if production results therefrom, this agreement shall continue in force as provided herein. In the event the well described in Article VI.A., or any subsequent well drilled hereunder, results in a dry hole, and no other well is producing, or capable of producing oil and/or gas from the Contract Area, this agreement shall terminate unless drilling, deepening, plugging back or reworking operations are commenced within              days from the date of abandonment of said well.

It is agreed, however, that the termination of this agreement shall not relieve any party hereto from any liability which has accrued or attached prior to the date of such termination.

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ARTICLE XIV.

COMPLIANCE WITH LAWS AND REGULATIONS

A.Laws, Regulations and Orders:

This agreement shall be subject to the conservation laws of the state in which the Contract Area is located, to the valid rules, regulations, and orders of any duly constituted regulatory body of said state; and to all other applicable federal, state, and local laws, ordinances, rules, regulations, and orders.

B.Governing Law:

This agreement and all matters pertaining hereto, including, but not limited to, matters of performance, non-performance, breach, remedies, procedures, rights, duties, and interpretation or construction, shall be governed and determined by the law of the state in which the Contract Area is located. If the Contract Area is in two or more states, the law of the state of Ohio shall govern.

C.Regulatory Agencies:

Nothing herein contained shall grant, or be construed to grant, Operator the right or authority to waive or release any rights, privileges, or obligations which Non-Operators may have under federal or state laws or under rules, regulations or orders promulgated under such laws in reference to oil, gas and mineral operations, including the location, operation, or production of wells, on tracts offsetting or adjacent to the Contract Area.

With respect to operations hereunder, Non-Operators agree to release Operator from any and all losses, damages, injuries, claims and causes of action arising out of, incident to or resulting directly or indirectly from Operator’s interpretation or application of rules, rulings, regulations or orders of the Department of Energy or predecessor or successor agencies to the extent such interpretation or application was made in good faith. Each Non-Operator further agrees to reimburse Operator for any amounts applicable to such Non-Operator’s share of production that Operator may be required to refund, rebate or pay as a result of such an incorrect interpretation or application, together with interest and penalties thereon owing by Operator as a result of such incorrect interpretation or application.

Non-Operators authorize Operator to prepare and submit such documents as may be required to be submitted to the purchaser of any crude oil sold hereunder or to any other person or entity pursuant to the requirements of the “Crude Oil Windfall Profit Tax Act of 1980”, as same may be amended from time to time (“Act”), and any valid regulations or rules which may be issued by the Treasury Department from time to time pursuant to said Act. Each party hereto agrees to furnish any and all certifications or other information which is required to be furnished by said Act in a timely manner and in sufficient detail to permit compliance with said Act.

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ARTICLE XV.

OTHER PROVISIONS

A.  Liability of Parties:

The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs of developing and operating the Contract Area.  Accordingly, the liens granted among the parties in Article VII.B. are given to secure only the debts of each severally, and no party shall have any liability to third parties hereunder to satisfy the default of any other party in the payment of any expense or obligation hereunder.  It is not the intention of the parties to create, nor shall this agreement be construed as creating, a mining or other partnership, joint venture, agency relationship or association, or to render the parties liable as partners, co-venturers, or principals.  In their relations with each other under this agreement, the parties shall not be considered fiduciaries or to have established a confidential relationship but rather shall be free to act on an arm’s-length basis in accordance with their own respective self-interest, subject, however, to the obligation of the parties to act in good faith in their dealings with each other with respect to activities hereunder.

B.  Liens and Security Interests:

Each party grants to the other parties hereto a lien upon any interest it now owns or hereafter acquires in Oil and Gas Leases and Oil and Gas Interests in the Contract Area, and a security interest and/or purchase money security interest in any interest it now owns or hereafter acquires in the personal property and fixtures on or used or obtained for use in connection therewith, to secure performance of all of its obligations under this agreement including but not limited to payment of expense, interest and fees, the proper disbursement of all monies paid hereunder, the assignment or relinquishment of interest in Oil and Gas Leases as required hereunder, and the proper performance of operations hereunder.  Such lien and security interest granted by each party hereto shall include such party’s leasehold interests, working interests, operating rights, and royalty and overriding royalty interests in the Contract Area now owned or hereafter acquired and in lands pooled or unitized therewith or otherwise becoming subject to this agreement, the Oil and Gas when extracted therefrom and equipment situated thereon or used or obtained for use in connection therewith (including, without limitation, all wells, tools, and tubular goods), and accounts (including, without limitation, accounts arising from gas imbalances or from the sale of Oil and/or Gas at the wellhead), contract rights, inventory and general intangibles relating thereto or arising therefrom, and all proceeds and products of the foregoing.

To perfect the lien and security agreement provided herein, each party hereto shall execute and acknowledge the Memorandum of Operating Agreement supplement and/or any financing statement prepared and submitted by any party hereto in conjunction herewith or at any  time following execution hereof, and Operator is authorized to file this agreement or the recording supplement executed herewith as a lien or mortgage in the applicable real estate records and as a financing statement with the proper officer under the Uniform Commercial Code in the state in which the Contract Area is situated and such other states as Operator shall deem appropriate to perfect the security interest granted hereunder.  Any party may file this agreement, the recording supplement executed herewith, or such other documents as it deems necessary as a lien or mortgage in the applicable real estate records and/or a financing statement with the proper officer under the Uniform Commercial Code.

Each party represents and warrants to the other parties hereto that the lien and security interest granted by such party to the other parties shall be a first and prior lien, and each party hereby agrees to maintain the priority of said lien and security interest against all persons acquiring an interest in Oil and Gas Leases and Interests covered by this agreement by, through or under such party.  All parties acquiring an interest in Oil and Gas Leases and Oil and Gas Interests covered by this agreement, whether by assignment, merger, mortgage, operation of law, or otherwise, shall be deemed to have taken subject to the lien and security interest granted by this Article VII.B. as to all obligations attributable to such interest hereunder whether or not such obligations arise before or after such interest is acquired.

To the extent that parties have a security interest under the Uniform Commercial Code of the state in which the Contract Area is situated, they shall be entitled to exercise the rights and remedies of a secured party under the Code. The bringing of a suit and the obtaining of judgment by a party for the secured indebtedness shall not be deemed an election of remedies or otherwise affect the lien rights or security interest as security for the payment thereof.  In addition, upon default by any party in the payment of its share of expenses, interests or fees, or upon the improper use of funds by the Operator, the other parties shall have the right, without prejudice to other rights or remedies, to collect from the purchaser the proceeds from the sale of such defaulting party’s share of Oil and Gas until the amount owed by such party, plus interest as provided in “Exhibit C,” has been received, and shall have the right to offset the amount owed against the proceeds from the sale of such defaulting party’s share of Oil and Gas.  All purchasers of production may rely on a notification of default from the non-defaulting party or parties stating the amount due as a result of the default, and all parties waive any recourse available against purchasers for releasing production proceeds as provided in this paragraph.

If any party fails to pay its share of cost within one hundred twenty (120) days after rendition of a statement therefor by Operator, the non-defaulting parties, including Operator, shall upon request by Operator, pay the unpaid amount in the proportion that the interest of each such party bears to the interest of all such parties.  The amount paid by each party so paying its share of the unpaid amount shall be secured by the liens and security rights described in Article VII.B., and each paying party may independently pursue any remedy available hereunder or otherwise.

If any party does not perform all of its obligations hereunder, and the failure to perform subjects such party to foreclosure or execution proceedings pursuant to the provisions of this agreement, to the extent allowed by governing law, the defaulting party waives any available right of redemption from and after the date of judgment, any required valuation or appraisement of the mortgaged or secured property prior to sale, any available right to stay execution or to require a marshaling of assets and any required bond in the event a receiver is appointed.  In addition, to the extent permitted by applicable law, each party hereby grants to the other parties a power of sale as to any property that is subject to the lien and security rights granted hereunder, such power to be exercised in the manner provided by applicable law or otherwise in a commercially reasonable manner and upon reasonable notice.

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Each party agrees that the other parties shall be entitled to utilize the provisions of Oil and Gas lien law or other lien law of any state in which the Contract Area is situated to enforce the obligations of each party hereunder.  Without limiting the generality of the foregoing, to the extent permitted by applicable law, Non-Operators agree that Operator may invoke or utilize the mechanics’ or materialmen’s lien law of the state in which the Contract Area is situated in order to secure the payment to Operator of any sum due hereunder for services performed or materials supplied by Operator.

C.  Defaults and Remedies:

If any party fails to discharge any financial obligation under this agreement, including without limitation the failure to make any advance under the preceding Article VII.C. or any other provision of this agreement, within the period required for such payment hereunder, then in addition to the remedies provided in Article VII.B. or elsewhere in this agreement, the remedies specified below shall be applicable.  For purposes of this Article VII.D., all notices and elections shall be delivered only by Operator, except that Operator shall deliver any such notice and election requested by a non-defaulting Non-Operator, and when Operator is the party in default, the applicable notices and elections can be delivered by any Non-Operator. Election of any one or more of the following remedies shall not preclude the subsequent use of any other remedy specified below or otherwise available to a non-defaulting party.

1. Suspension of Rights: Any party may deliver to the party in default a Notice of Default, which shall specify the default, specify the action to be taken to cure the default, and specify that failure to take such action will result in the exercise of one or more of the remedies provided in this Article.  If the default is not cured within thirty (30) days of the delivery of such Notice of Default, all of the rights of the defaulting party granted by this agreement may upon notice be suspended until the default is cured, without prejudice to the right of the non-defaulting party or parties to continue to enforce the obligations of the defaulting party previously accrued or thereafter accruing under this agreement.  If Operator is the party in default, the Non-Operators shall have in addition the right, by vote of Non-Operators owning a majority in interest in the Contract Area after excluding the voting interest of Operator, to appoint a new Operator effective immediately.  The rights of a defaulting party that may be suspended hereunder at the election of the non-defaulting parties shall include, without limitation, the right to receive information as to any operation conducted hereunder during the period of such default, the right to elect to participate in an operation proposed under Article VI.B. of this agreement, the right to participate in an operation being conducted under this agreement even if the party has previously elected to participate in such operation, and the right to receive proceeds of production from any well subject to this agreement.

2. Suit for Damages: Non-defaulting parties or Operator for the benefit of non-defaulting parties may sue (at joint account expense) to collect the amounts in default, plus interest accruing on the amounts recovered from the date of default until the date of collection at the rate specified in Exhibit “C” attached hereto.  Nothing herein shall prevent any party from suing any defaulting party to collect consequential damages accruing to such party as a result of the default.

3. Deemed Non-Consent: The non-defaulting party may deliver a written Notice of Non-Consent Election to the defaulting party at any time after the expiration of the thirty-day cure period following delivery of the Notice of Default, in which event if the billing is for the drilling a new well or the Plugging Back, Sidetracking, Reworking or Deepening of a well which is to be or has been plugged as a dry hole, or for the Completion or Recompletion of any well, the defaulting party will be conclusively deemed to have elected not to participate in the operation and to be a Non-Consenting Party with respect thereto under Article VI.B. or VI.C., as the case may be, to the extent of the costs unpaid by such party, notwithstanding any election to participate theretofore made.  If election is made to proceed under this provision, then the non-defaulting parties may not elect to sue for the unpaid amount pursuant to Article VII.D.2.

Until the delivery of such Notice of Non-Consent Election to the defaulting party, such party shall have the right to cure its default by paying its unpaid share of costs plus interest at the rate set forth in Exhibit “C,” provided, however, such payment shall not prejudice the rights of the non-defaulting parties to pursue remedies for damages incurred by the non-defaulting parties as a result of the default.  Any interest relinquished pursuant to this Article VII.D.3. shall be offered to the non-defaulting parties in proportion to their interests, and the non-defaulting parties electing to participate in the ownership of such interest shall be required to contribute their shares of the defaulted amount upon their election to participate therein.

4. Advance Payment: If a default is not cured within thirty (30) days of the delivery of a Notice of Default, Operator, or

Non-Operators if Operator is the defaulting party, may thereafter require advance payment from the defaulting party of such defaulting party’s anticipated share of any item of expense for which Operator, or Non-Operators, as the case may be, would be entitled to reimbursement under any provision of this agreement, whether or not such expense was the subject of the previous default.  Such right includes, but is not limited to, the right to require advance payment for the estimated costs of drilling a well or Completion of a well as to which an election to participate in drilling or Completion has been made.  If the defaulting party fails to pay the required advance payment, the non-defaulting parties may pursue any of the remedies provided in the Article VII.D. or any other default remedy provided elsewhere in this agreement.  Any excess of funds advanced remaining when the operation is completed and all costs have been paid shall be promptly returned to the advancing party.

D.  Costs Associated with Use of Consultants:

Operator may charge the reasonable costs of consultants, including attorneys, necessary to secure regulatory permits and approvals for drilling wells, laying pipelines, collecting and discharging water and any other matters related to the project.

E.  Advances of Cost of Operations:

Notwithstanding the provisions of Article VII.C herein to the contrary, Operator may require from any other party advance payment, no more than 30 days prior to commencement of operations, within 15 days after billing, or within 48 hours after billing in the event of a proposed completion or in the event a drilling rig is on location, of such other party’s anticipated share of any item of expense for which the Operator would be entitled to reimbursement under any provision of this agreement.  Such right includes, but is not limited to, the right to require advance payment for the estimated costs of drilling a well or completion of a well as to which an election to participate in drilling or completion has been made.  For horizontal wells, the requirement for advance payment shall apply to a party’s share of both the drilling and the completion costs associated with the proposed well. Any amounts advanced by a Non-Operator hereunder in excess of that which is reasonably expected to be needed by Operator to complete the operations for which the funds were advanced shall be promptly refunded to such Non-Operator.

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F.  Operator Affiliates:

Notwithstanding the provisions of Article V. herein to the contrary, a party to this agreement that has been designated as the Operator under this Agreement (“Party”) may employ a subsidiary or affiliate to serve as Operator so long as the Party owns an interest in the Contract Area and is otherwise in compliance with the provisions of this Agreement. However, at such time as the Party sells its interest or no longer owns an interest in the Contract Area, the Party’s subsidiary or affiliate that is serving as Operator shall be deemed to have resigned just as if the Party had been serving as Operator. Furthermore, the Operator’s failure to observe or comply with the provisions of this Agreement may be applied and enforced against the Party just as if the Party was serving as the Operator. Therefore, the provisions of this Agreement may be enforced interchangeably between the Operator and the Party just as if they are one entity.

G. Operations Necessary to Maintain a Lease(s) in Force:

Notwithstanding the provisions of this Agreement and particularly Article VI, if any proposed operations are necessary to maintain a lease covered by this Agreement in force, or an agreement to earn a lease(s) which would otherwise expire unless such operations are conducted, then in addition to being penalized under Article VI.B.2. (a) and (b), each Non-Consenting Party shall assign to Consenting Parties all of such Non-Consenting Party’s right, title and interest in and to the lease(s) or portion thereof or such agreement which would be lost or not earned if such operations were not conducted. Such assignment shall be promptly due upon commencement of said proposed operations by Consenting Parties and if the assignment is in favor of more than one party the assigned interest shall be shared by the Consenting Parties unless otherwise agree to in writing. Thereafter, such acreage covered by said assignment shall not be subject to the terms of this Agreement, but shall be deemed to be subject to an agreement identical to this Agreement changed only in Exhibit “A” to indicate the Consenting Parties and their percentages. For purposes of defining necessary operations to maintain a lease or agreement to earn a lease(s) in force which would otherwise expire, such operations will be deemed necessary if proposed within six (6) months of the date the lease or agreement would otherwise expire.

H.Non-consent on Developed Properties:

In the event that a Party elects under Article VI.B, to non-consent any operation for any well(s) on a lease which has had prior development, and has, or has planned a separate tank battery or other necessary equipment, facilities or infrastructure that is required to separately account for the interests from the non-consent operation under Article VI.B.2(a), shall carry a penalty of 400%.

I.  Conflict of Terms:

In the event of a conflict between the typewritten portion and printed portions hereof in this Operating Agreement, the typewritten portions shall prevail.

In the event of a conflict between the provisions of this Article XV and any other provisions of the printed portions of the Operating Agreement, the provisions of this Article XV shall control and prevail.

J.  Metering of Production:

In the event of transfer, sale, encumbrance or other disposition of interest within the Contract Area which creates the necessity of separate measurement of production, the party creating the necessity for such separate measurement shall alone bear the cost of purchase, installation and operation of such facilities.

K.   Arbitration:

If any claim or controversy arises out of, or relates to, this Agreement, Operator and Non-Operators shall make a good faith attempt to resolve the matter through their senior management representatives, and said personnel of Operator and each Non-Operator shall meet in person and make a good faith attempt to resolve or settle the matter.  In the event that Operator and senior management of the Non-Operators cannot settle the claim or controversy, Operator and the Non-Operators agree to resolve or settle the matter in accordance with the rules of the American Arbitration Association then in effect including the sharing and payment of costs provided in said rules. If the rules do not address the sharing and payment of costs, then said costs shall be borne proportionately between Operator and the Non-Operators in accordance with their respective after payout interests.

The Arbitration shall be in Oklahoma City, Oklahoma, or such other place within the United States on which Operator and the Non-Operators agree, and shall be held before a disinterested third party arbitrator with a minimum of ten (10) years of experience, and qualified in the area under dispute, selected by mutual agreement of Operator and the Non-Operators. If the Non-Operators are unable to promptly agree upon an arbitrator, any Non-Operator may apply to the Senior Judge of the United States District Court for the Western District of Oklahoma who shall appoint such arbitrator.

Notwithstanding any provisions contained in the Rules of the American Arbitration Association, Operator and the Non-Operators shall, prior to any arbitration hearing, be entitled to discovery of all documents and information reasonably necessary for a full understanding of any legitimate issue raised in the arbitration. They may use all legal methods of discovery, including but not limited to depositions, requests for admissions, interrogatories and requests for production of documents. In addition thereto, Operator and/or any Non-Operator may use discovery for any matter or use any method of discovery allowed under the Federal Rules of Civil Procedure. The time period for compliance shall be set by the arbitrator, who may also set reasonable limits on the scope of such discovery. The decision of the arbitrator shall be in writing and include a statement of facts and conclusion of law and shall be final and binding upon Operator and the Non-Operators. Operator and the Non-Operators hereto consent to and do hereby submit to the jurisdiction of the Courts (Federal and State) of Garfield County, Oklahoma, for all purposes in connection with the arbitration, including the enforcement of the award and/or findings of the arbitrator.

L.   Additional Definitions (Continued from Article I):

1.	The term “lateral” shall mean that portion of a wellbore that deviates from approximate vertical orientation and all wellbore beyond such deviation to total depth.
2.	The term “horizontal well” shall mean a well containing a single lateral in which the wellbore deviates from approximate vertical orientation to approximate horizontal orientation in order to drill within and test a specific geological interval, utilizing deviation equipment, services, and technology. This shall include similar operations conducted in the re-entry of an existing wellbore.
3.	The term “multi-lateral well” shall mean a well which contains more than one lateral and in which the wellbores deviate from approximate vertical orientation to approximate horizontal orientation in order to drill within and test a specific geological interval, utilizing deviation equipment, services and technology. This shall include similar operations conducted in the re-entry of an existing wellbore.

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4.	The term “total depth” shall apply to all multi-lateral or horizontal wells drilled pursuant to this Agreement and shall mean the distance from the surface of the ground to the terminus of the wellbore. Each lateral together with the common vertical wellbore shall be considered a single wellbore and shall have a corresponding total depth if the production from each lateral is to be measured separately and not commingled in the vertical wellbore. If the production from each lateral is to be commingled in the common vertical wellbore then the lateral(s) and vertical wellbore shall be considered collectively as a single wellbore. When the proposed operation is the drilling of, or operations on, a well containing a lateral component, the term “depth” whenever used in this Agreement shall be deemed to read “total measured depth” insofar as it applies to such well.
5.	The term “deepen” when used in conjunction with a horizontal or multi-lateral well shall mean an operation whereby a lateral is drilled to a distance greater than the distance set out in Article VI.A.
6.	For the purposes of this Agreement, as to a horizontal or multi-lateral well, the term “plug back” shall mean an operation to test or complete the well at a stratigraphically shallower geological horizon in which an operation has been or is being completed and which is not within an existing lateral.

M.   Substitute Well Provision:

In the event any well drilled hereunder is lost for any reason prior to being drilled to the proposed total depth for such, or Operator has encountered during drilling mechanical conditions which would, in Operator’s opinion, make further drilling in any test well hereunder impracticable or inadvisable, Operator may abandon said test well and thereafter may commence operations for a substitute well for any such well (which has been lost or abandoned) within ninety (90) days after abandonment, to the same proposed total depth, drilled in the same quarter section (unless a different location is agreeable to both parties), and drilled subject to the same terms and conditions as the provided for the well so lost or abandoned. Such substitute well shall thereafter be considered as the originally proposed test well under this Agreement.

N.   Payment of Royalties:

Notwithstanding the provisions of Article III.B herein to the contrary, so long as the Drilling Unit for the productive Zone(s) is identical with the Contract Area, each party shall pay or deliver, or cause to be paid or delivered, all burdens on production from the Contract Area due under the terms of the Oil and Gas Lease(s) which such party has contributed to this agreement, and shall indemnify, defend and hold the other parties free from any liability therefore.

O.  Regulations:

Any state or Federal regulation, penalties and/or assessments which may be lawfully applied to Operator as the result of any action by said Operator in Operator’s conduct of the operations hereunder, shall be shared by the Operator and the Non-Operators in proportion to their interests as set forth in Exhibit “A” hereof provided there is no fraud, intentional misrepresentation or other act of gross negligence or willful misconduct by the Operator.

P. Priority of Operations:

Where a well, authorized under the terms of this Agreement by all parties (or by less than all parties under Article VI.B.2) and the parties participating in the well cannot agree upon the sequence and timing of further operations regarding the well, the following elections shall control in the order enumerated below:

1.Prior to reaching the objective depth or zone:

a.Drilling the well to its objective depth.

b.In the event that impenetrable conditions or mechanical difficulties prevent reaching the objective depth or zone, a proposal to sidetrack in an effort to reach the objective depth or zone shall have priority over a proposal to attempt a completion in a zone already reached.

2.After the objective depth or zone has been reached:

a.an election to conduct additional logging, coring or testing;

b.an election to attempt to complete the well at the objective depth or zone;

c.an election to deepen the well;

d.an election to plug back and attempt to complete the well;

e.an election to sidetrack the well;

f.an election to plug and abandon the well;

It is provided however, that if at the time said participating parties are considering any of the above elections the hole is in such a condition that a reasonably prudent operator would not conduct the operations contemplated by the particular election involved for fear of placing the hole or objective formation in jeopardy, such election shall be eliminated from the sequence set forth above.

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ARTICLE XVI.

MISCELLANEOUS

This agreement shall be binding upon and shall inure to the benefit of the parties hereto and to their respective heirs, devisees, legal representatives, successors and assigns.

This instrument may be executed in any number of counterparts, each of which shall be considered an original for all purposes.

IN WITNESS WHEREOF, this agreement shall be effective as of 6thday of May, (year) 2011. Gulfport Energy Corporation, who has prepared and circulated this form for execution, represents and warrants that the form was printed from and with the exception listed below, is identical to the AAPL Form 610-1982 Model Form Operating Agreement, as published in computerized form by Forms On-A-Disk, Inc. No changes, alterations, or modifications, other than those in Articles amended herein, have been made to the form.

	OPERATOR
	Gulfport Energy Corporation
	/s/ James D. Palm
	By: James D. Palm
	Title: CEO
	NON-OPERATORS
Windsor Ohio, LLC	Rhino Exploration, L.L.C.
/s/ Paul Jacobi	/s/ David G. Zatezalo
By: Paul Jacobi	By: David G. Zatezalo
Title: Vice President	Title: President and CEO

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EXHIBIT “A”

Attached to and made a part of that certain Joint Operating Agreement by and between Gulfport Energy Corporation, as Operator and Windsor Ohio LLC and Rhino Exploration L.L.C., as Non-Operators dated May 6, 2011.

1.Contract Area

2.Restrictions, if any, as to depths formations or substances are those set forth in the Oil and Gas Leases of Assignments of Record.

3.Percentage of interest to the parties to this Agreement:

Working Interest:

Gulfport Energy Corporation	50.0000	%
Windsor Ohio LLC	45.0000	%
Rhino Exploration LLC	5.0000	%
Total	100.0000	%

4.Oil and gas leases subject to this Agreement:

To be described for each prospect area.

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5.Addresses of the parties to this agreement:

Gulfport Energy Corporation

14313 N. May Avenue, Suite 100

Oklahoma City, OK 73134

Fax: (405) 848-8816

Windsor Ohio LLC

14301 Caliber Dr., Suite 300

Oklahoma City, OK 73134

Fax: (405) 286-5927

Rhino Exploration LLC

424 Lewis Hargett Circle, Suite 250

Lexington, KY 40503

Fax: (859)-389-6588

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EX-31.1

Exhibit 31.1

CERTIFICATION

I, David G. Zatezalo, certify that:

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

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

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

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

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

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

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

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

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

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

Date: November 9, 2012

/s/ David G. Zatezalo

David G. Zatezalo

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard A. Boone, certify that:

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

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

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

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

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

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

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

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

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

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

Date: November 9, 2012

/s/ Richard A. Boone

Richard A. Boone

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

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

In connection with this Quarterly Report on Form 10-Q of Rhino Resource Partners LP for the quarter ended September 30, 2012, I, David G. Zatezalo, President and Chief Executive Officer of Rhino GP LLC, the general partner of Rhino Resource Partners LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Quarterly Report Form 10-Q for the quarter ended September 30, 2012 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 fairly presents, in all material respects, the financial condition and results of operations of Rhino Resource Partners LP for the periods presented therein.

Date: November 9, 2012

/s/ David G. Zatezalo

David G. Zatezalo

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

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

In connection with this quarterly report on Form 10-Q of Rhino Resource Partners LP for the quarter ended September 30, 2012, I, Richard A. Boone, Senior Vice President and Chief Financial Officer of Rhino GP LLC, the general partner of Resource Partners LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 fairly presents, in all material respects, the financial condition and results of operations of Rhino Resource Partners LP for the periods presented therein.

Date: November 9, 2012

/s/ Richard A. Boone

Richard A. Boone

Senior Vice President and Chief Financial Officer

EX-95.1

Exhibit 95.1

Federal Mine Safety and Health Act Information

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). The following disclosures respond to that legislation.

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

Responding to the Dodd-Frank Act legislation, we report that, for the three months ended September 30, 2012, none of our 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. In addition, none of our subsidiaries suffered any mining related fatalities during the three months ended September 30, 2012.

The following table sets out information required by the Dodd-Frank Act for the three months ended September 30, 2012. The mine data retrieval system maintained by MSHA may show information that is different than what is provided herein.  Any such difference may be attributed to the need to update that information on MSHA’s system and/or other factors. The table also displays pending legal actions before the Federal Mine Safety and Health Review Commission (the “Commission”) that were initiated during the three months ended September 30, 2012 as well as total pending legal actions that were pending before the Commission as of September 30, 2012, which includes the legal proceedings before the Commission as well as all contests of citations and penalty assessments which are not before an administrative law judge. All of these pending legal actions constitute challenges by us of citations issued by MSHA. Since none of our subsidiaries received notice from MSHA of either a pattern of violations of mandatory health or safety standards under section 104(e) of the Mine Act, or the potential to have such a pattern, and none of our subsidiaries suffered any fatalities during the three months ended September 30, 2012, the columns that would normally display this information in the table below have been omitted for ease of presentation.

For the three months ended September 30, 2012

Company	Mine(1)	MSHA ID	104(a)S & S (2)	104 (b)(3)	104 (d)(4)	107 (a)(5)	110 (b)(2)(6)	Proposed Assessments(7)		Pending Legal Proceedings(8)	Legal Proceedings Initiated	Legal Proceedings Resolved
Hopedale Mining LLC	Hopedale Mine	33-00968	10	0	0	0	0	$	2,724	3	0	0
	Nelms Plant	33-04187	0	0	0	0	0	$	—	0	0	0
Sands Hill Mining LLC	Big Valley Mine	33-01358	1	0	0	0	0	$	—	0	0	0
	Kanauga Dock	33-02044	0	0	0	0	0	$	—	0	0	0
	Clinton Stone	33-04041	0	0	0	0	0	$	—	0	0	0
CAM/Deane Mining LLC	Access Energy	15-19532	1	0	0	0	0	$	876	0	0	0
	Mine #28	15-18911	4	0	0	0	0	$	5,609	0	2	1
	Deane #1	15-18569	0	0	0	0	0	$	—	0	0	0
	Love Branch	15-19191	0	0	0	0	0	$	—	0	0	0
	Bevins Branch	15-18570	4	0	0	0	0	$	—	0	0	0
	Marion Branch	15-18100	0	0	0	0	0	$	—	0	0	0
	Three Mile Mine #1	15-17659	0	0	0	0	0	$	—	0	0	0
	Grapevine South	46-08930	1	0	0	0	0	$	—	0	0	1
	Remining No. 3	46-09345	1	0	0	0	0	$	—	0	0	0
	Rob Fork Processing	15-14468	0	0	0	0	0	$	300	0	0	1
	Jamboree Loadout	15-12896	0	0	0	0	0	$	—	0	0	0
	Mill Creek Prep Plant	15-16577	0	0	0	0	0	$	—	0	0	0
	Tug Fork Plant	46-08626	0	0	0	0	0	$	—	0	0	0
	Rhino Trucking	Q569	0	0	0	0	0	$	—	0	0	0
	Rhino Reclamation Services	R134	0	0	0	0	0	$	—	0	0	0
	Rhino Services	S359	0	0	0	0	0	$	—	0	0	0
	Rhino Oilfields	X663	0	0	0	0	0	$	—	0	0	0
	Cam Mining	T075	0	0	0	0	0	$	—	0	0	0
McClane Canyon Mining LLC	McClane Canyon Mine	05-03013	1	0	0	0	0	$	562	0	0	0
Castle Valley Mining LLC	Castle Valley Mine #3	42-02263	0	0	0	0	0	$	—	0	0	0
	Castle Valley Mine #4	42-02335	1	0	0	0	0	$	687	0	0	0
	Bear Canyon Loading Facility	42-02395	0	0	0	0	0	$	—	0	0	0
Total			24	0	0	0	0	$	10,758	3	2	3

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

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

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

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

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

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

(7) Total dollar value of MSHA assessments proposed during the three months ended September 30, 2012.

(8) Any pending legal action before the Federal Mine Safety and Health Review Commission (the “Commission”) involving a coal mine owned and operated by us.  The number of legal actions pending as of September 30, 2012 that fall into each of the following categories is as follows:

(a)Contests of citations and orders:

(b)Contests of proposed penalties:

(c)Complaints for compensation under Section 111 of the Mine Act:

(d)Complaints of discharge, discrimination or interference under Section 105 of the Mine Act:

(e)Applications for temporary relief under Section 105(b)(2) of the Mine Act:

(f)Appeals of judges’ decisions or orders to the Commission:

XML

Basis Of Presentation And Organization (Details) (USD $)	0 Months Ended	9 Months Ended
	Jul. 18, 2011	Sep. 30, 2012 item	Sep. 30, 2011
Subsidiary, Sale of Stock [Line Items]
Number of underground mines temporarily idle		1
Limited partnership common units issued	2,875,000
Limited partnership common units price	$ 24.50
Proceeds from issuance of common units			$ 66,916,000
Underwriting discounts and offering expenses	4,100,000
Partner contributions	1,400,000	7,000	1,444,000
Repayments of credit facility	67,800,000
Underwriters Option To Purchase Additional Units [Member]
Subsidiary, Sale of Stock [Line Items]
Limited partnership common units issued	375,000
After Deducting Underwriting Discounts And Offering Expenses [Member]
Subsidiary, Sale of Stock [Line Items]
Proceeds from issuance of common units	$ 66,400,000

XML

Other Non-Current Assets (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Deposits and other	$ 2,470,000	$ 2,481,000
Debt issuance costs - net	4,119,000	4,925,000
Deferred expenses	19,000	27,000
Total	6,608,000	7,433,000
Debt issuance costs, gross	8,000,000	8,000,000
Accumulated amortization of debt issuance costs	$ 3,900,000	$ 3,100,000

XML

Property, Plant And Equipment (Property, Plant And Equipment By Major Classification) (Details) (USD $) In Thousands, unless otherwise specified															9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Land And Land Improvements [Member]	Dec. 31, 2011 Land And Land Improvements [Member]	Sep. 30, 2012 Mining And Other Equipment And Related Facilities [Member]	Dec. 31, 2011 Mining And Other Equipment And Related Facilities [Member]	Sep. 30, 2012 Mine Development Costs [Member]	Dec. 31, 2011 Mine Development Costs [Member]	Sep. 30, 2012 Coal Properties [Member]	Dec. 31, 2011 Coal Properties [Member]	Sep. 30, 2012 Oil And Gas Properties [Member]	Dec. 31, 2011 Oil And Gas Properties [Member]	Sep. 30, 2012 Construction Work In Process [Member]	Dec. 31, 2011 Construction Work In Process [Member]	Sep. 30, 2012 Minimum [Member] Mining And Other Equipment And Related Facilities [Member]	Sep. 30, 2012 Minimum [Member] Mine Development Costs [Member]	Sep. 30, 2012 Minimum [Member] Coal Properties [Member]	Sep. 30, 2012 Maximum [Member] Mining And Other Equipment And Related Facilities [Member]	Sep. 30, 2012 Maximum [Member] Mine Development Costs [Member]	Sep. 30, 2012 Maximum [Member] Coal Properties [Member]
Property, Plant and Equipment [Line Items]
Useful Lives															2 years	1 year	1 year	20 years	15 years	15 years
Total	$ 676,370	$ 637,563	$ 36,924	$ 33,298	$ 285,855	$ 244,819	$ 65,571	$ 65,824	$ 239,140	$ 238,355	$ 31,164	$ 27,964	$ 17,716	$ 27,303
Less accumulated depreciation, depletion and amortization	(209,932)	(187,447)
Net property, plant and equipment	$ 466,438	$ 450,116

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Segment Information (Reportable Segment Results Of Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Segment Reporting Information [Line Items]
Total revenues	$ 93,575	$ 93,564	$ 265,455	$ 266,195
DD&A	10,065	9,157	30,912	26,513
Interest expense	2,105	1,850	5,889	4,274
Net income (loss)	8,876	9,846	30,846	25,359
Central Appalachia [Member]
Segment Reporting Information [Line Items]
Total revenues	51,428	53,443	135,607	158,092
DD&A	6,165	5,550	19,801	15,948
Interest expense	1,212	691	3,340	1,640
Net income (loss)	(143)	3,904	812	10,336
Northern Appalachia [Member]
Segment Reporting Information [Line Items]
Total revenues	29,939	32,568	94,298	90,306
DD&A	2,189	1,992	6,154	6,177
Interest expense	221	675	620	1,429
Net income (loss)	6,123	6,313	23,199	18,036
Rhino Western [Member]
Segment Reporting Information [Line Items]
Total revenues	10,621	6,044	30,767	13,065
DD&A	1,217	857	3,323	2,117
Interest expense	201	201	546	360
Net income (loss)	1,891	(427)	4,750	(2,327)
Complete Basis [Member] | Eastern Met [Member]
Segment Reporting Information [Line Items]
Total revenues	16,296	14,323	49,133	37,093
DD&A	508	754	1,630	2,328
Interest expense	16	32	155	49
Net income (loss)	3,558	2,466	12,312	6,193
Equity Method Eliminations [Member] | Eastern Met [Member]
Segment Reporting Information [Line Items]
Total revenues	(16,296)	(14,323)	(49,133)	(37,093)
DD&A	(508)	(754)	(1,630)	(2,328)
Interest expense	(16)	(32)	(155)	(49)
Net income (loss)	(1,743)	(1,208)	(6,106)	(3,035)
Equity Method Presentation [Member] | Eastern Met [Member]
Segment Reporting Information [Line Items]
Net income (loss)	1,815	1,258	6,206	3,158
Other [Member]
Segment Reporting Information [Line Items]
Total revenues	1,587	1,509	4,783	4,732
DD&A	494	758	1,634	2,271
Interest expense	471	283	1,383	845
Net income (loss)	$ (810)	$ (1,202)	$ (4,121)	$ (3,844)

XML

Accrued Expenses And Other Current Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Accrued Expenses And Other Current Liabilities [Abstract]
Payroll, bonus and vacation expense	$ 3,992	$ 4,128
Non income taxes	4,314	3,950
Royalty expenses	2,860	2,489
Accrued interest	646	797
Health claims	1,538	1,386
Workers' compensation & pneumoconiosis	1,690	1,690
Deferred revenues	2,490	1,967
Other	2,444	3,284
Total	$ 19,974	$ 19,691

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Prepaid Expenses And Other Current Assets (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other prepaid expenses	$ 672	$ 577
Prepaid insurance	2,360	1,526
Prepaid leases	150	103
Supply inventory	1,265	1,951
Deposits	321	170
Total Prepaid expenses and other	$ 4,768	$ 4,327

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2012

Asset Retirement Obligations [Abstract]

Schedule Of Asset Retirement Obligations

	Nine months ended September 30, 2012	Year ended December 31, 2011
	(in thousands)
Balance at beginning of period (including current portion)	$                            34,113	$                            35,691
Accretion expense	1,305	1,956
Adjustment resulting from addition of property	-	2,707
Adjustment resulting from disposal of property	(271)	(3,588)
Adjustments to the liability from annual recosting and other	-	(617)
Liabilities settled	(1,269)	(2,036)
Balance at end of period	33,878	34,113
Current portion of asset retirement obligation	3,409	3,192
Long-term portion of asset retirement obligation	$                            30,469	$                            30,921

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Debt (Note Payable To H&L Construction) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Debt [Abstract]
Imputed interest discount rate	5.00%
Mineral rights owned and pledged as collateral, carrying amount	$ 11.4	$ 11.6
Note payable maturity date	Jan. 01, 2015

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Segment Information (Equity Method Investments, Summarized Financial Information) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Segment Information [Abstract]
Total costs and expenses	$ 12,733	$ 11,825	$ 36,676	$ 30,851
Income from operations	$ 3,563	$ 2,498	$ 12,457	$ 6,242

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Summary Of Significant Accounting Polcies And General (Policies)

9 Months Ended

Sep. 30, 2012

Summary Of Significant Accounting Policies And General [Abstract]

Investment In Joint Venture

Investment in Joint Venture.  Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Partnership is determined to be the primary beneficiary of a variable interest entity. Equity investments are recorded at original cost and adjusted periodically to recognize the Partnership’s proportionate share of the investees’ net income or losses after the date of investment. Any losses from the Partnership’s equity method investment are absorbed by the Partnership based upon its proportionate ownership percentage. If losses are incurred that exceed the Partnership’s investment in the equity method entity, then the Partnership must continue to record its proportionate share of losses in excess of its investment. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.

In May 2008, the Operating Company entered into a joint venture, Rhino Eastern LLC (“Rhino Eastern”), with an affiliate of Patriot Coal Corporation (“Patriot”) to acquire the Eagle mining complex. To initially capitalize the joint venture, the Operating Company contributed approximately $16.1 million for a 51% ownership interest in the joint venture and accounts for the investment in the joint venture and its results of operations under the equity method. The Partnership considers the operations of this entity to comprise a reporting segment (“Eastern Met”) and has provided additional detail related to this operation in Note 18, “Segment Information.” As of September  30, 2012 and December 31, 2011, the Partnership has recorded its Rhino Eastern equity method investment of $22.0 million and $18.7 million, respectively, as a long-term asset. During the nine months ended September 30, 2012, the Partnership provided loans to the Rhino Eastern joint venture in the amount of  $11.9 million, which were fullyrepaid as of September 30, 2012.

On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

In March 2012, the Partnership made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf, with affiliates of Wexford Capital LP (“Wexford Capital”).  Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio.  The initial investment was the Partnership’s proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during the nine months ended September 30, 2012 and the Partnership will initially include any operating activities of Timber Wolf in its Other category.

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Goodwill And Intangible Assets (Narrative) (Details) (USD $)			9 Months Ended		12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Patent And Developed Technology [Member]	Sep. 30, 2012 Trade Name And Customer List [Member]	Dec. 31, 2011 Elk Horn Coal Company [Member} Trade Name [Member]	Dec. 31, 2011 Elk Horn Coal Company [Member} Customer List [Member]	Sep. 30, 2012 Sale Of Triad Operations [Member]	Aug. 31, 2012 Sale Of Triad Operations [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Intangible assets, useful life			17 years	20 years
Acquired intangible asset value					$ 184,000	$ 470,000
Goodwill		$ 202,000					$ 0	$ 200,000

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Business Combinations And Other Acquisitions (Summary Of Assets Acquired And Liabilities Assumed) (Details) (Elk Horn Coal Company [Member}, USD $) In Thousands, unless otherwise specified	Jun. 30, 2011
Elk Horn Coal Company [Member}
Business Acquisition [Line Items]
Cash	$ 58
Accounts receivable	2,619
Prepaid expenses and other	94
Property, plant and equipment	7,056
Mine development costs	3,000
Coal properties	112,057
Intangible assets	654
Other non-current assets	1,112
Accounts payable	(79)
Deferred revenues	(2,499)
Accrued expenses and other	(1,691)
Asset retirement obligations	(2,707)
Net assets acquired	119,674
Total consideration	$ 119,674

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Major Customers (Tables)

9 Months Ended

Sep. 30, 2012

Major Customers [Abstract]

Major Customers

	September 30,	Nine months	Nine months
	2012	ended	ended
	Receivable	September 30,	September 30,
	Balance	2012 Sales	2011 Sales
	(in thousands)
GenOn Energy, Inc.	$                   5,352	$                 38,847	$                 44,178
Indiana Harbor Coke Company, L.P	4,652	28,806	29,812
PPL Corporation	3,042	30,553	n/a
American Electric Power Company, Inc.	3,271	26,683	34,273

XML

Goodwill And Intangible Assets (Schedule Of Intangible Assets By Major Class) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 1,460	$ 1,460
Accumulated Amortization	212	152
Net Carrying Amount	1,248	1,308
Patent [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	728	728
Accumulated Amortization	153	121
Net Carrying Amount	575	607
Developed Technology [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	78	78
Accumulated Amortization	16	13
Net Carrying Amount	62	65
Trade Name [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	184	184
Accumulated Amortization	12	5
Net Carrying Amount	172	179
Customer List [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	470	470
Accumulated Amortization	31	13
Net Carrying Amount	$ 439	$ 457

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Major Customers (Details) (USD $) In Thousands, unless otherwise specified			9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 GenOn Energy, Inc. [Member]	Sep. 30, 2011 GenOn Energy, Inc. [Member]	Sep. 30, 2012 Indiana Harbor Coke Company, L.P. [Member]	Sep. 30, 2011 Indiana Harbor Coke Company, L.P. [Member]	Sep. 30, 2012 PPL Corporation [Member]	Sep. 30, 2012 American Electric Power Company, Inc. [Member]	Sep. 30, 2011 American Electric Power Company, Inc. [Member]
Revenue, Major Customer [Line Items]
Receivable balance	$ 37,227	$ 37,242	$ 5,352		$ 4,652		$ 3,042	$ 3,271
Sales			$ 38,847	$ 44,178	$ 28,806	$ 29,812	$ 30,553	$ 26,683	$ 34,273

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Employee Benefits (Schedule Of Expense Under Defined Contribution Savings Plans) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Employee Benefits [Abstract]
401(k) plan expense	$ 580	$ 583	$ 1,743	$ 1,652

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Property, Plant And Equipment (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended			1 Months Ended		0 Months Ended	1 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Aug. 31, 2012 Sale Of Triad Operations [Member]	Sep. 30, 2012 Sale Of Triad Operations [Member]	Feb. 29, 2012 Pike County Kentucky [Member] Sale Of Mining Assets [Member]	Aug. 31, 2011 Phelps Kentucky [Member] Sale Of Mining Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of other assets								$ 600,000	$ 20,000,000
Gain on disposition of assets	1,185,000	2,702,000	2,176,000	2,836,000		200,000		900,000	2,400,000
Gain contingency unrecorded amount									8,750,000
Proceeds from sale of business						500,000
Goodwill					$ 202,000	$ 200,000	$ 0

XML

Prepaid Expenses And Other Current Assets

9 Months Ended

Sep. 30, 2012

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Prepaid Expenses And Other Current Assets

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS 

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

	September 30,	December 31,
	2012	2011
	(in thousands)
Other prepaid expenses	$                      672	$                      577
Prepaid insurance	2,360	1,526
Prepaid leases	150	103
Supply inventory	1,265	1,951
Deposits	321	170
Total Prepaid expenses and other	$                   4,768	$                   4,327

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Equity-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	9 Months Ended
	Mar. 31, 2012	Sep. 30, 2011	Sep. 30, 2012
Equity-Based Compensation [Abstract]
Phantom units granted	20,664
Vesting period	3 years
Total fair value of awards granted	$ 0.4
Fair value of awards			0.3
Share based compensation expense		$ 0.2

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Business Combinations And Other Acquisitions (Business Acquisition, Pro Forma Information) (Details) (Elk Horn Coal Company [Member}, USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011
Business Acquisition [Line Items]
Revenues	$ 93,564	$ 266,195
Net Income	9,846	25,359
Net income per limited partner unit, diluted	$ 0.36	$ 0.98
Pro Forma Adjustments [Member]
Business Acquisition [Line Items]
Revenues		9,477
Net Income	(26)	3,076
Net income per limited partner unit, diluted	$ (0.01)	$ 0.03
Pro Forma [Member]
Business Acquisition [Line Items]
Revenues	93,564	275,672
Net Income	$ 9,820	$ 28,435
Net income per limited partner unit, diluted	$ 0.35	$ 1.01

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Goodwill And Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2012

Goodwill And Intangible Assets [Abstract]

Schedule Of Goodwill

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

Schedule Of Intangible Assets By Major Class

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

	Gross		Net
	Carrying	Accumulated	Carrying
Intangible Asset	Amount	Amortization	Amount
	(in thousands)
Patent	$              728	$              153	$              575
Developed Technology	78	16	62
Trade Name	184	12	172
Customer List	470	31	439
Total	$           1,460	$              212	$           1,248

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

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

Future Amortization Expense

		Developed		Customer
	Patent	Technology	Trade Name	List	Total
	(in thousands)
2012 (from Oct 1 to Dec 31)	$                  11	$                    1	$                    2	$             6	$           20
2013	43	5	9	23	80
2014	43	5	9	23	80
2015	43	5	9	23	80
2016	43	5	9	23	80

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Property, Plant And Equipment (Tables)

9 Months Ended

Sep. 30, 2012

Property, Plant And Equipment [Abstract]

Property, Plant And Equipment By Major Classification

	Useful Lives	September 30, 2012	December 31, 2011
		(in thousands)
Land and land improvements		$        36,924	$         33,298
Mining and other equipment and related facilities	2 - 20 Years	285,855	244,819
Mine development costs	1 - 15 Years	65,571	65,824
Coal properties	1 - 15 Years	239,140	238,355
Oil and gas properties		31,164	27,964
Construction work in process		17,716	27,303
Total		676,370	637,563
Less accumulated depreciation, depletion and amortization		(209,932)	(187,447)
Net		$      466,438	$       450,116

Depreciation, Depletion, And Amortization

	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$           7,950	$           6,488	$         24,414	$         19,769
Depletion expense for coal properties	1,440	1,510	4,361	3,358
Amortization expense for mine development costs	526	809	1,650	2,358
Amortization expense for intangible assets	20	12	60	36
Amortization expense for asset retirement costs	129	338	427	992
Total depreciation, depletion and amortization	$         10,065	$           9,157	$         30,912	$         26,513

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Debt (Senior Secured Credit Facility With PNC Bank, N.A.) (Narrative) (Details) (USD $)			1 Months Ended	9 Months Ended							1 Months Ended	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Jun. 30, 2011 PNC Bank, N.A. [Member]	Sep. 30, 2012 PNC Bank, N.A. [Member]	Sep. 30, 2012 Letters of Credit [Member] PNC Bank, N.A. [Member]	Jul. 31, 2011 Letters of Credit [Member] PNC Bank, N.A. [Member]	Sep. 30, 2012 Credit Facility LIBOR Plus Applicable Spread [Member] PNC Bank, N.A. [Member]	Sep. 30, 2012 Credit Facility PRIME Plus Applicable Spread [Member] PNC Bank, N.A. [Member]	Jun. 30, 2011 Before Exercising Option To Increase Borrowing Capacity [Member] PNC Bank, N.A. [Member]	Jun. 30, 2011 After Exercising Option To Increase Borrowing Capacity [Member] PNC Bank, N.A. [Member]	Jul. 31, 2011 Amended And Restated [Member] PNC Bank, N.A. [Member]	Sep. 30, 2012 Amended And Restated [Member] PNC Bank, N.A. [Member]
Line of Credit Facility [Line Items]
Credit facility, maximum available						$ 75,000,000			$ 200,000,000	$ 250,000,000	$ 300,000,000
Line of credit facility increase in maximum borrowing capacity			50,000,000
Line of credit facility option to increase maximum borrowing capacity											50,000,000
Debt issuance costs			1,000,000								2,800,000
Line of credit facility, expiration date												Jul. 01, 2016
Line of credit facility, amount outstanding	163,530,000	137,000,000					162,000,000	1,500,000
Incremental interest rate above variable rate							2.75%	1.75%
Effective interest rate	5.00%						2.98%	5.00%
Long-term debt, percentage bearing fixed interest, percentage					2.75%
Outstanding letters of credit					23,200,000
Maximum borrowing capacity measured as a multiple of EBITDA				300.00%
EBITDA measurement period for determining maximum borrowing capacity				12 months
Line of credit facility, remaining borrowing capacity				$ 78,000,000

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Business Combinations And Other Acquisitions (Acquisition Of Oil And Gas Mineral Rights) (Details) (USD $)	3 Months Ended		9 Months Ended			12 Months Ended	0 Months Ended		3 Months Ended	4 Months Ended	9 Months Ended	0 Months Ended	9 Months Ended						3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Utica Shale [Member]	Dec. 31, 2011 Cana Woodford Region Of Oklamoma [Member]	Mar. 13, 2012 Utica Shale Region Of Ohio [Member]	Mar. 06, 2012 Utica Shale Region Of Ohio [Member] acre	Jun. 30, 2012 Utica Shale Region Of Ohio [Member]	Jun. 30, 2012 Utica Shale Region Of Ohio [Member]	Sep. 30, 2012 Utica Shale Region Of Ohio [Member]	Mar. 06, 2012 Down Payment At Lease Signing [Member] Utica Shale Region Of Ohio [Member]	Sep. 30, 2012 Lease Bonus Payments [Member] Utica Shale Region Of Ohio [Member]	Sep. 30, 2012 Exchange Transaction [Member] acre	Sep. 30, 2012 Expected Ultimate Net Interest [Member] acre	Jun. 30, 2012 Subject To Lease [Member] Utica Shale Region Of Ohio [Member] acre	Sep. 30, 2012 Subject To Title Restrictions [Member] Utica Shale Region Of Ohio [Member] acre	Dec. 31, 2011 Joint Investment With Affiliate Of Wexford Capital [Member] acre	Sep. 30, 2012 Oil And Gas Properties [Member]	Sep. 30, 2012 Oil And Gas Properties [Member]
Acquisition Of Oil And Gas Mineral Rights [Line Items]
Acquisition of mineral rights						$ 8,100,000
Ownership interest in Gulfport Energy by an affiliate of Wexford Capital, percentage							9.50%
Other revenues	8,063,000	10,028,000	34,849,000	17,710,000					6,900,000	7,400,000		500,000	7,400,000
Ownership interest in joint venture														10.80%	5.00%			10.80%
Acres subject to lease agreement								1,500						125,000	6,250	1,232	250	80,000
Cumulative investment in pro rata interest in oil and gas leases					22,800,000
Payments to acquire property, plant and equipment			53,347,000	64,606,000															3,200,000	3,200,000
Capitalized drilling costs											$ 3,200,000
Lease term								5 years
Lease renewal term								3 years
Lease bonus per acre								6,000
Royalty percentage											20.00%

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Other Non-Current Assets (Tables)

9 Months Ended

Sep. 30, 2012

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Non-Current Assets

	September 30,	December 31,
	2012	2011
	(in thousands)
Deposits and other	$                2,470	$                2,481
Debt issuance costs—net	4,119	4,925
Deferred expenses	19	27
Total	$                6,608	$                7,433

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Accrued Expenses And Other Current Liabilities (Tables)

9 Months Ended

Sep. 30, 2012

Accrued Expenses And Other Current Liabilities [Abstract]

Accrued Expenses And Other Current Liabilities

	September 30,	December 31,
	2012	2011
	(in thousands)
Payroll, bonus and vacation expense	$                3,992	$                4,128
Non income taxes	4,314	3,950
Royalty expenses	2,860	2,489
Accrued interest	646	797
Health claims	1,538	1,386
Workers’ compensation & pneumoconiosis	1,690	1,690
Deferred revenues	2,490	1,967
Other	2,444	3,284
Total	$              19,974	$              19,691

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Business Combinations And Other Acquisitions

9 Months Ended

Sep. 30, 2012

Business Combinations And Other Acquisitions [Abstract]

Business Combinations And Other Acquisitions

3. BUSINESS COMBINATIONS AND OTHER ACQUISITIONS

Acquisition of The Elk Horn Coal Company, LLC

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

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

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

The following table presents selected unaudited pro forma financial information for the three and nine months ended September  30,  2011, as if the acquisition had occurred on January 1, 2011. The pro forma information was prepared using Elk Horn’s historical financial data and also reflects adjustments based upon assumptions by the Partnership’s management to give effect for certain pro forma items that are directly attributable to the acquisition. These pro forma adjustment items include increased depletion expense related to the step-up in basis for the mineral assets acquired and increased interest expense from borrowings incurred to fund the acquisition. The pro forma adjustments for interest expense and earnings per unit reflect the net amount of the additional borrowings incurred by the Partnership in June 2011 to initially fund the acquisition that were partially offset by proceeds from common units issued in a public offering completed in July 2011. Supplemental pro forma revenue, net earnings and earnings per unit disclosures are as follows.

	Three months ended	Nine months ended
	September 30, 2011	September 30, 2011
Revenues:	(in thousands)
As reported	$                   93,564	$                266,195
Pro forma adjustments	-	9,477
Pro forma revenues	$                   93,564	$                275,672
Net Income:
As reported	$                     9,846	$                  25,359
Pro forma adjustments	(26)	3,076
Pro forma net income	$                     9,820	$                  28,435
Net income per limited partner unit, diluted:
As reported	$                       0.36	$                      0.98
Pro forma adjustments	$                     (0.01)	$                      0.03
Pro forma net income per limited partner unit	$                       0.35	$                      1.01

Acquisition of Oil and Gas Mineral Rights

During the year ended December 31, 2011, the Partnership completed the acquisition of certain oil and gas mineral rights in the Cana Woodford region of western Oklahoma for a total purchase price of approximately $8.1 million. The Partnership began to receive royalty revenues from these mineral rights in early 2012.

The Partnership and an affiliate of Wexford Capital have participated with Gulfport Energy (“Gulfport”), a publicly traded company, to acquire interests in a portfolio of oil and gas leases in the Utica Shale. An affiliate of Wexford Capital owns approximately  9.5% of the common stock of Gulfport as of March 13, 2012. During the year ended December 31, 2011, the Partnership completed the acquisitions of interests in a portfolio of leases in the Utica Shale region of eastern Ohio,  which consisted of a 10.8% interest in approximately 80,000 acres. During the third quarter of 2012, the board of directors of the General Partner approved and the Partnership completed an exchange of its initial 10.8% position for a pro rata interest in 125,000 acres under lease by Gulfport and an affiliate of Wexford Capital. The non-cash transaction was an exchange of the Partnership’s operating interest for the operating interest owned by another party in order to diversify the Partnership’s risk in its oil and gas investment. Thus, the Partnership determined that the non-cash exchange of the Partnership’s ownership interest in the Utica acreage did not result in any gain or loss. Also during the third quarter of 2012, the Partnership’s position was adjusted to a  5% net interest in the 125,000 acres, or approximately 6,250 net acres. As of September 30, 2012, the Partnership had invested approximately $22.8 million for its pro rata interest in the Utica Shale portfolio of oil and gas leases. In addition, per the joint operating agreement completed between the Partnership, Gulfport and an affiliate of Wexford Capital, the Partnership has funded its proportionate share of drilling costs to Gulfport for wells being drilled on the Partnership’s acreage. For the three and nine months ended September 30, 2012, the Partnership has funded approximately $3.2 million of drilling costs that are included in Oil and gas properties in the unaudited condensed consolidated statements of financial position as of September 30, 2012. No revenues have been recognized by the Partnership on its Utica Shale investment for the three and nine months ended September 30, 2012.

On March 6, 2012, the Partnership completed a lease agreement with a third party for an estimated 1,500 acres that the Partnership previously owned in the Utica Shale region in Harrison County, Ohio. The lease agreement is for an initial five year term with an optional three year renewal period and conveys rights to the third party to perform drilling and operating activities for producing oil, natural gas or other hydrocarbons. As part of the lease agreement, the third party agreed to pay the Partnership the sum of $6,000 per acre as a lease bonus, of which $0.5 million was paid at the signing of the lease agreement. An additional $6.9 million was paid in the second quarter of 2012 totaling approximately $7.4 million of lease bonus payments for approximately 1,232acres.  The Partnership is working to resolve title issues on approximately250 remaining acres to be included in the lease.In addition, the lease agreement stipulates that the third party shall pay the Partnership a 20% royalty based upon the gross proceeds received from the sale of oil and/or natural gas recovered from the leased property.

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

Acquisition of Coal Properties 

In May 2012, the Partnership completed the purchase of certain rights to coal leases and surface property located in Daviess and McLean counties in western Kentucky for approximately $1.5 million. In addition, the Partnership could potentially be required to pay an additional $3.0 million related to this acquisition if certain conditions are met. Of that amount, $2.0 million was recorded in the Partnership’s unaudited condensed consolidated statements of financial position as of June 30, 2012 in Property, plant and equipment and Accrued expenses related to this acquisition since this additional amount related to the purchase of these assets was probable and estimable. The remaining $1.0 million in potential payments has not been recorded because the conditions requiring payment of this amount are currently not probable.

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

The coal leases and property are estimated to contain approximately 30 million tons of non-reserve coal deposits that are contiguous to the Green River. The property is undeveloped, but fully permitted, and provides the Partnership with access to Illinois Basin coal that is adjacent to a navigable waterway, which could be exported to non-U.S. customers.

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

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

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Debt (Tables)

9 Months Ended

Sep. 30, 2012

Debt [Abstract]

Schedule Of Debt

	September 30,	December 31,
	2012	2011
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$            163,530	$            137,000
Note payable to H&L Construction Co., Inc.	1,745	2,284
Other notes payable	5,189	3,814
Total	170,464	143,098
Less current portion	(2,829)	(1,334)
Long-term debt	$            167,635	$            141,764

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Summary Of Significant Accounting Policies And General (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	9 Months Ended		1 Months Ended
	May 31, 2008 Rhino Eastern LLC [Member]	Sep. 30, 2012 Rhino Eastern LLC [Member]	Dec. 31, 2011 Rhino Eastern LLC [Member]	Mar. 31, 2012 Timber Wolf [Member]
Schedule of Equity Method Investments [Line Items]
Payments to acquire interest in joint venture	$ 16.1			$ 0.1
Ownership interest in joint venture	51.00%
Equity method investment		22.0	18.7
Loans to joint venture		11.9
Loan repayments from joint venture		$ 11.9

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Goodwill And Intangible Assets (Future Amortization Expense) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012
Acquired Finite-Lived Intangible Assets [Line Items]
2012 (from Oct 1 to Dec 31)	$ 20
2013	80
2014	80
2015	80
2016	80
Patent [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
2012 (from Oct 1 to Dec 31)	11
2013	43
2014	43
2015	43
2016	43
Developed Technology [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
2012 (from Oct 1 to Dec 31)	1
2013	5
2014	5
2015	5
2016	5
Trade Name [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
2012 (from Oct 1 to Dec 31)	2
2013	9
2014	9
2015	9
2016	9
Customer List [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
2012 (from Oct 1 to Dec 31)	6
2013	23
2014	23
2015	23
2016	$ 23

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Subsequent Events (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended
	Nov. 09, 2012	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Subsequent Events [Abstract]
Cash distribution, date declared				Oct. 22, 2012
Cash distribution	$ 0.445	$ 0.445	$ 0.455	$ 1.405	$ 1.3308
Cash distribution, annualized	$ 1.78
Cash distribution, date of distribution				Nov. 14, 2012
Cash distribution, date of record				Nov. 01, 2012

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Condensed Consolidated Statements Of Financial Position (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 540	$ 449
Accounts receivable, net of allowance for doubtful accounts ($0 as of September 30, 2012 and December 31, 2011)	37,227	37,242
Inventories	18,878	15,629
Advance royalties, current portion	471	1,428
Prepaid expenses and other	4,768	4,327
Total current assets	61,884	59,075
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs	676,370	637,563
Less accumulated depreciation, depletion and amortization	(209,932)	(187,447)
Net property, plant and equipment	466,438	450,116
Advance royalties, net of current portion	3,361	1,924
Investment in unconsolidated affiliates	22,098	18,736
Goodwill		202
Intangible assets	1,248	1,308
Other non-current assets	6,608	7,433
TOTAL	561,637	538,794
CURRENT LIABILITIES:
Accounts payable	19,761	23,145
Accrued expenses and other	19,974	19,691
Current portion of long-term debt	2,829	1,334
Current portion of asset retirement obligations	3,409	3,192
Current portion of postretirement benefits	157	157
Total current liabilities	46,130	47,519
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion	167,635	141,764
Asset retirement obligations, net of current portion	30,469	30,921
Other non-current liabilities	7,746	6,000
Postretirement benefits, net of current portion	5,842	5,492
Total non-current liabilities	211,692	184,177
Total liabilities	257,822	231,696
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS' CAPITAL:
Limited partners	290,210	293,100
General partner	11,478	11,650
Accumulated other comprehensive income	2,127	2,348
Total partners' capital	303,815	307,098
TOTAL	$ 561,637	$ 538,794

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Business Combinations And Other Acquisitions (Acquisition Of Coal Properties) (Details) (USD $)			1 Months Ended	3 Months Ended		1 Months Ended		12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	May 31, 2012 Daviess And McLean Counties In Kentucky [Member]	Sep. 30, 2012 Daviess And McLean Counties In Kentucky [Member] T	Jun. 30, 2012 Daviess And McLean Counties In Kentucky [Member]	Aug. 31, 2011 Sands Hill [Member] T	Jun. 30, 2011 Randolph And Upshure Counties In West Virginia [Member] acre	Dec. 31, 2011 Randolph And Upshure Counties In West Virginia [Member] T
Coal Property [Line Items]
Acquisition of mineral rights			$ 1,500,000	$ 1,600,000		$ 2,500,000	$ 7,500,000
Contingent additional payments			3,000,000
Coal tonnage				30,000,000		2,500,000		8,600,000
Property, plant and equipment	676,370,000	637,563,000			2,000,000
Accrued expenses	19,974,000	19,691,000		400,000	2,000,000
Potential payment not recorded as currently not probable					$ 1,000,000
Land acreage							32,600

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Basis Of Presentation And Organization

9 Months Ended

Sep. 30, 2012

Basis Of Presentation And Organization [Abstract]

Basis Of Presentation And Organization

1. BASIS OF PRESENTATION AND ORGANIZATION 

Basis of Presentation and Principles of Consolidation— The accompanying unaudited interim financial statements include the accounts of Rhino Resource Partners LP (the “Partnership”) and its subsidiaries. Intercompany transactions and balances have been eliminated in consolidation. 

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, 2012, condensed consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011 and the condensed consolidated statements of cash flows for the nine months ended September 30, 2012 and 2011 include all adjustments (consisting of normal recurring adjustments) which the Partnership considers necessary for a fair presentation of the financial position, operating results and cash flows for the periods presented. The condensed consolidated statement of financial position as of December 31, 2011 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America (“U.S.”). The Partnership filed its Annual Report on Form 10-K for the year ended December 31, 2011 with the Securities and Exchange Commission (“SEC”), which included all information and notes necessary for such presentation. The results of operations for the interim period are not necessarily indicative of the results to be expected for the year or any future period. These unaudited interim financial statements should be read in conjunction with the audited financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011filed with the SEC. 

Organization—The Partnership is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor” or the “Operating Company”). The Partnership had no operations during the period from April 19, 2010 (date of inception) to October 5, 2010 (the consummation of the IPO of the Partnership). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Kentucky, Ohio, West Virginia, and Utah and also haveone underground mine located in Colorado thatremained temporarily idled at September 30, 2012.The majority of sales are made to domestic utilities and other coal-related organizations in the United States. In addition to operating coal properties, the Operating Company manages and leases coal properties and collects royalties from such management and leasing activities. The Operating Company was formed in April 2003 and has been built primarily via acquisitions. 

In addition to its coal operations, the Partnership has invested in oil and gas mineral rights that began to generate royalty revenues in early 2012.

Follow-on Offering

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

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended		12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Asset Retirement Obligations [Abstract]
Balance at beginning of period (including current portion)	$ 34,113	$ 35,691	$ 35,691
Accretion expense	1,305	1,469	1,956
Adjustment resulting from addition of property			2,707
Adjustment resulting from disposal of property	(271)		(3,588)
Adjustments to liability from annual recosting and other			(617)
Liabilities settled	(1,269)		(2,036)
Balance at end of period	33,878		34,113
Current portion of asset retirement obligation	3,409		3,192
Long-term portion of asset retirement obligation	$ 30,469		$ 30,921

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Commitments And Contingencies (Tables)

9 Months Ended

Sep. 30, 2012

Commitments And Contingencies [Abstract]

Schedule Of Purchased Coal Expenses

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Purchased coal expense	$          7,460	$          1,326	$        17,622	$          6,211
OTC expense	$                  -	$             771	$                  -	$             785

Schedule Of Lease And Royalty Expense

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Lease expense	$            873	$            607	$         2,136	$         1,924
Royalty expense	$         3,654	$         3,692	$       10,741	$       11,444

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Commitments And Contingencies (Schedule Of Lease And Royalty Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Commitments And Contingencies [Abstract]
Lease expense	$ 873	$ 607	$ 2,136	$ 1,924
Royalty expense	$ 3,654	$ 3,692	$ 10,741	$ 11,444

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Supplemental Disclosures Of Cash Flow Information

9 Months Ended

Sep. 30, 2012

Supplemental Disclosures Of Cash Flow Information [Abstract]

Supplemental Disclosures Of Cash Flow Information

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION 

The unaudited condensed consolidated statement of cash flows for the nine months ended September  30, 2012 excludes approximately $2.8 million ofproperty additions, which are recorded in accounts payable, and approximately $0.4 million related to the value of phantom and restricted units that were issued to certain employees and directors of the General Partner. The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2012 also excludes$0.4 million related to the amount accrued for the acquisition of the western Kentucky assets discussed in Note 3 and approximately $0.4 million related to a gain recognized on an approved insurance claim for a damaged piece of equipment, which the proceeds had not been received as of September 30, 2012. The unaudited condensed consolidated statement of cash flows for the nine months ended September 30, 2011 excludes approximately $1.8 million of property additions, which are recorded in accounts payable and approximately $0.5 million related to the value of phantom and restricted units that were issued to certain employees and directors of the General Partner.

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Earnings Per Unit ("EPU") (Tables)

9 Months Ended

Sep. 30, 2012

Earnings Per Unit ("EPU") [Abstract]

Schedule Of Calculation Of Numerator And Denominator In Earnings Per Share

Three months ended September 30, 2012	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              177	$                4,806	$                 3,893
Denominator:
Weighted average units used to compute basic EPU	n/a	15,332	12,397
Effect of dilutive securities — LTIP awards	n/a	1	-
Weighted average units used to compute diluted EPU	n/a	15,333	12,397
Net income per limited partner unit, basic	n/a	$                  0.31	$                   0.31
Net income per limited partner unit, diluted	n/a	$                  0.31	$                   0.31
Nine months ended September 30, 2012	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              617	$              16,709	$               13,520
Denominator:
Weighted average units used to compute basic EPU	n/a	15,322	12,397
Effect of dilutive securities — LTIP awards	n/a	5	-
Weighted average units used to compute diluted EPU	n/a	15,327	12,397
Net income per limited partner unit, basic	n/a	$                  1.09	$                   1.09
Net income per limited partner unit, diluted	n/a	$                  1.09	$                   1.09

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three months ended September  30, 2012, approximately 77,000 LTIP granted phantom units were anti-dilutive. There were no other anti-dilutive units for any other periods presented. 

Three months ended September 30, 2011	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              197	$                5,240	$                 4,409
Denominator:
Weighted average units used to compute basic EPU	n/a	14,732	12,397
Effect of dilutive securities — LTIP awards	n/a	15	-
Weighted average units used to compute diluted EPU	n/a	14,747	12,397
Net income per limited partner unit, basic	n/a	$                  0.36	$                   0.36
Net income per limited partner unit, diluted	n/a	$                  0.36	$                   0.36
Nine months ended September 30, 2011	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              507	$              12,718	$               12,134
Denominator:
Weighted average units used to compute basic EPU	n/a	12,993	12,397
Effect of dilutive securities — LTIP awards	n/a	21	-
Weighted average units used to compute diluted EPU	n/a	13,014	12,397
Net income per limited partner unit, basic	n/a	$                  0.98	$                   0.98
Net income per limited partner unit, diluted	n/a	$                  0.98	$                   0.98

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Subsequent Events

9 Months Ended

Sep. 30, 2012

Subsequent Events [Abstract]

Subsequent Events

19.  SUBSEQUENT EVENTS

On October 22, 2012, the Partnership announced a cash distribution of $0.445  per common unit, or $1.78 per unit on an annualized basis. This distribution will be paid on November 14, 2012 to all common unit holders of record as of the close of business on November 1, 2012.

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Supplemental Disclosures Of Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Other Significant Noncash Transactions [Line Items]
Receivable for insurance settlement	$ 0.4
Recorded In Accounts Payable [Member]
Other Significant Noncash Transactions [Line Items]
Property additions	2.8	1.8
Value Of LTIP Units [Member]
Other Significant Noncash Transactions [Line Items]
Value of units issued	0.4	0.5
Contingent Payments Related To Acquisition [Member]
Other Significant Noncash Transactions [Line Items]
Property additions	$ 0.4

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Summary Of Significant Accounting Policies And General

9 Months Ended

Sep. 30, 2012

Summary Of Significant Accounting Policies And General [Abstract]

Summary Of Significant Accounting Policies And General

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Investment in Joint Venture.  Investments in other entities are accounted for using the consolidation, equity method or cost basis depending upon the level of ownership, the Partnership’s ability to exercise significant influence over the operating and financial policies of the investee and whether the Partnership is determined to be the primary beneficiary of a variable interest entity. Equity investments are recorded at original cost and adjusted periodically to recognize the Partnership’s proportionate share of the investees’ net income or losses after the date of investment. Any losses from the Partnership’s equity method investment are absorbed by the Partnership based upon its proportionate ownership percentage. If losses are incurred that exceed the Partnership’s investment in the equity method entity, then the Partnership must continue to record its proportionate share of losses in excess of its investment. Investments are written down only when there is clear evidence that a decline in value that is other than temporary has occurred.

In May 2008, the Operating Company entered into a joint venture, Rhino Eastern LLC (“Rhino Eastern”), with an affiliate of Patriot Coal Corporation (“Patriot”) to acquire the Eagle mining complex. To initially capitalize the joint venture, the Operating Company contributed approximately $16.1 million for a 51% ownership interest in the joint venture and accounts for the investment in the joint venture and its results of operations under the equity method. The Partnership considers the operations of this entity to comprise a reporting segment (“Eastern Met”) and has provided additional detail related to this operation in Note 18, “Segment Information.” As of September  30, 2012 and December 31, 2011, the Partnership has recorded its Rhino Eastern equity method investment of $22.0 million and $18.7 million, respectively, as a long-term asset. During the nine months ended September 30, 2012, the Partnership provided loans to the Rhino Eastern joint venture in the amount of  $11.9 million, which were fullyrepaid as of September 30, 2012.

On July 9, 2012, Patriot filed for Chapter 11 bankruptcy protection. While the long term impact of the Patriot bankruptcy filing on the Rhino Eastern joint venture remains uncertain at this point, normal operations have continued at the joint venture and thus far the bankruptcy filing has not had a material negative effect on Rhino Eastern.

In March 2012, the Partnership made an initial investment of approximately $0.1 million in a new joint venture, Timber Wolf, with affiliates of Wexford Capital LP (“Wexford Capital”).  Timber Wolf was formed to construct and operate a condensate river terminal that will provide barge trans-loading services for parties conducting activities in the Utica Shale region of eastern Ohio.  The initial investment was the Partnership’s proportionate minority ownership share to purchase land for the construction site of the condensate river terminal. Timber Wolf had no operating activities during the nine months ended September 30, 2012 and the Partnership will initially include any operating activities of Timber Wolf in its Other category.

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

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

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

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Condensed Consolidated Statements Of Financial Position (Parenthetical) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Condensed Consolidated Statements Of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 0	$ 0

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Equity-Based Compensation

9 Months Ended

Sep. 30, 2012

Equity-Based Compensation [Abstract]

Equity-Based Compensation

12. EQUITY-BASED COMPENSATION 

In October 2010, the General Partner established the Rhino Long-Term Incentive Plan (the “Plan” or “LTIP”). The Plan is intended to promote the interests of the Partnership by providing to employees, consultants and directors of the General Partner, the Partnership or affiliates of either incentive compensation awards to encourage superior performance. The LTIP provides for grants of restricted units, unit options, unit appreciation rights, phantom units, unit awards, and other unit-based awards.

As of September 30, 2012, the General Partner granted phantom units to certain employees and restricted units and unit awards to its directors. A portion of these grants were made in connection with the IPO completed during October 2010, as well as annual restricted unit awards to directors and phantom unit awards granted in the first quarter of 2012 to certain employees in connection with fiscal year 2011 performance. A total of 20,664 phantom units were granted in the first quarter of 2012 and these awards vest in equal annual installments over a three year period from the date of grant.The remaining terms and conditions of these phantom unit awards are similar to the phantom units awarded in connection with the Partnership’s IPO.  The total fair value of the awards granted in the first quarter of 2012 was approximately $0.4 million at the grant date and the fair value of these awards was approximately $0.3 million as of September 30, 2012.The expense related to these awards will be recognized ratably over the three year vesting period, plus any mark-to-market expense or income, and the amount of expense recognized in the three and nine months ended September 30, 2012 related to these awards was immaterial.

With the vesting of the first portion of the employees’ IPO awards in early April 2011, the Compensation Committee of the board of directors of the General Partner elected to pay some of the awards in cash or a combination of cash and common units. This election was a change in policy since management had previously planned to settle all employee awards with units upon vesting as per the grant agreements. This policy change resulted in a modification of all employee awards from equity to liability classification as of March 31, 2011 and all new awards granted thereafter. For the nine months ended September 30, 2011, the Partnership recorded approximately $0.2 million in incremental compensation expense due to the modification of the employees’ IPO awards. For the three months ended September 30, 2011 and the three and nine months ended September  30, 2012, the Partnership did not record any incremental compensation expense due to the modification of the employees’ IPO awards since the market price of the Partnership’s common units was below the IPO grant price. 

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Document And Entity Information	9 Months Ended
	Sep. 30, 2012	Nov. 02, 2012 Common Units [Member]	Nov. 02, 2012 Subordinated Units [Member]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Entity Registrant Name	Rhino Resource Partners LP
Entity Central Index Key	0001490630
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock Shares Outstanding		15,346,683	12,397,000

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2012

Commitments And Contingencies [Abstract]

Commitments And Contingencies

13. COMMITMENTS AND CONTINGENCIES 

Coal Sales Contracts and Contingencies—As of September 30, 2012, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of approximately  1.1 million, 3.6 million, 2.4 million, 0.8 million and 0.3 million tons of coal to 18 customers in 2012, 12 customers in 2013, 7 customer in 2014, 3 customer in 2015, and 1 customer in 2016, respectively. Some of the contracts have sales price adjustment provisions, subject to certain limitations and adjustments, based on a variety of factors and indices.

The Partnership received a notice from one of its major customers in early April 2012 announcing it would be delaying some of its contracted steam coal shipments from the Partnership’s Central Appalachia and Northern Appalachia operations for an undefined period of time due to an over-supply of coal at its locations. This customer resumed purchasing regularly scheduled contracted tons during June and purchased regularly scheduled contracted tons during the third quarter of 2012.The Partnership continues to work with this customer to deliver contracted shipments that were delayed earlier in 2012.

Purchase Commitments—As of September 30, 2012, the Partnership had approximately 1.0 million gallons remaining on a commitment to purchase diesel fuel at fixed prices through December 2012 for approximately $3.5 million. 

Purchased Coal Expenses—The Partnership incurs purchased coal expense from time to time related to coal purchase contracts. In addition, the Partnership incurs expense from time to time related to coal purchased on the over-the-counter market (“OTC”). Purchased coal expense from coal purchase contracts and expense from OTC purchases for the three and ninemonths ended September  30, 2012 and 2011  were as follows:

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Purchased coal expense	$          7,460	$          1,326	$        17,622	$          6,211
OTC expense	$                  -	$             771	$                  -	$             785

As of September  30, 2012, the Partnership had an outstanding commitment to purchase approximately 0.1 million tons of coal from a third party for the remainder of 2012 for approximately $7.3 million.

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the threeand nine months ended September  30, 2012 and 2011 was as follows:  

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Lease expense	$            873	$            607	$         2,136	$         1,924
Royalty expense	$         3,654	$         3,692	$       10,741	$       11,444

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

The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012.  The Partnership made an initial capital contribution of approximately $0.1 million during the nine months ended September  30, 2012 based upon its proportionate ownership interest.

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Condensed Consolidated Statements Of Operations And Comprehensive Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
REVENUES:
Coal sales	$ 83,902	$ 81,988	$ 225,683	$ 244,367
Freight and handling revenues	1,610	1,548	4,923	4,118
Other revenues	8,063	10,028	34,849	17,710
Total revenues	93,575	93,564	265,455	266,195
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	69,369	69,004	186,659	197,477
Freight and handling costs	1,521	1,331	4,583	3,271
Depreciation, depletion and amortization	10,065	9,157	30,912	26,513
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)	4,654	6,350	15,039	15,345
(Gain)/loss on sale of assets-net	(1,185)	(2,702)	(2,176)	(2,836)
Total costs and expenses	84,424	83,140	235,017	239,770
INCOME FROM OPERATIONS	9,151	10,424	30,438	26,425
INTEREST AND OTHER INCOME (EXPENSE):
Interest expense	(2,105)	(1,850)	(5,889)	(4,274)
Interest income and other	15	14	91	50
Equity in net income of unconsolidated affiliate	1,815	1,258	6,206	3,158
Total interest and other income (expense)	(275)	(578)	408	(1,066)
INCOME BEFORE INCOME TAXES	8,876	9,846	30,846	25,359
INCOME TAXES
NET INCOME	8,876	9,846	30,846	25,359
Other comprehensive income:
Amortization of actuarial gain under ASC Topic 715	(73)		(221)
COMPREHENSIVE INCOME	8,803	9,846	30,625	25,359
General partner's interest in net income	177	197	617	507
Distributions paid per limited partner unit	$ 0.445	$ 0.455	$ 1.405	$ 1.3308
Common Units [Member]
Other comprehensive income:
Unitholders' interest in net income	4,806	5,240	16,709	12,718
Net income per limited partner unit, basic:
Net income per limited partner unit, basic	0.31	0.36	1.09	0.98
Net income per limited partner unit, diluted:
Net income per limited partner unit, diluted	0.31	0.36	1.09	0.98
Weighted average number of limited partner units outstanding, basic:
Weighted average number of limited partner units outstanding, basic	15,332	14,732	15,322	12,993
Weighted average number of limited partner units outstanding, diluted:
Weighted average number of limited partner units outstanding, diluted	15,333	14,747	15,327	13,014
Subordinated Units [Member]
Other comprehensive income:
Unitholders' interest in net income	$ 3,893	$ 4,409	$ 13,520	$ 12,134
Net income per limited partner unit, basic:
Net income per limited partner unit, basic	0.31	0.36	1.09	0.98
Net income per limited partner unit, diluted:
Net income per limited partner unit, diluted	0.31	0.36	1.09	0.98
Weighted average number of limited partner units outstanding, basic:
Weighted average number of limited partner units outstanding, basic	12,397	12,397	12,397	12,397
Weighted average number of limited partner units outstanding, diluted:
Weighted average number of limited partner units outstanding, diluted	12,397	12,397	12,397	12,397

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Other Non-Current Assets

9 Months Ended

Sep. 30, 2012

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Non-Current Assets

7. OTHER NON-CURRENT ASSETS 

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

	September 30,	December 31,
	2012	2011
	(in thousands)
Deposits and other	$                2,470	$                2,481
Debt issuance costs—net	4,119	4,925
Deferred expenses	19	27
Total	$                6,608	$                7,433

Debt issuance costs were approximately $8.0 million as of September  30, 2012 and December 31, 2011. Accumulated amortization of debt issuance costs were approximately$3.9 million and approximately $3.1million as of September  30, 2012 and December 31, 2011, respectively.

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Goodwill And Intangible Assets

9 Months Ended

Sep. 30, 2012

Goodwill And Intangible Assets [Abstract]

Goodwill And Intangible Assets

6. GOODWILL AND INTANGIBLE ASSETS

ASC Topic 350 addresses financial accounting and reporting for goodwill and other intangible assets subsequent to their acquisition. Under the provisions of ASC Topic 350, goodwill and other intangible assets with indefinite useful lives are no longer amortized but instead tested for impairment at least annually.

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

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

As discussed in Note 5, the Partnership’s goodwill balance was reduced to zero since it was included in the disposal of the Partnership’s Triad operations that were sold during the third quarter of 2012.

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

	Gross		Net
	Carrying	Accumulated	Carrying
Intangible Asset	Amount	Amortization	Amount
	(in thousands)
Patent	$              728	$              153	$              575
Developed Technology	78	16	62
Trade Name	184	12	172
Customer List	470	31	439
Total	$           1,460	$              212	$           1,248

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

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

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

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

Amortization expense for the three and nine months ended September  30, 2012 and 2011 is included in the depreciation, depletion and amortization table included in Note 5. The future total amortization expense for each of the five succeeding years related to intangible assets that are currently recorded in the unaudited condensed consolidated statement of financial position is estimated to be as follows at September 30, 2012:  

		Developed		Customer
	Patent	Technology	Trade Name	List	Total
	(in thousands)
2012 (from Oct 1 to Dec 31)	$                  11	$                    1	$                    2	$             6	$           20
2013	43	5	9	23	80
2014	43	5	9	23	80
2015	43	5	9	23	80
2016	43	5	9	23	80

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Segment Information

9 Months Ended

Sep. 30, 2012

Segment Information [Abstract]

Segment Information

18. SEGMENT INFORMATION 

The Partnership produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah and also has one underground mine located in Colorado that was temporarily idled.The Partnership sells primarily to electric utilities in the United States. In addition, with the acquisition of Elk Horn, the Partnership also leases coal reserves to third parties in exchange for royalty revenues. For the three and nine months ended September 30, 2012, the Partnership had four reportable segments: Central Appalachia (comprised of both surface and underground mines located in Eastern Kentucky and Southern West Virginia, along with the Elk Horn operations), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Rhino Western (comprised of underground mines in Colorado and Utah) and Eastern Met (comprised solely of the joint venture with Patriot). Additionally, the Partnership has an Other category that is comprised of the Partnership’s ancillary businesses and investments in oil and gas mineral rights. The Partnership has not provided disclosure of total expenditures by segment for long-lived assets, as the Partnership does not maintain discrete financial information concerning segment expenditures for long lived assets, and accordingly such information is not provided to the Partnership’s chief operating decision maker. 

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

Reportable segment results of operations for the three months ended September 30, 2012 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Consolidated
	(in thousands)
Total revenues	$       51,428	$       29,939	$     10,621	$     16,296	$        (16,296)	$                   -	$       1,587	$         93,575
DD&A	6,165	2,189	1,217	508	(508)	-	494	10,065
Interest expense	1,212	221	201	16	(16)	-	471	2,105
Net Income (loss)	$          (143)	$         6,123	$       1,891	$       3,558	$          (1,743)	$           1,815	$         (810)	$           8,876

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

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Consolidated
	(in thousands)
Total revenues	$       53,443	$       32,568	$      6,044	$     14,323	$        (14,323)	$                   -	$      1,509	$         93,564
DD&A	5,550	1,992	857	754	(754)	-	758	9,157
Interest expense	691	675	201	32	(32)	-	283	1,850
Net Income (loss)	$         3,904	$         6,313	$        (427)	$       2,466	$          (1,208)	$           1,258	$     (1,202)	$           9,846

Reportable segment results of operations for the nine months ended September 30, 2012 are as follows:

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Segments
	(in thousands)
Total revenues	$      135,607	$        94,298	$     30,767	$     49,133	$        (49,133)	$                   -	$       4,783	$       265,455
DD&A	19,801	6,154	3,323	1,630	(1,630)	-	1,634	30,912
Interest expense	3,340	620	546	155	(155)	-	1,383	5,889
Net Income (loss)	$             812	$        23,199	$       4,750	$     12,312	$          (6,106)	$           6,206	$      (4,121)	$         30,846

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

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Segments
	(in thousands)
Total revenues	$      158,092	$        90,306	$     13,065	$     37,093	$        (37,093)	$                   -	$       4,732	$       266,195
DD&A	15,948	6,177	2,117	2,328	(2,328)	-	2,271	26,513
Interest expense	1,640	1,429	360	49	(49)	-	845	4,274
Net Income (loss)	$        10,336	$        18,036	$      (2,327)	$       6,193	$          (3,035)	$           3,158	$      (3,844)	$         25,359

During 2012, the Partnership’s management changed the method that allocates certain corporate overhead and interest charges to the Partnership’s reportable segments from a method based on production tons to a method based upon the amount invested in fixed assets. The Partnership’s management changed the allocation method as a result of additional investments that the Partnership has made in its non-coal operations. Reportable segment figures have not been re-casted for 2011. If the new allocation method had been used for the three months ended September 30, 2011, reportable segment net income would have been reduced by approximately $0.8 million for Central Appalachia and reduced by approximately $0.6 million for the Other category as compared to the reported figures above, and reportable segment net income would have been increased by approximately $1.2 million for Northern Appalachia and increased by approximately $0.2 million for Rhino Western as compared to the reported figures above. If the new allocation method had been used for the nine months ended September 30, 2011, reportable segment net income would have been reduced by approximately $1.4 million for Central Appalachia, reduced by approximately $0.1 million for Rhino Western and reduced by approximately $1.6 million for the Other category as compared to the reported figures above, and reportable segment net income would have been increased by approximately $3.1 million for Northern Appalachia from the reported figures above.

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

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Total costs and expenses	$        12,733	$        11,825	$        36,676	$        30,851
Income from operations	3,563	2,498	12,457	6,242

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Earnings Per Unit ("EPU")

9 Months Ended

Sep. 30, 2012

Earnings Per Unit ("EPU") [Abstract]

Earnings Per Unit ("EPU")

14. EARNINGS PER UNIT (“EPU”)

The following tables present a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended September  30, 2012 and 2011:

Three months ended September 30, 2012	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              177	$                4,806	$                 3,893
Denominator:
Weighted average units used to compute basic EPU	n/a	15,332	12,397
Effect of dilutive securities — LTIP awards	n/a	1	-
Weighted average units used to compute diluted EPU	n/a	15,333	12,397
Net income per limited partner unit, basic	n/a	$                  0.31	$                   0.31
Net income per limited partner unit, diluted	n/a	$                  0.31	$                   0.31
Nine months ended September 30, 2012	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              617	$              16,709	$               13,520
Denominator:
Weighted average units used to compute basic EPU	n/a	15,322	12,397
Effect of dilutive securities — LTIP awards	n/a	5	-
Weighted average units used to compute diluted EPU	n/a	15,327	12,397
Net income per limited partner unit, basic	n/a	$                  1.09	$                   1.09
Net income per limited partner unit, diluted	n/a	$                  1.09	$                   1.09

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three months ended September  30, 2012, approximately 77,000 LTIP granted phantom units were anti-dilutive. There were no other anti-dilutive units for any other periods presented. 

Three months ended September 30, 2011	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              197	$                5,240	$                 4,409
Denominator:
Weighted average units used to compute basic EPU	n/a	14,732	12,397
Effect of dilutive securities — LTIP awards	n/a	15	-
Weighted average units used to compute diluted EPU	n/a	14,747	12,397
Net income per limited partner unit, basic	n/a	$                  0.36	$                   0.36
Net income per limited partner unit, diluted	n/a	$                  0.36	$                   0.36
Nine months ended September 30, 2011	General Partner	Common Unitholders	Subordinated Unitholders
Numerator:	(in thousands, except per unit data)
Interest in net income	$              507	$              12,718	$               12,134
Denominator:
Weighted average units used to compute basic EPU	n/a	12,993	12,397
Effect of dilutive securities — LTIP awards	n/a	21	-
Weighted average units used to compute diluted EPU	n/a	13,014	12,397
Net income per limited partner unit, basic	n/a	$                  0.98	$                   0.98
Net income per limited partner unit, diluted	n/a	$                  0.98	$                   0.98

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2012

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

10. ASSET RETIREMENT OBLIGATIONS 

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

	Nine months ended September 30, 2012	Year ended December 31, 2011
	(in thousands)
Balance at beginning of period (including current portion)	$                            34,113	$                            35,691
Accretion expense	1,305	1,956
Adjustment resulting from addition of property	-	2,707
Adjustment resulting from disposal of property	(271)	(3,588)
Adjustments to the liability from annual recosting and other	-	(617)
Liabilities settled	(1,269)	(2,036)
Balance at end of period	33,878	34,113
Current portion of asset retirement obligation	3,409	3,192
Long-term portion of asset retirement obligation	$                            30,469	$                            30,921

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Employee Benefits (Schedule Of Net Periodic Benefit Cost) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Employee Benefits [Abstract]
Service costs	$ 86	$ 116	$ 291	$ 349
Interest cost	52	74	179	222
Amortization of (gain)	(73)		(221)
Total	$ 65	$ 190	$ 249	$ 571

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Accrued Expenses And Other Current Liabilities

9 Months Ended

Sep. 30, 2012

Accrued Expenses And Other Current Liabilities [Abstract]

Accrued Expenses And Other Current Liabilities

8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES 

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

	September 30,	December 31,
	2012	2011
	(in thousands)
Payroll, bonus and vacation expense	$                3,992	$                4,128
Non income taxes	4,314	3,950
Royalty expenses	2,860	2,489
Accrued interest	646	797
Health claims	1,538	1,386
Workers’ compensation & pneumoconiosis	1,690	1,690
Deferred revenues	2,490	1,967
Other	2,444	3,284
Total	$              19,974	$              19,691

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Debt

9 Months Ended

Sep. 30, 2012

Debt [Abstract]

Debt

9. DEBT 

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

	September 30,	December 31,
	2012	2011
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$            163,530	$            137,000
Note payable to H&L Construction Co., Inc.	1,745	2,284
Other notes payable	5,189	3,814
Total	170,464	143,098
Less current portion	(2,829)	(1,334)
Long-term debt	$            167,635	$            141,764

Senior Secured Credit Facility with PNC Bank, N.A.—The original maximum availability under the credit facility by and among the Operating Company, the guarantors (including the Partnership) and lenders which are parties thereto, and PNC Bank, N.A. as administrative agent was $200.0 million. On June 8, 2011, with the consent of the lenders, the Operating Company exercised the option to increase the amount available to borrow under the credit agreement by $50.0 million to $250.0 million as part of the Elk Horn acquisition. As part of exercising this option to increase the available amount under the credit agreement, the Operating Company paid a fee of $1.0 million to the lenders, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position. 

On July 29, 2011, the Operating Company and the Partnership, as a guarantor, executed an amended and restated senior secured credit facility with PNC Bank, N.A., as administrative agent, and a group of lenders, which are parties thereto. The maximum availability under the amended and restated credit facility is $300.0 million, with a one-time option to increase the availability by an amount not to exceed $50.0 million. Of the $300.0 million, $75.0 million is available for letters of credit. Borrowings under the facility bear interest, which varies depending upon the levels of certain financial ratios. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability that also varies depending upon the levels of certain financial ratios. Borrowings on the amended and restated senior secured credit facility are collateralized by all of the unsecured assets of the Partnership. The amended and restated senior secured credit facility requires the Partnership to maintain certain minimum financial ratios and contains certain restrictive provisions, including among others, restrictions on making loans, investments and advances, incurring additional indebtedness, guaranteeing indebtedness, creating liens, and selling or assigning stock. The Partnership was in compliance with all covenants contained in the amended and restated senior secured credit facility as of and for the twelve months ended September 30, 2012. The amended and restated senior secured credit facility expires in July 2016.  

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

At September 30, 2012, the Operating Company had borrowed $162.0 million at a variable interest rate of LIBOR plus 2.75% (2.98% at September 30, 2012) and an additional $1.5 million at a variable interest rate of PRIME plus 1.75% (5.00% at September 30, 2012). In addition, the Operating Company had outstanding letters of credit of approximately $23.2 million at a fixed interest rate of 2.75% at September 30, 2012. Based upon a maximum borrowing capacity of three times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had not used $78.0 million of the borrowing availability at September 30, 2012. 

Note payable to H&L Construction Co., Inc.— The note payable to H&L Construction Co., Inc. was originally a non-interest bearing note and the Partnership has recorded a discount for imputed interest at a rate of 5.0% on this note that is being amortized over the life of the note using the effective interest method. The note payable matures in January 2015. The note is secured by mineral rights purchased by the Partnership from H&L Construction Co., Inc. with a carrying amount of approximately  $11.4 million and approximately $11.6 million at September 30, 2012 and December 31, 2011, respectively.

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Employee Benefits

9 Months Ended

Sep. 30, 2012

Employee Benefits [Abstract]

Employee Benefits

11. EMPLOYEE BENEFITS 

In conjunction with the acquisition of the coal operations of American Electric Power on April 16, 2004, the Operating Company acquired a postretirement benefit plan providing healthcare to eligible employees. The Partnership has no other postretirement plans.

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

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Service costs	$              86	$            116	$            291	$            349
Interest cost	52	74	179	222
Amortization of (gain)	(73)	-	(221)	-
Total	$              65	$            190	$            249	$            571

401(k) Plans—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Operating Company’s discretion. The expense under these plans for the threeand nine months ended September  30, 2012 and 2011 was as follows:  

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
401(k) plan expense	$            580	$            583	$         1,743	$         1,652

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Commitments And Contingencies (Schedule Of Purchased Coal Expenses) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Commitments And Contingencies [Abstract]
Purchased coal expense	$ 7,460	$ 1,326	$ 17,622	$ 6,211
OTC expense		$ 771		$ 785

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Earnings Per Unit ("EPU") (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Earnings Per Unit [Line Items]
Interest in net income	$ 8,876	$ 9,846	$ 30,846	$ 25,359
Anti-dilutive LTIP phantom units	77,000
General Partner [Member]
Earnings Per Unit [Line Items]
Interest in net income	177	197	617	507
Common Unitholders [Member]
Earnings Per Unit [Line Items]
Interest in net income	4,806	5,240	16,709	12,718
Weighted average units used to compute basic EPU	15,332,000	14,732,000	15,322,000	12,993,000
Effect of dilutive securities - LTIP awards	1,000	15,000	5,000	21,000
Weighted average units used to compute diluted EPU	15,333,000	14,747,000	15,327,000	13,014,000
Net income per limited partner unit, basic	0.31	0.36	1.09	0.98
Net income per limited partner unit, diluted	0.31	0.36	1.09	0.98
Subordinated Unitholders[Member]
Earnings Per Unit [Line Items]
Interest in net income	$ 3,893	$ 4,409	$ 13,520	$ 12,134
Weighted average units used to compute basic EPU	12,397,000	12,397,000	12,397,000	12,397,000
Weighted average units used to compute diluted EPU	12,397,000	12,397,000	12,397,000	12,397,000
Net income per limited partner unit, basic	0.31	0.36	1.09	0.98
Net income per limited partner unit, diluted	0.31	0.36	1.09	0.98

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Commitments And Contingencies (Narrative) (Details) (USD $)	9 Months Ended				12 Months Ended					1 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Diesel Fuel [Member] gal	Sep. 30, 2012 Coal [Member] T	Dec. 31, 2016 Scenario, Forecast [Member] customer T	Dec. 31, 2015 Scenario, Forecast [Member] customer T	Dec. 31, 2014 Scenario, Forecast [Member] T customer	Dec. 31, 2013 Scenario, Forecast [Member] T customer	Dec. 31, 2012 Scenario, Forecast [Member] T customer	Apr. 30, 2012 Notice Of Delayed Coal Shipments [Member] customer
Commitments And Contingencies [Line Items]
Coal sales commitments, tons					300,000	800,000	2,400,000	3,600,000	1,100,000
Number of customers					1	3	7	12	18	1
Diesel fuel purchase commitments, gallons			1,000,000
Coal purchase commitments, tons				100,000
Purchase commitments			$ 3,500,000	$ 7,300,000
Initial capital contribution in joint venture	$ 114,000

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Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2012

Employee Benefits [Abstract]

Schedule Of Net Periodic Benefit Cost

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Service costs	$              86	$            116	$            291	$            349
Interest cost	52	74	179	222
Amortization of (gain)	(73)	-	(221)	-
Total	$              65	$            190	$            249	$            571

Schedule Of Expense Under Defined Contribution Savings Plans

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
401(k) plan expense	$            580	$            583	$         1,743	$         1,652

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Goodwill And Intangible Assets (Schedule Of Goodwill) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Goodwill And Intangible Assets [Abstract]
Goodwill from the acquisition of Triad		$ 202

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Fair Value Of Financial Instruments

9 Months Ended

Sep. 30, 2012

Fair Value Of Financial Instruments [Abstract]

Fair Value Of Financial Instruments

16. FAIR VALUE OF FINANCIAL INSTRUMENTS 

The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership’s senior secured credit facility was determined based upon a market approach and approximates the carrying value at September  30, 2012. The fair value of the Partnership’s senior secured credit facility is a Level 2 measurement.

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Business Combinations And Other Acquisitions (Tables)

9 Months Ended

Sep. 30, 2012

Business Combinations And Other Acquisitions [Abstract]

Summary Of Assets Acquired And Liabilities Assumed

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

Business Acquisition, Pro Forma Information

	Three months ended	Nine months ended
	September 30, 2011	September 30, 2011
Revenues:	(in thousands)
As reported	$                   93,564	$                266,195
Pro forma adjustments	-	9,477
Pro forma revenues	$                   93,564	$                275,672
Net Income:
As reported	$                     9,846	$                  25,359
Pro forma adjustments	(26)	3,076
Pro forma net income	$                     9,820	$                  28,435
Net income per limited partner unit, diluted:
As reported	$                       0.36	$                      0.98
Pro forma adjustments	$                     (0.01)	$                      0.03
Pro forma net income per limited partner unit	$                       0.35	$                      1.01

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Property, Plant And Equipment (Depreciation, Depletion And Amortization) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Depreciation Depletion And Amortization Details [Line Items]
Depreciation, depletion and amortization	$ 10,065	$ 9,157	$ 30,912	$ 26,513
Mining And Other Equipment And Related Facilities [Member]
Depreciation Depletion And Amortization Details [Line Items]
Depreciation, depletion and amortization	7,950	6,488	24,414	19,769
Coal Properties [Member]
Depreciation Depletion And Amortization Details [Line Items]
Depreciation, depletion and amortization	1,440	1,510	4,361	3,358
Mine Development Costs [Member]
Depreciation Depletion And Amortization Details [Line Items]
Depreciation, depletion and amortization	526	809	1,650	2,358
Intangible Assets [Member]
Depreciation Depletion And Amortization Details [Line Items]
Depreciation, depletion and amortization	20	12	60	36
Asset Retirement Costs [Member]
Depreciation Depletion And Amortization Details [Line Items]
Depreciation, depletion and amortization	$ 129	$ 338	$ 427	$ 992

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Business Combinations And Other Acquisitions (Acquisition Of The Elk Horn Coal Company, LLC) (Details) (Elk Horn Coal Company [Member}, USD $) In Millions, unless otherwise specified	1 Months Ended
	Jun. 30, 2011
Elk Horn Coal Company [Member}
Business Acquisition [Line Items]
Percentage of ownership interest acquired	100.00%
Cash consideration	$ 119.7
Cash paid, net of cash acquired	$ 119.6
Effective date of acquisition	Jun. 10, 2011

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Condensed Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 30,846	$ 25,359
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	30,912	26,513
Accretion on asset retirement obligations	1,305	1,469
Accretion on interest-free debt	165	157
Amortization of deferred revenue	(910)	(361)
Amortization of advance royalties	161	906
Amortization of debt issuance costs	806	774
Provision (reversal) for doubtful accounts		(19)
Amortization of actuarial gain	(221)
Equity in net (income) of unconsolidated affiliate	(6,206)	(3,158)
Distribution from unconsolidated affiliate	2,958
Loss on retirement of advance royalties	86	79
(Gain) on sale of assets-net	(1,764)	(2,836)
Equity-based compensation	683	643
Changes in assets and liabilities:
Accounts receivable	15	(4,913)
Inventories	(3,249)	1,621
Advance royalties	(728)	(981)
Prepaid expenses and other assets	(416)	1,074
Accounts payable	(3,384)	5,657
Accrued expenses and other liabilities	7,888	779
Asset retirement obligations	(1,269)	(1,967)
Postretirement benefits	350	521
Net cash provided by operating activities	58,028	51,317
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment	(53,347)	(64,606)
Proceeds from sales of property, plant, and equipment	2,684	1,841
Proceeds from sale of coal properties and related assets and liabilities		20,000
Principal payments received on notes receivable	11,945	5,270
Cash paid from issuance of notes receivable	(11,945)	(5,270)
Changes in restricted cash		34
Acquisition of coal companies and other properties		(119,299)
Return of capital from unconsolidated affiliate		1,311
Investment in unconsolidated affiliate	(114)
Net cash used in investing activities	(50,777)	(160,719)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit	173,300	276,350
Repayments on line of credit	(146,770)	(194,450)
Proceeds from issuance of long-term debt	2,603	1,379
Repayments on long-term debt	(1,932)	(2,700)
Net settlement of employee withholding taxes on unit awards vested	(85)	(164)
Debt issuance costs		(3,758)
Distributions to unitholders	(34,276)	(35,038)
General partner's contributions	7	1,444
Proceeds from issuance of common units, net of issuance costs		66,916
Payment of offering costs	(7)	(357)
Net cash (used in) provided by financing activities	(7,160)	109,622
NET INCREASE IN CASH AND CASH EQUIVALENTS	91	220
CASH AND CASH EQUIVALENTS-Beginning of period	449	76
CASH AND CASH EQUIVALENTS-End of period	$ 540	$ 296

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Property, Plant And Equipment

9 Months Ended

Sep. 30, 2012

Property, Plant And Equipment [Abstract]

Property, Plant And Equipment

5. PROPERTY, PLANT AND EQUIPMENT 

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

	Useful Lives	September 30, 2012	December 31, 2011
		(in thousands)
Land and land improvements		$        36,924	$         33,298
Mining and other equipment and related facilities	2 - 20 Years	285,855	244,819
Mine development costs	1 - 15 Years	65,571	65,824
Coal properties	1 - 15 Years	239,140	238,355
Oil and gas properties		31,164	27,964
Construction work in process		17,716	27,303
Total		676,370	637,563
Less accumulated depreciation, depletion and amortization		(209,932)	(187,447)
Net		$      466,438	$       450,116

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties, amortization expense for mine development costs, amortization expense for intangible assets and amortization expense for asset retirement costs for the three and nine months ended September  30, 2012 and 2011  were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$           7,950	$           6,488	$         24,414	$         19,769
Depletion expense for coal properties	1,440	1,510	4,361	3,358
Amortization expense for mine development costs	526	809	1,650	2,358
Amortization expense for intangible assets	20	12	60	36
Amortization expense for asset retirement costs	129	338	427	992
Total depreciation, depletion and amortization	$         10,065	$           9,157	$         30,912	$         26,513

Sale of Mining Assets

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

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

Sale of Triad Operations

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

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Debt (Schedule Of Debt) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Debt [Abstract]
Senior secured credit facility with PNC Bank, N.A.	$ 163,530	$ 137,000
Notes payable to H&L Construction Co., Inc.	1,745	2,284
Other notes payable	5,189	3,814
Total	170,464	143,098
Less current portion	(2,829)	(1,334)
Long-term debt	$ 167,635	$ 141,764

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Segment Information (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2012 segment item	Sep. 30, 2011 Central Appalachia [Member]	Sep. 30, 2011 Central Appalachia [Member]	Sep. 30, 2011 Northern Appalachia [Member]	Sep. 30, 2011 Northern Appalachia [Member]	Sep. 30, 2011 Rhino Western [Member]	Sep. 30, 2011 Rhino Western [Member]	Sep. 30, 2011 Other [Member]	Sep. 30, 2011 Other [Member]
Number of underground mines temporarily idle	1
Number of reportable business segments	4
Increase (decrease) in net income under new methodology based on fixed asset investment		$ (0.8)	$ (1.4)	$ 1.2	$ 3.1	$ 0.2	$ (0.1)	$ (0.6)	$ (1.6)

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Prepaid Expenses And Other Current Assets (Tables)

9 Months Ended

Sep. 30, 2012

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Prepaid Expenses And Other Current Assets

	September 30,	December 31,
	2012	2011
	(in thousands)
Other prepaid expenses	$                      672	$                      577
Prepaid insurance	2,360	1,526
Prepaid leases	150	103
Supply inventory	1,265	1,951
Deposits	321	170
Total Prepaid expenses and other	$                   4,768	$                   4,327

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2012

Segment Information [Abstract]

Reportable Segment Results Of Operations

Reportable segment results of operations for the three months ended September 30, 2012 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Consolidated
	(in thousands)
Total revenues	$       51,428	$       29,939	$     10,621	$     16,296	$        (16,296)	$                   -	$       1,587	$         93,575
DD&A	6,165	2,189	1,217	508	(508)	-	494	10,065
Interest expense	1,212	221	201	16	(16)	-	471	2,105
Net Income (loss)	$          (143)	$         6,123	$       1,891	$       3,558	$          (1,743)	$           1,815	$         (810)	$           8,876

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

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Consolidated
	(in thousands)
Total revenues	$       53,443	$       32,568	$      6,044	$     14,323	$        (14,323)	$                   -	$      1,509	$         93,564
DD&A	5,550	1,992	857	754	(754)	-	758	9,157
Interest expense	691	675	201	32	(32)	-	283	1,850
Net Income (loss)	$         3,904	$         6,313	$        (427)	$       2,466	$          (1,208)	$           1,258	$     (1,202)	$           9,846

Reportable segment results of operations for the nine months ended September 30, 2012 are as follows:

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Segments
	(in thousands)
Total revenues	$      135,607	$        94,298	$     30,767	$     49,133	$        (49,133)	$                   -	$       4,783	$       265,455
DD&A	19,801	6,154	3,323	1,630	(1,630)	-	1,634	30,912
Interest expense	3,340	620	546	155	(155)	-	1,383	5,889
Net Income (loss)	$             812	$        23,199	$       4,750	$     12,312	$          (6,106)	$           6,206	$      (4,121)	$         30,846

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

				Eastern Met
					Equity	Equity
	Central	Northern	Rhino	Complete	Method	Method		Total
	Appalachia	Appalachia	Western	Basis	Eliminations	Presentation	Other	Segments
	(in thousands)
Total revenues	$      158,092	$        90,306	$     13,065	$     37,093	$        (37,093)	$                   -	$       4,732	$       266,195
DD&A	15,948	6,177	2,117	2,328	(2,328)	-	2,271	26,513
Interest expense	1,640	1,429	360	49	(49)	-	845	4,274
Net Income (loss)	$        10,336	$        18,036	$      (2,327)	$       6,193	$          (3,035)	$           3,158	$      (3,844)	$         25,359

Equity Method Investments, Summarized Financial Information

	Three months ended September 30,		Nine months ended September 30,
	2012	2011	2012	2011
	(in thousands)
Total costs and expenses	$        12,733	$        11,825	$        36,676	$        30,851
Income from operations	3,563	2,498	12,457	6,242

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Major Customers

9 Months Ended

Sep. 30, 2012

Major Customers [Abstract]

Major Customers

15. MAJOR CUSTOMERS 

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

	September 30,	Nine months	Nine months
	2012	ended	ended
	Receivable	September 30,	September 30,
	Balance	2012 Sales	2011 Sales
	(in thousands)
GenOn Energy, Inc.	$                   5,352	$                 38,847	$                 44,178
Indiana Harbor Coke Company, L.P	4,652	28,806	29,812
PPL Corporation	3,042	30,553	n/a
American Electric Power Company, Inc.	3,271	26,683	34,273