Rhino Resource Partners LP - FORM 10-Q

Attached files

file	filename
EX-95.1 - Rhino Resource Partners LP	ex95-1.htm
EX-32.2 - Rhino Resource Partners LP	ex32-2.htm
EX-32.1 - Rhino Resource Partners LP	ex32-1.htm
EX-31.2 - Rhino Resource Partners LP	ex31-2.htm
EX-31.1 - Rhino Resource Partners LP	ex31-1.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]

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

For the quarterly period ended June 30, 2016

[ ]

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

For the transition period from ________ to ________

Commission files number 001-34892

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

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

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

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

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

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 [ ] 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 [ ]	Accelerated filer [ ]
Non-accelerated filer [ ] (Do not check if a smaller reporting company)	Smaller reporting company [X]

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

As of August 8, 2016, 7,905,799 common units and 1,235,534 subordinated units were outstanding.

TABLE OF CONTENTS

Cautionary Note Regarding Forward-Looking Statements	3
Part I.—Financial Information (Unaudited)	4
ITEM 1. FINANCIAL STATEMENTS	4
Condensed Consolidated Statements of Financial Position as of June 30, 2016 and December 31, 2015	4
Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2016 and 2015	5
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 4. Controls and Procedures	67
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	68
Item 3. Defaults upon Senior Securities	68
Item 4. Mine Safety Disclosure	68
Item 5. Other Information	68
Item 6. Exhibits	69
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 statements regarding our future financial position, expectations with respect to our liquidity, capital resources and ability to continue as a going concern, plans for growth of the business, future capital expenditures, 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 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: our ability to maintain adequate cash flow and to obtain financing necessary to fund our capital expenditures, meet working capital needs and maintain and grow our operations; our future levels of indebtedness and compliance with debt covenants; sustained depressed levels of or decline in coal prices, which depend upon several factors such as the supply of domestic and foreign coal, the demand for domestic and foreign coal, governmental regulations, price and availability of alternative fuels for electricity generation and prevailing economic conditions; our ability to comply with the qualifying income requirement necessary to maintain our status as a partnership for U.S. federal income tax purposes; declines in demand for electricity and coal; current and future environmental laws and regulations, which could materially increase operating costs or limit our ability to produce and sell coal; extensive government regulation of mine operations, especially with respect to mine safety and health, which imposes significant actual and potential costs; difficulties in obtaining and/or renewing permits necessary for operations; a variety of operating risks, such as unfavorable geologic conditions, adverse weather conditions and natural disasters, mining and processing equipment unavailability, failures and unexpected maintenance problems and accidents, including fire and explosions from methane; poor mining conditions resulting from the effects of prior mining; the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives; fluctuations in transportation costs or disruptions in transportation services, which could increase competition or impair our ability to supply coal; a shortage of skilled labor, increased labor costs or work stoppages; our ability to secure or acquire new or replacement high-quality coal reserves that are economically recoverable; material inaccuracies in our estimates of coal reserves and non-reserve coal deposits; existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds, which could affect coal consumers and reduce demand for coal; federal and state laws restricting the emissions of greenhouse gases; our ability to acquire or failure to maintain, obtain or renew surety bonds used to secure obligations to reclaim mined property; our dependence on a few customers and our ability to find and retain customers under favorable supply contracts; changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices; changes in governmental regulation of the electric utility industry; our ability to successfully diversify our operations into other non-coal natural resources; disruption in supplies of coal produced by contractors operating our mines; defects in title in properties that we own or losses of any of our leasehold interests; our ability to retain and attract senior management and other key personnel; material inaccuracy of assumptions underlying reclamation and mine closure obligations; and weakness in global economic conditions. 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, 2015, (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 from 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, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I.—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(in thousands)

	June 30, 2016			December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15		$	78
Accounts receivable, net of allowance for doubtful accounts ($166 as of June 30, 2016 and $166 as of December 31, 2015)		13,234			14,569
Inventories		7,859			8,570
Advance royalties, current portion		849			753
Prepaid expenses and other		4,145			5,474
Total current assets		26,102			29,444
PROPERTY, PLANT AND EQUIPMENT:
At cost, including coal properties, mine development and construction costs		476,932			604,514
Less accumulated depreciation, depletion and amortization		(270,038	)		(271,007	)
Net property, plant and equipment		206,894			333,507
Advance royalties, net of current portion		7,708			7,326
Investment in unconsolidated affiliates		7,473			7,578
Intangible assets		489			505
Other non-current assets		28,915			26,307
TOTAL	$	277,581		$	404,667
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	11,537		$	9,336
Accrued expenses and other		12,223			14,102
Current portion of long-term debt		288			41,479
Current portion of asset retirement obligations		1,646			767
Current portion of postretirement benefits		-			45
Total current liabilities		25,694			65,729
NON-CURRENT LIABILITIES:
Long-term debt, net of current portion		40,225			2,595
Asset retirement obligations, net of current portion		22,722			22,980
Other non-current liabilities		43,468			45,435
Total non-current liabilities		106,415			71,010
Total liabilities		132,109			136,739
COMMITMENTS AND CONTINGENCIES (NOTE 13)
PARTNERS’ CAPITAL:
Limited partners		140,483			253,312
Subscription receivable from limited partners		(4,000	)		-
General partner		8,989			9,821
Accumulated other comprehensive income		-			4,795
Total partners’ capital		145,472			267,928
TOTAL	$	277,581		$	404,667

See notes to unaudited condensed consolidated financial statements.

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND

COMPREHENSIVE INCOME

(in thousands, except per unit data)

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2016			2015			2016			2015
REVENUES:
Coal sales	$	39,106		$	48,469		$	75,786		$	94,025
Freight and handling revenues		581			668			1,210			1,207
Other revenues		3,053			7,628			6,173			17,717
Total revenues		42,740			56,765			83,169			112,949
COSTS AND EXPENSES:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		33,860			47,318			63,311			93,470
Freight and handling costs		516			670			1,066			1,205
Depreciation, depletion and amortization		5,931			8,596			12,178			17,448
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)		3,986			4,913			8,040			9,329
Loss on asset impairments		118,705			2,179			118,705			2,179
(Gain)/loss on sale/disposal of assets—net		(25	)		48			(295	)		25
Total costs and expenses		162,973			63,724			203,005			123,656
(LOSS) FROM OPERATIONS		(120,233	)		(6,959	)		(119,836	)		(10,707	)
INTEREST AND OTHER (EXPENSE)/INCOME:
Interest expense		(1,725	)		(1,313	)		(3,299	)		(2,270	)
Interest income and other		31			36			64			38
Equity in net (loss)/income of unconsolidated affiliates		(26	)		124			(105	)		265
Total interest and other (expense)		(1,720	)		(1,153	)		(3,340	)		(1,967	)
NET (LOSS) BEFORE INCOME TAXES FROM CONTINUING OPERATIONS		(121,953	)		(8,112	)		(123,176	)		(12,674	)
INCOME TAXES		-			-			-			-
NET (LOSS) FROM CONTINUING OPERATIONS		(121,953	)		(8,112	)		(123,176	)		(12,674	)
DISCONTINUED OPERATIONS (NOTE 3)
Income from discontinued operations		-			-			-			722
NET (LOSS)		(121,953	)		(8,112	)		(123,176	)		(11,952	)
Other comprehensive income:
Amortization of actuarial gain under ASC Topic 715		-			(44	)		(4,796	)		(89	)
COMPREHENSIVE (LOSS)	$	(121,953	)	$	(8,156	)	$	(127,972	)	$	(12,041	)

General partner’s interest in net (loss)/income:
Net (loss) from continuing operations	$	(808	)	$	(162	)	$	(832	)	$	(253	)
Net income from discontinued operations		-			-			-			14
General partner’s interest in net (loss)/income	$	(808	)	$	(162	)	$	(832	)	$	(239	)
Common unitholders’ interest in net (loss)/income:
Net (loss) from continuing operations	$	(104,558	)	$	(4,563	)	$	(89,511	)	$	(7,128	)
Net income from discontinued operations		-			-			-			406
Common unitholders’ interest in net (loss)/income	$	(104,558	)	$	(4,563	)	$	(89,511	)	$	(6,722	)
Subordinated unitholders’ interest in net (loss)/income:
Net (loss) from continuing operations	$	(16,587	)	$	(3,387	)	$	(32,833	)	$	(5,293	)
Net income from discontinued operations		-			-			-			302
Subordinated unitholders’ interest in net (loss)/income	$	(16,587	)	$	(3,387	)	$	(32,833	)	$	(4,991	)
Net (loss)/income per limited partner unit, basic:
Common units:
Net (loss) per unit from continuing operations	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(4.18	)
Net income per unit from discontinued operations		-			-			-			0.24
Net (loss)/income per common unit, basic	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(3.94	)
Subordinated units
Net (loss) per unit from continuing operations	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(4.38	)
Net income per unit from discontinued operations		-			-			-			0.24
Net (loss)/income per subordinated unit, basic	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(4.14	)
Net (loss)/income per limited partner unit, diluted:
Common units
Net (loss) per unit from continuing operations	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(4.18	)
Net income per unit from discontinued operations		-			-			-			0.24
Net (loss)/income per common unit, diluted	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(3.94	)
Subordinated units
Net (loss) per unit from continuing operations	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(4.38	)
Net income per unit from discontinued operations		-			-			-			0.24
Net (loss)/income per subordinated unit, diluted	$	(13.42	)	$	(2.73	)	$	(26.57	)	$	(4.14	)

Distributions paid per limited partner unit (1)	$	-		$	0.02		$	-		$	0.07
Weighted average number of limited partner units outstanding, basic:
Common units		7,788			1,670			3,368			1,669
Subordinated units		1,236			1,240			1,236			1,240
Weighted average number of limited partner units outstanding, diluted:
Common units		7,788			1,670			3,368			1,669
Subordinated units		1,236			1,240			1,236			1,240

(1) No distributions were paid on the subordinated units for the three and six months ended June 30, 2016 and 2015

See notes to unaudited condensed consolidated financial statements

RHINO RESOURCE PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Six Months Ended June 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)	$	(123,176	)	$	(11,952	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		12,178			17,448
Accretion on asset retirement obligations		763			1,101
Accretion on interest-free debt		-			51
Amortization of deferred revenue		(718	)		(1,673	)
Amortization of advance royalties		570			398
Amortization of debt issuance costs		998			738
Amortization of actuarial gain		(4,796	)		(89	)
Provision for doubtful accounts		-			362
Equity in net loss/(income) of unconsolidated affiliates		105			(265	)
Distributions from unconsolidated affiliate		-			232
Loss on retirement of advance royalties		140			28
Loss on asset impairments		118,705			2,179
(Gain) on sale/disposal of assets—net		(295	)		(696	)
Equity-based compensation		520			33
Changes in assets and liabilities:
Accounts receivable		1,371			2,309
Inventories		710			(2,528	)
Advance royalties		(1,188	)		(937	)
Prepaid expenses and other assets		(697	)		1,754
Accounts payable		1,676			1,505
Accrued expenses and other liabilities		(2,626	)		1,444
Asset retirement obligations		(142	)		(172	)
Postretirement benefits		(45	)		120
Net cash provided by operating activities		4,053			11,390
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant, and equipment		(4,362	)		(7,843	)
Proceeds from sales of property, plant, and equipment		341			1,094
Return of capital from unconsolidated affiliates		-			35
Net cash used in investing activities		(4,021	)		(6,714	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on line of credit		48,800			50,900
Repayments on line of credit		(52,250	)		(52,750	)
Repayments on long-term debt		(111	)		(51	)
Distributions to unitholders		(24	)		(1,267	)
General partner’s contributions		-			1
Payments on debt issuance costs		(1,510	)		(2,062	)
Limited partner contributions		5,000			-
Net cash used in financing activities		(95	)		(5,229	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(63	)		(553	)
CASH AND CASH EQUIVALENTS—Beginning of period		78			626
CASH AND CASH EQUIVALENTS—End of period	$	15		$	73

See notes to unaudited condensed consolidated financial statements.

RHINO RESOURCE PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2016 AND DECEMBER 31, 2015 AND FOR THE THREE AND SIX MONTHS ENDED
JUNE 30, 2016 AND 2015

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 and its subsidiaries (the “Partnership”). Intercompany transactions and balances have been eliminated in consolidation.

Unaudited Interim Financial Information—The accompanying unaudited interim financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. The condensed consolidated statement of financial position as of June 30, 2016, condensed consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2016 and 2015 and the condensed consolidated statements of cash flows for the six months ended June 30, 2016 and 2015 include all adjustments that 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, 2015 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, 2015 with the Securities and Exchange Commission (“SEC”), which included all information and notes necessary for such presentation. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the year or any future period. These unaudited interim financial statements should be read in conjunction with the audited financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC.

Organization—Rhino Resource Partners LP is a Delaware limited partnership formed on April 19, 2010 to acquire Rhino Energy LLC (the “Predecessor” or the “Operating Company”). The Operating Company and its wholly owned subsidiaries produce and market coal from surface and underground mines in Kentucky, Ohio, West Virginia, and Utah. The 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.

On January 21, 2016, a definitive agreement (“Definitive Agreement”) was completed between Royal Energy Resources, Inc. (“Royal”) and Wexford Capital LP (“Wexford Capital”) whereby Royal acquired 6,769,112 issued and outstanding common units of the Partnership from Wexford Capital for $3.5 million. The Definitive Agreement also included the committed acquisition by Royal within sixty days from the date of the Definitive Agreement of all of the issued and outstanding membership interests of Rhino GP LLC, the general partner of the Partnership (the “General Partner”), as well as 9,455,252 issued and outstanding subordinated units of the Partnership from Wexford Capital for $1.0 million.

On March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of Rhino GP LLC as well as the 9,455,252 issued and outstanding subordinated units from Wexford Capital. Royal obtained control of, and a majority limited partner interest, in the Partnership with the completion of this transaction.

On March 21, 2016, the Partnership and Royal entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant to which the Partnership issued 60,000,000 common units in the Partnership to Royal in a private placement at $0.15 per common unit for an aggregate purchase price of $9.0 million. Royal paid the Partnership $2.0 million in cash and delivered a promissory note payable to the Partnership in the amount of $7.0 million. The promissory note is payable in three installments: (i) $3.0 million on July 31, 2016; (ii) $2.0 million on or before September 30, 2016 and (iii) $2.0 million on or before December 31, 2016. In the event the disinterested members of the board of directors of the General Partner determine that the Partnership does not need the capital that would be provided by either or both installments set forth in (ii) and (iii) above, in each case, the Partnership has the option to rescind Royal’s purchase of 13,333,333 common units and the applicable installment will not be payable (each, a “Rescission Right”). If the Partnership fails to exercise a Rescission Right, in each case, the Partnership has the option to repurchase 13,333,333 common units at $0.30 per common unit from Royal (each, a “Repurchase Option”). The Repurchase Options terminate on December 31, 2017. Royal’s obligation to pay any installment of the promissory note is subject to certain conditions, including that the Operating Company has entered into an agreement to extend the Amended and Restated Credit Agreement, as amended, to a date no sooner than December 31, 2017. In the event such conditions are not satisfied as of the date each installment is due, Royal has the right to cancel the remaining unpaid balance of the promissory note in exchange for the surrender of such number of common units equal to the principal balance of the promissory note divided by $0.15. On May 13, 2016, Royal paid the Partnership the $3.0 million promissory note installment that was due July 31, 2016. The payment was made in relation to the fifth amendment of the Amended and Restated Credit Agreement completed on May 13, 2016. See Note 9 for more information on the fifth amendment to the Amended and Restated Credit Agreement.

On April 18, 2016, the Partnership completed a 1-for-10 reverse split on its common units and subordinated units. Pursuant to the reverse split, common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated unitholders received one subordinated unit for every 10 subordinated units owned on April 18, 2016. Any fractional units resulting from the reverse unit split were rounded to the nearest whole unit. The reverse unit split was intended to increase the market price per unit of Rhino’s common units in order to comply with the New York Stock Exchange’s (“NYSE”) continued listing standards.

As previously reported, on December 17, 2015, the Partnership was notified by the NYSE that the NYSE had determined to commence proceedings to delist its common units from the NYSE as a result of the Partnership’s failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of the Partnership’s common units at the close of trading on December 17, 2015. On January 4, 2016, the Partnership filed an appeal with the NYSE to review the suspension and delisting determination of its common units. The NYSE held a hearing regarding the Partnership’s appeal on April 20, 2016 and affirmed its prior decision to delist the Partnership’s common units. On April 27, 2016, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist the Partnership’s common units and terminate the registration of the Partnership’s common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on May 9, 2016. The Partnership’s common units continued to trade on the OTCQB Marketplace under the ticker symbol “RHNOD” until May 16, 2016, at which time the OTCQB ticker symbol reverted to “RHNO.”

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND GENERAL

Investments in Unconsolidated Affiliates. 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 investments 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 located in Central Appalachia. The Partnership accounted for the investment in the joint venture and its results of operations under the equity method. In January 2015, the Partnership completed a Membership Transfer Agreement (the “Transfer Agreement”) with an affiliate of Patriot that terminated the Rhino Eastern joint venture. Pursuant to the Transfer Agreement, Patriot sold and assigned its 49% membership interest in the Rhino Eastern joint venture to the Partnership and, in consideration of this transfer, Patriot received certain fixed assets, leased equipment and coal reserves associated with the mining area previously operated by the Rhino Eastern joint venture. Patriot also assumed substantially all of the active workforce related to the Eagle mining area that was previously employed by the Rhino Eastern joint venture. The Partnership retained approximately 34 million tons of coal reserves that are not related to the Eagle mining area as well as a prepaid advanced royalty balance. As part of the closing of the Transfer Agreement, the Partnership and Patriot agreed to a dissolution payment based upon a final working capital adjustment calculation as defined in the Transfer Agreement. Refer to Note 17 for information on the financial statement impact of the Rhino Eastern dissolution completed in January 2015.

In December 2012, the Partnership made an initial investment of approximately $2.0 million in a new joint venture, Muskie Proppant LLC (“Muskie”), with affiliates of Wexford Capital. Muskie was formed to provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States. The Partnership accounted for the investment in the joint venture and results of operations under the equity method. In November 2014, the Partnership contributed its interest in Muskie to Mammoth Energy Partners LP (“Mammoth”), which is discussed below.

In November 2014, the Partnership contributed its investment interest in Muskie to Mammoth in return for a limited partner interest in Mammoth. Mammoth was formed to own various companies that provide services to companies, which engage in the exploration and development of North American onshore unconventional oil and natural gas reserves. Mammoth’s companies provide services that include completion and production services, contract land and directional drilling services and remote accommodation services. The non-cash transaction was a contribution of the Partnership’s investment interest in the Muskie entity for an investment interest in Mammoth. Thus, the Partnership determined that the non-cash exchange of the Partnership’s ownership interest in Muskie did not result in any gain or loss. As of June 30, 2016 and 2015, the Partnership has recorded its investment in Mammoth of $1.9 million as a long-term asset, which the Partnership records as a cost method investment based upon its ownership percentage. The Partnership has included its investment in Mammoth and its prior investment in Muskie in its Other category for segment reporting purposes.

In September 2014, the Partnership made an initial investment of $5.0 million in a new joint venture, Sturgeon Acquisitions LLC (“Sturgeon”), with affiliates of Wexford Capital and Gulfport Energy (“Gulfport”), a publicly traded company. Sturgeon subsequently acquired 100% of the outstanding equity interests of certain limited liability companies located in Wisconsin that provide frac sand for oil and natural gas drillers in the United States. The Partnership accounts for the investment in the joint venture and results of operations under the equity method. The Partnership recorded its proportionate share of the operating (loss) for Sturgeon for the three and six months ended June 30, 2016 of approximately ($26,000) and ($0.1) million, respectively. The Partnership recorded its proportionate share of the operating income for Sturgeon for the three and six months ended June 30, 2015 of approximately $0.1 million and $0.3 million, respectively. The Partnership has included the operating activities of Sturgeon in its Other category for segment reporting purposes.

Recently Issued Accounting Standards. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”). ASU 2014-09 clarifies the principles for recognizing revenue and establishes a common revenue standard for U.S. financial reporting purposes. The guidance in ASU 2014-09 affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). ASU 2014-09 supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 605, Revenue Recognition, and most industry-specific accounting guidance. Additionally, ASU 2014-09 supersedes some cost guidance included in ASC 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of ASC 360, Property, Plant, and Equipment, and intangible assets within the scope of ASC 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in ASU 2014-09. In July 2015, the FASB approved to defer the effective date of ASU 2014-09 by one year. Accordingly, ASU 2014-09 will be effective for public entities for annual reporting periods beginning after December 15, 2017 and interim periods therein. The Partnership is evaluating the requirements of this new accounting guidance.

In January 2015, the FASB issued ASU 2015-01, “Income Statement-Extraordinary and Unusual Items”. ASC 225-20, Income Statement—Extraordinary and Unusual Items, required that an entity separately classify, present, and disclose extraordinary events and transactions. ASU 2015-01 eliminates the concept of extraordinary items. The amendments in ASU 2015-01 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity also may apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. The effective date is the same for both public business entities and all other entities. The adoption of ASU 2015-01 on January 1, 2016 did not have a material impact on the Partnership’s financial statements.

In February 2015, the FASB issued ASU 2015-02, “Consolidation”. ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, the amendments of ASU 2015-02: a) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, b) eliminate the presumption that a general partner should consolidate a limited partnership, c) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and d) provide a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. ASU 2015-02 is effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. A reporting entity may apply the amendments in this Update using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. A reporting entity also may apply the amendments retrospectively. The adoption of ASU 2015-02 on January 1, 2016 did not have a material impact on the Partnership’s financial statements.

In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30)-Simplifying the Presentation of Debt Issuance Costs”. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to ASU 2015-03, debt issuance costs have been presented in the balance sheet as a deferred charge, or asset. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. For public business entities, ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of ASU 2015-03 is permitted for financial statements that have not been previously issued. In addition, ASU 2015-03 requires entities to apply the new guidance on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The adoption of ASU 2015-03 on January 1, 2016 did not have a material impact on the Partnership’s financial statements.

3. DISCONTINUED OPERATIONS

Utica Shale Oil and Natural Gas Assets

Beginning in 2011, the Partnership and an affiliate of Wexford Capital participated with Gulfport to acquire interests in a portfolio of oil and natural gas leases in the Utica Shale, which consisted of a 5% interest in a total of approximately 152,300 gross acres, or approximately 7,615 net acres. In March 2014, the Partnership completed a purchase and sale agreement with Gulfport to sell the Partnership’s oil and natural gas properties in the Utica Shale region. In addition, in January 2014, the Partnership received approximately $8.4 million of net proceeds from the sale by Blackhawk Midstream LLC (“Blackhawk”) of its equity interest in two entities, Ohio Gathering Company, LLC and Ohio Condensate Company, LLC, to Summit Midstream Partners, LLC. As part of the joint operating agreement for the Utica Shale investment discussed above, the Partnership had the right to approximately 5% of the proceeds of the sale by Blackhawk. In February 2015, the Partnership received approximately $0.7 million in additional proceeds from the sale by Blackhawk that had been held in escrow. For the six months ended June 30, 2015, the Partnership recorded the $0.7 million in Income from discontinued operations in the unaudited condensed consolidated statements of operations and comprehensive income. The gain from the Blackhawk transaction is included in the (Gain) on sale/disposal of assets—net line in the operating activities section of the Partnership’s unaudited condensed consolidated statements of cash flows. The proceeds from the Blackhawk transaction are included in the Proceeds from sales of property, plant, and equipment line in the investing activities section of the Partnership’s unaudited condensed consolidated statements of cash flows.

4. PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other current assets as of June 30, 2016 and December 31, 2015 consisted of the following:

	June 30, 2016		December 31, 2015
	(in thousands)
Other prepaid expenses	$	474	$	682
Debt issuance costs—net		-		2,155
Prepaid insurance		2,495		1,492
Prepaid leases		57		80
Supply inventory		955		901
Deposits		164		164
Total Prepaid expenses and other	$	4,145	$	5,474

Debt issuance costs were included in Prepaid expenses and other current assets as of December 31, 2015 since the Partnership classified its credit facility balance as a current liability prior to the fifth amendment to the credit facility completed in May 2016. See Note 7 for further information on debt issuance costs and accumulated amortization of debt issuance costs as of June 30, 2016 and December 31, 2015. See Note 9 for further information on the amendments to the amended and restated senior secured credit facility.

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including coal properties and mine development and construction costs, as of June 30, 2016 and December 31, 2015 are summarized by major classification as follows:

	Useful Lives	June 30, 2016			December 31, 2015
		(in thousands)
Land and land improvements		$	23,752		$	24,157
Mining and other equipment and related facilities	2 - 20 Years		305,606			306,609
Mine development costs	1 - 15 Years		60,340			67,277
Coal properties	1 - 15 Years		85,087			203,791
Construction work in process			2,147			2,680
Total			476,932			604,514
Less accumulated depreciation, depletion and amortization			(270,038	)		(271,007	)
Net		$	206,894		$	333,507

Depreciation expense for mining and other equipment and related facilities, depletion expense for coal properties and oil and natural gas properties, amortization expense for mine development costs, amortization expense for intangible assets and amortization expense for asset retirement costs for the three and six months ended June 30, 2016 and 2015 were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in thousands)
Depreciation expense-mining and other equipment and related facilities	$	5,031		$	7,391		$	10,327		$	14,968
Depletion expense for coal properties and oil and natural gas properties		532			727			1,114			1,534
Amortization expense for mine development costs		379			558			782			1,081
Amortization expense for intangible assets		8			20			16			40
Amortization expense for asset retirement costs		(19	)		(100	)		(61	)		(175	)
Total depreciation, depletion and amortization	$	5,931		$	8,596		$	12,178		$	17,448

Asset Impairment

The Partnership’s Elk Horn coal leasing company is located in eastern Kentucky and provides the Partnership with coal royalty revenues from coal properties owned by Elk Horn and leased to third party operators. The ongoing weakness in the central Appalachia steam coal markets has adversely affected the price and demand for steam coal produced by operators that mine coal on the Elk Horn properties. Thus, Elk Horn’s royalty revenues have also declined as the operators produce less coal and prices for steam are depressed. During the second quarter of 2016, the Partnership received an inquiry from a third party interested in purchasing Elk Horn. Based upon the price offered by the third party and the continued deterioration of the central Appalachia steam coal markets that has adversely affected Elk Horn’s financial results, the Partnership decided to evaluate the Elk Horn assets for potential impairment as of June 30, 2016. The Partnership’s impairment analysis determined that a potential impairment existed since the carrying amount of the Elk Horn long-lived asset group exceeded the cash flows that would be generated from the purchase price offered from the third party. Based on a market approach used to estimate the fair value of the Elk Horn long-lived asset group, the Partnership recorded total asset impairment charges of approximately $118.7 million related to Coal properties for the three and six months ended June 30, 2016, which is recorded on the Loss on asset impairments line of the unaudited condensed consolidated statements of operations and comprehensive income.

6. GOODWILL AND INTANGIBLE ASSETS

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

Intangible assets as of June 30, 2016 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Trade Name	$	184	$	46	$	138
Customer List		470		119		351
Total	$	654	$	165	$	489

Intangible assets as of December 31, 2015 consisted of the following:

	Gross				Net
	Carrying		Accumulated		Carrying
Intangible Asset	Amount		Amortization		Amount
	(in thousands)
Trade Name	$	184	$	42	$	142
Customer List		470		107		363
Total	$	654	$	149	$	505

The Partnership considers the trade name and customer list intangible assets to have a useful life of twenty years and are amortized over their useful life on a straight-line basis.

Amortization expense for the three and six months ended June 30, 2016 and 2015 is included in the depreciation, depletion and amortization table included in Note 5. The future total amortization expense for each of the five succeeding years related to intangible assets that are currently recorded in the unaudited condensed consolidated statement of financial position is estimated to be as follows at June 30, 2016:

			Customer
	Trade Name		List		Total
			(in thousands)
2016 (from Jul 1 to Dec 31)	$	4	$	12	$	16
2017		9		23		32
2018		9		23		32
2019		9		23		32
2020		9		23		32

7. OTHER NON-CURRENT ASSETS

Other non-current assets as of June 30, 2016 and December 31, 2015 consisted of the following:

	June 30, 2016		December 31, 2015
	(in thousands)
Deposits and other	$	154	$	138
Debt issuance costs—net		2,555		-
Non-current receivable		23,908		23,908
Note Receivable		2,064		2,000
Deferred expenses		234		261
Total	$	28,915	$	26,307

Debt issuance costs were included in Prepaid expenses and other current assets as of December 31, 2015 since the Partnership classified its credit facility balance as a current liability prior to the fifth amendment to the credit facility completed in May 2016 and discussed further below (see Note 4 for Prepaid expenses and other current assets). Debt issuance costs were $13.1 million and $11.6 million as of June 30, 2016 and December 31, 2015, respectively. Accumulated amortization of debt issuance costs were $10.5 million and $9.4 million as of June 30, 2016 and December 31, 2015, respectively.

In April 2015, the Partnership entered into a third amendment of its amended and restated senior secured credit facility that reduced the borrowing commitment to $100 million. As part of executing the third amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $2.1 million to the lenders in April 2015, which was recorded as an addition to Debt issuance costs. The Partnership wrote-off approximately $0.2 million of its remaining unamortized debt issuance costs since the third amendment reduced the borrowing commitment under the amended and restated senior secured credit facility.

In March 2016, the Partnership entered into a fourth amendment of its amended and restated senior secured credit facility that reduced the borrowing commitment to $80 million. As part of executing the fourth amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $0.4 million to the lenders in March 2016, which was recorded as an addition to Debt issuance costs. The Partnership wrote-off approximately $0.2 million of its remaining unamortized debt issuance costs since the fourth amendment reduced the borrowing commitment under the amended and restated senior secured credit facility.

In May 2016, the Partnership entered into a fifth amendment of its amended and restated senior secured credit facility that reduced the borrowing commitment to $75 million. As part of executing the fifth amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $1.2 million to the lenders in May 2016, which was recorded as an addition to Debt issuance costs. The Partnership wrote-off approximately $0.1 million of its remaining unamortized debt issuance costs since the fifth amendment reduced the borrowing commitment under the amended and restated senior secured credit facility. See Note 9 for further information on the amendments to the amended and restated senior secured credit facility.

The non-current receivable balance of $23.9 million as of June 30, 2016 and December 31, 2015 consisted of the amount due from the Partnership’s workers’ compensation insurance providers for potential claims against the Partnership that are the primary responsibility of the Partnership, which are covered under the Partnership’s insurance policies. The $23.9 million is also included in the Partnership’s accrued workers’ compensation benefits liability balance, which is included in the non-current liabilities section of the Partnership’s unaudited condensed consolidated statements of financial position. The Partnership presents this amount on a gross asset and liability basis since a right of setoff does not exist per the accounting guidance in ASC Topic 210, Balance Sheet. This presentation has no impact on the Partnership’s results of operations or cash flows.

8. ACCRUED EXPENSES AND OTHER CURRENT LIABILITIES

Accrued expenses and other current liabilities as of June 30, 2016 and December 31, 2015 consisted of the following:

	June 30, 2016		December 31, 2015
	(in thousands)
Payroll, bonus and vacation expense	$	1,451	$	1,447
Non income taxes		3,576		3,774
Royalty expenses		1,466		1,566
Accrued interest		1,120		575
Health claims		839		817
Workers’ compensation & pneumoconiosis		1,150		1,150
Deferred revenues		1,800		2,260
Accrued insured litigation claims		302		266
Other		519		2,247
Total	$	12,223	$	14,102

The $0.3 million accrued for insured litigation claims as of June 30, 2016 and December 31, 2015 consists of probable and estimable litigation claims that are the primary obligation of the Partnership. The amount accrued for litigation claims is also due from the Partnership’s insurance providers and is included in Accounts receivable, net of allowance for doubtful accounts on the Partnership’s unaudited condensed consolidated statements of financial position. The Partnership presents this amount on a gross asset and liability basis, as a right of setoff does not exist per the accounting guidance in ASC Topic 210, Balance Sheet. This presentation has no impact on the Partnership’s results of operations or cash flows.

9. DEBT

Debt as of June 30, 2016 and December 31, 2015 consisted of the following:

	June 30, 2016			December 31, 2015
	(in thousands)
Senior secured credit facility with PNC Bank, N.A.	$	37,750		$	41,200
Other notes payable		2,763			2,874
Total		40,513			44,074
Less current portion		(288	)		(41,479	)
Long-term debt	$	40,225		$	2,595

Senior Secured Credit Facility with PNC Bank, N.A.—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 was $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 was available for letters of credit. As described below, in April 2015, March 2016 and May 2016, the amended and restated credit facility was amended and the borrowing commitment under the facility was reduced to $75 million, with the amount available for letters of credit reduced to $30 million. Borrowings under the facility bear interest, which per the March 2016 amendment described further below, is based upon the current PRIME rate plus an applicable margin of 3.50%. As part of the agreement, the Operating Company is required to pay a commitment fee on the unused portion of the borrowing availability. 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-month period ended June 30, 2016. Per the May 2016 amendment described further below, the amended and restated senior secured credit facility is set to expire on July 31, 2017, with the possibility to extend the facility to December 31, 2017 if certain conditions are met as described below.

In April 2015, the Partnership entered into a third amendment of its amended and restated senior secured credit facility. The third amendment reduced the borrowing commitment under the credit facility to a maximum of $100 million and reduced the amount available for letters of credit to $50 million. The third amendment also provides that the disposition of any assets by the Partnership consisting of net cash proceeds up to an aggregate $35 million shall reduce the total commitment under the facility on a dollar-for-dollar basis by up to a total of $10 million, and any dispositions of assets in excess of $35 million in the aggregate shall reduce the commitment under the facility on a dollar-for-dollar basis. The third amendment limits the Partnership’s quarterly distributions to a maximum of $0.035 per unit unless (i) the pro forma leverage ratio of the Partnership, immediately prior to and after giving effect to such distribution, is less than or equal to 3.0 to 1.0 and (ii) the amount of borrowings available under the credit facility, immediately prior to and after giving effect to such distribution, is at least $20 million. In addition, the third amendment removed the interest coverage ratio covenant and replaced it with a minimum fixed charge coverage ratio, which consists of the ratio of consolidated EBITDA minus maintenance capital expenditures to fixed charges. Fixed charges are defined in the third amendment to include the sum of cash interest expense, scheduled principal installments on indebtedness (as adjusted for prepayments), dividends and distributions. Commencing with the quarter ended September 30, 2015, the fixed charge coverage ratio for the trailing four quarters must be a minimum of 1.1 to 1.0. The third amendment also limits any investments made by the Partnership, including investments in hydrocarbons, to $10 million provided that the leverage ratio is less than or equal to 3.0 to 1.0 and the borrowers’ available liquidity is at least $20 million. The third amendment does not permit the Partnership to issue any new equity of the Partnership unless the proceeds of such equity issuance are used to reduce the outstanding borrowings under the facility. Issuances of equity under the Partnership’s long-term incentive plan are excluded from this requirement. The third amendment limits the amount of the Partnership’s capital expenditures to $20.0 million for fiscal year 2015 and limited capital expenditures to $27.5 million for each fiscal year after 2015. However, to the extent that capital expenditures for any fiscal year are less than indicated above, the Partnership may increase the following year’s capital expenditures by the lesser of such unused amount or $5.0 million. As part of executing the third amendment to the amended and restated senior secured credit facility, the Operating Company paid a fee of approximately $2.1 million to the lenders in April 2015, which was recorded in Debt issuance costs in Other non-current assets on the Partnership’s unaudited condensed consolidated statements of financial position. In addition, the Partnership recorded a non-cash charge of approximately $0.2 million to write-off a portion of its unamortized debt issuance costs since the third amendment reduced the borrowing commitment under the amended and restated senior secured credit facility, which was recorded in Interest expense on the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

In March 2016, the Partnership entered into a fourth amendment (the “Fourth Amendment”) of its amended and restated senior secured credit facility. The Fourth Amendment amended the definition of change of control in the amended and restated credit agreement to permit Royal to purchase the membership interests of the General Partner and set the expiration of the facility to July 29, 2016. The Fourth Amendment reduced the borrowing capacity under the credit facility to a maximum of $80 million and reduced the amount available for letters of credit to $30 million. The Fourth Amendment eliminated the option to borrow funds utilizing the LIBOR rate plus an applicable margin and established the borrowing rate for all borrowings under the facility to be based upon the current PRIME rate plus an applicable margin of 3.50%. The Fourth Amendment eliminated the capability to make Swing Loans under the facility and eliminated the ability of the Partnership to pay distributions to its common or subordinated unitholders. The Fourth Amendment altered the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve-month basis, to 6.75 to 1.00. The leverage ratio shall be reduced by 0.50 to 1.00 for every $10 million of net cash proceeds, in the aggregate, received by the Partnership after the date of the Fourth Amendment from a liquidity event; provided, however, that in no event shall the maximum permitted leverage ratio be reduced below 3.00 to 1.00. A liquidity event is defined in the Fourth Amendment as the issuance of any equity by the Partnership on or after the Fourth Amendment effective date (other than the Royal equity contribution discussed above), or the disposition of any assets by the Partnership. The Fourth Amendment requires the Partnership to maintain minimum liquidity of $5 million and minimum EBITDA (as defined in the credit agreement), calculated as of the end of the most recent month, on a trailing twelve month basis, of $8 million. The Fourth Amendment limits the amount of the Partnership’s capital expenditures to $15 million, calculated as of end of the most recent month, on a trailing twelve-month basis. The Fourth Amendment requires the Partnership to provide monthly financial statements and a weekly rolling thirteen-week cash flow forecast to the administrative agent.

On May 13, 2016, the Partnership entered into a fifth amendment (the “Fifth Amendment”) of its amended and restated senior secured credit facility that extends the term of the senior secured credit facility to July 31, 2017. Per the Fifth Amendment, the credit facility will be automatically extended to December 31, 2017 if revolving credit commitments are reduced to $55 million or less on or before July 31, 2017. The Fifth Amendment immediately reduces the revolving credit commitments under the credit facility to a maximum of $75 million and maintains the amount available for letters of credit at $30 million. The Fifth Amendment further reduces the revolving credit commitments over time on a dollar-for-dollar basis in amounts equal to each of the following: (i) the face amount of any letter of credit that expires or whose face amount is reduced by any such dollar amount, (ii) the net proceeds received from any asset sales, (iii) the Royal scheduled capital contributions (as outlined below), (iv) the net proceeds from the issuance of any equity by the Partnership up to $20.0 million (other than equity issued in exchange for any Royal contribution as outlined in the Securities Purchase Agreement or the Royal scheduled capital contributions to the Partnership as outlined below), and (v) the proceeds from the incurrence of any subordinated debt. The first $11 million of proceeds received from any equity issued by the Partnership described in clause (iv) above shall also satisfy the Royal scheduled capital contributions as outlined below. The Fifth Amendment requires Royal to contribute $2 million each quarter beginning September 30, 2016 through September 30, 2017 and $1 million on December 1, 2017, for a total of $11 million. The Fifth Amendment further reduces the revolving credit commitments as follows:

Date of Reduction		Reduction Amount

September 30, 2016		The lesser of (i) $2 million or (ii) the positive difference (if any) of $2 million minus the proceeds from the issuance of any Partnership equity (excluding any Royal equity contributions)

December 31, 2016		The lesser of (i) $2 million or (ii) the positive difference (if any) of $4 million minus the proceeds from the issuance of any Partnership equity (excluding any Royal equity contributions)

March 31, 2017		The lesser of (i) $2 million or (ii) the positive difference (if any) of $6 million minus the proceeds from the issuance of any Partnership equity (excluding any Royal equity contributions)

June 30, 2017		The lesser of (i) $2 million or (ii) the positive difference (if any) of $8 million minus the proceeds from the issuance of any Partnership equity (excluding any Royal equity contributions)

September 30, 2017		The lesser of (i) $2 million or (ii) the positive difference (if any) of $10 million minus the proceeds from the issuance of any Partnership equity (excluding any Royal equity contributions)

December 1, 2017		The lesser of (i) $1 million or (ii) the positive difference (if any) of $11 million minus the proceeds from the issuance of any Partnership equity (excluding any Royal equity contributions)

The Fifth Amendment requires that on or before March 31, 2017, the Partnership shall have solicited bids for the potential sale of certain non-core assets, satisfactory to the administrative agent, and provided the administrative agent, and any other lender upon its request, with a description of the solicitation process, interested parties and any potential bids. The Fifth Amendment limits any payments by the Partnership to the General Partner to: (i) the usual and customary payroll and benefits of the Partnership’s management team so long as the Partnership’s management team remains employees of the General Partner, (2) the usual and customary board fees of the General Partner, and (3) the usual and customary general and administrative costs and expenses of the General Partner incurred in connection with the operation of its business in an amount not to exceed $0.3 million per fiscal year. The Fifth Amendment limits asset sales to a maximum of $5 million unless the Partnership receives consent from the lenders. The Fifth Amendment alters the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve-month basis, as follows:

Period				Ratio
For the month ending April 30, 2016, through the month ending May 31, 2016				7.50 to 1.00
For the month ending June 30, 2016, through the month ending August 31, 2016				7.25 to 1.00
For the month ending September 30, 2016, through the month ending November 30, 2016				7.00 to 1.00
For the month ending December 31, 2016, through the month ending March 31, 2017				6.75 to 1.00
For the month ending April 30, 2017, through the month ending June 30, 2017				6.25 to 1.00
For the month ending July 31, 2017, through the month ending November 30, 2017				6.0 to 1.00
For the month ending December 31, 2017				5.50 to 1.00

The leverage ratios above shall be reduced by 0.50 to 1.00 for every $10 million of aggregate proceeds received by the Partnership from: (i) the issuance of equity by the Partnership (excluding any Royal capital contributions) and/or (ii) the proceeds received from the sale of assets, provided that the leverage ratio shall not be reduced below 3.50 to 1.00. The Fifth Amendment removes the $5.0 million minimum liquidity requirement and requires the Partnership to have any deposit, securities or investment accounts with a member of the lending group.

At June 30, 2016, the Operating Company had borrowings outstanding (excluding letters of credit) of $37.8 million at a variable interest rate of PRIME plus 3.50% (7.00% at June 30, 2016). In addition, the Operating Company had outstanding letters of credit of approximately $27.8 million at a fixed interest rate of 5.00% at June 30, 2016. Based upon a maximum borrowing capacity of 7.25 times a trailing twelve-month EBITDA calculation (as defined in the credit agreement), the Operating Company had available borrowing capacity of approximately $6.7 million at June 30, 2016.

10. ASSET RETIREMENT OBLIGATIONS

The changes in asset retirement obligations for the six months ended June 30, 2016 and the year ended December 31, 2015 are as follows:

	June 30, 2016			December 31, 2015
	(in thousands)
Balance at beginning of period (including current portion)	$	23,747		$	29,883
Accretion expense		763			2,082
Adjustment resulting from addition of property		-			1,235
Adjustment resulting from disposal of property (1)		-			(6,861	)
Adjustments to the liability from annual recosting and other		-			(2,078	)
Liabilities settled		(142	)		(514	)
Balance at end of period		24,368			23,747
Less current portion of asset retirement obligation		(1,646	)		(767	)
Long-term portion of asset retirement obligation	$	22,722		$	22,980

(1)	The ($6.9) million adjustment for the year ended December 31, 2015 relates to the sale of the Partnership’s Deane mining complex.

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 that provided healthcare to eligible employees at its Hopedale operations. The Partnership has no other postretirement plans.

On December 10, 2015, the Partnership notified the employees at its Hopedale operations that healthcare benefits from the postretirement benefit plan would cease on January 31, 2016. The negative plan amendment that arose on December 10, 2015 resulted in an approximate $6.5 million prior service cost benefit. The Partnership amortized the prior service cost benefit over the remaining term of the benefits provided through January 31, 2016. For the six months ended June 30, 2016, the Partnership recognized a benefit of approximately $3.9 million from the plan amendment in the Cost of operations line of the unaudited condensed consolidated statements of operations and comprehensive income.

Net periodic benefit cost for the three and six months ended June 30, 2016 and 2015 are as follows:

	Three months ended June 30,					Six months ended June 30,
	2016		2015			2016			2015
	(in thousands)
Service costs	$	-	$	67		$	-		$	135
Interest cost		-		51			-			101
Amortization of (gain)		-		(44	)		(4,796	)		(89	)
Total	$	-	$	74		$	(4,796	)	$	147

For the three and six months ended June 30, 2016 and 2015, net periodic benefit costs, including the amortization of actuarial gain included in the table above, are included in Cost of operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income.

401(k) Plans—The Operating Company and certain subsidiaries sponsor defined contribution savings plans for all employees. Under one defined contribution savings plan, the Operating Company matches voluntary contributions of participants up to a maximum contribution based upon a percentage of a participant’s salary with an additional matching contribution possible at the Operating Company’s discretion. The expense under these plans for the three and six months ended June 30, 2016 and 2015 is included in Cost of operations and Selling, general and administrative expense in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income and was as follows:

	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(in thousands)
401(k) plan expense	$	405	$	595	$	713	$	1,153

12. EQUITY-BASED COMPENSATION

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

As of June 30, 2016, the General Partner had granted phantom units to certain employees and restricted units and unit awards to its directors. These grants consisted of annual restricted unit awards to directors and phantom unit awards with tandem distribution equivalent rights (“DERs”) granted in the first quarters from 2012 through 2015 to certain employees in connection with the prior year’s performance. The DERs consist of rights to accrue quarterly cash distributions in an amount equal to the cash distribution the Partnership makes to unitholders during the vesting period. These awards are subject to service based vesting conditions and any accrued distributions will be forfeited if the related awards fail to vest according to the relevant service based vesting conditions.

The Partnership accounts for its unit-based awards as liabilities with applicable mark-to-market adjustments at each reporting period because the Compensation Committee of the board of directors of the General Partner has historically elected to pay some of the awards in cash in lieu of issuing common units.

As discussed in Note 1, on March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of Rhino GP LLC as well as 9,455,252 issued and outstanding subordinated units from Wexford Capital. Royal obtained control of, and a majority limited partner interest, in the Partnership with the completion of this transaction, which constituted a change in control of the Partnership. The language in the Partnership’s phantom unit and restricted unit grant agreements states that all outstanding, unvested units will become immediately vested upon a change in control. The Partnership recognized approximately $10,000 of expense from the vesting of these units as a result of the change in control.

During the three months ended June 30, 2016, the General Partner granted fully vested common units to its board of directors as well as certain members of management. The Partnership recognized approximately $0.6 million of expense for the three months ended June 30, 2016 in relation to the common units granted.

13. COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts and Contingencies—As of June 30, 2016, the Partnership had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

Year		Tons (in thousands)		Number of customers
	2016 Q3-Q4		1,702		13
	2017		1,826		4
	2018		414		2

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

Leases—The Partnership leases various mining, transportation and other equipment under operating leases. The Partnership also leases coal reserves under agreements that call for royalties to be paid as the coal is mined. Lease and royalty expense for the three and six months ended June 30, 2016 and 2015 are included in Cost of operations in the Partnership’s unaudited condensed consolidated statements of operations and comprehensive income and was as follows:

	Three months ended June 30,				Six months ended June 30,
	2016		2015		2016		2015
	(in thousands)
Lease expense	$	1,049	$	1,298	$	2,092	$	2,419
Royalty expense	$	2,606	$	3,592	$	4,948	$	6,426

Joint Ventures—The Partnership may contribute additional capital to the Timber Wolf joint venture that was formed in the first quarter of 2012. The Partnership did not make any capital contributions to the Timber Wolf joint venture during the six months ended June 30, 2016 or 2015.

The Partnership may contribute additional capital to the Sturgeon joint venture that was formed in the third quarter of 2014. The Partnership made an initial capital contribution of $5.0 million during the third quarter ended September 30, 2014 based upon its proportionate ownership interest. The Partnership did not make any capital contributions to the Sturgeon joint venture during the six months ended June 30, 2016 or 2015.

14. EARNINGS PER UNIT (“EPU”)

On April 18, 2016, the Partnership completed a 1-for-10 reverse split on its common units and subordinated units. The following tables present a reconciliation of the numerators and denominators of the basic and diluted EPU calculations for the periods ended June 30, 2016 and 2015, which include the retrospective application of the 1-for-10 reverse unit split:

Three months ended June 30, 2016	General Partner			Common Unitholders			Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss):
Net (loss) from continuing operations	$	(808	)	$	(104,558	)	$	(16,587	)
Net income from discontinued operations		-			-			-
Total interest in net (loss)	$	(808	)	$	(104,558	)	$	(16,587	)
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations	$	-		$	-		$	-
Net income from discontinued operations		-			-			-
Interest in net income	$	-		$	-		$	-
Interest in net (loss) for EPU purposes:
Net (loss) from continuing operations	$	(808	)	$	(104,558	)	$	(16,587	)
Net income from discontinued operations		-			-			-
Interest in net (loss)	$	(808	)	$	(104,558	)	$	(16,587	)
Denominator:
Weighted average units used to compute basic EPU		n/a			7,788			1,236
Effect of dilutive securities — LTIP awards:
Dilutive securities for net (loss) from continuing operations		n/a			-			-
Dilutive securities for net income from discontinued operations		n/a			-			-
Total dilutive securities		n/a			-			-
Weighted average units used to compute diluted EPU		n/a			7,788			1,236

Net (loss)/income per limited partner unit, basic
Net (loss) per unit from continuing operations		n/a		$	(13.42	)	$	(13.42	)
Net income per unit from discontinued operations		n/a			-			-
Net (loss) per common unit, basic		n/a		$	(13.42	)	$	(13.42	)
Net (loss)/income per limited partner unit, diluted
Net (loss) per unit from continuing operations		n/a		$	(13.42	)	$	(13.42	)
Net income per unit from discontinued operations		n/a			-			-
Net (loss) per common unit, diluted		n/a		$	(13.42	)	$	(13.42	)

Six months ended June 30, 2016	General Partner			Common Unitholders			Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net (loss) from continuing operations	$	(832	)	$	(89,511	)	$	(32,833	)
Net income from discontinued operations		-			-			-
Total interest in net (loss)	$	(832	)	$	(89,511	)	$	(32,833	)
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations	$	-		$	-		$	-
Net income from discontinued operations		-			-			-
Interest in net income/(loss)	$	-		$	-		$	-
Interest in net (loss)/income for EPU purposes:
Net (loss) from continuing operations	$	(832	)	$	(89,511	)	$	(32,833	)
Net income from discontinued operations		-			-			-
Interest in net (loss)	$	(832	)	$	(89,511	)	$	(32,833	)
Denominator:
Weighted average units used to compute basic EPU		n/a			3,368			1,236
Effect of dilutive securities — LTIP awards:
Dilutive securities for net (loss) from continuing operations		n/a			-			-
Dilutive securities for net income from discontinued operations		n/a			-			-
Total dilutive securities		n/a			-			-
Weighted average units used to compute diluted EPU		n/a			3,368			1,236

Net (loss)/income per limited partner unit, basic
Net (loss) per unit from continuing operations		n/a		$	(26.57	)	$	(26.57	)
Net income per unit from discontinued operations		n/a			-			-
Net income per common unit, basic		n/a		$	(26.57	)	$	(26.57	)
Net (loss)/income per limited partner unit, diluted
Net (loss) per unit from continuing operations		n/a		$	(26.57	)	$	(26.57	)
Net income per unit from discontinued operations		n/a			-			-
Net income per common unit, diluted		n/a		$	(26.57	)	$	(26.57	)

Three months ended June 30, 2015	General Partner			Common Unitholders			Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss):
Net (loss) from continuing operations	$	(162	)	$	(4,563	)	$	(3,387	)
Net income from discontinued operations		-			-			-
Total interest in net (loss)	$	(162	)	$	(4,563	)	$	(3,387	)
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations	$	-		$	-		$	-
Net income from discontinued operations		-			-			-
Interest in net income/(loss)	$	-		$	-		$	-
Interest in net (loss) for EPU purposes:
Net (loss) from continuing operations	$	(162	)	$	(4,563	)	$	(3,387	)
Net income from discontinued operations		-			-			-
Interest in net (loss)	$	(162	)	$	(4,563	)	$	(3,387	)
Denominator:
Weighted average units used to compute basic EPU		n/a			1,670			1,240
Effect of dilutive securities — LTIP awards:
Dilutive securities for net (loss) from continuing operations		n/a			-			-
Dilutive securities for net income from discontinued operations		n/a			-			-
Total dilutive securities		n/a			-			-
Weighted average units used to compute diluted EPU		n/a			1,670			1,240

Net (loss)/income per limited partner unit, basic
Net (loss) per unit from continuing operations		n/a		$	(2.73	)	$	(2.73	)
Net income per unit from discontinued operations		n/a			-			-
Net (loss) per common unit, basic		n/a		$	(2.73	)	$	(2.73	)
Net (loss)/income per limited partner unit, diluted
Net (loss) per unit from continuing operations		n/a		$	(2.73	)	$	(2.73	)
Net income per unit from discontinued operations		n/a			-			-
Net (loss) per common unit, diluted		n/a		$	(2.73	)	$	(2.73	)

Six months ended June 30, 2015	General Partner			Common Unitholders			Subordinated Unitholders
	(in thousands, except per unit data)
Numerator:
Interest in net (loss)/income:
Net (loss) from continuing operations	$	(253	)	$	(7,128	)	$	(5,293	)
Net income from discontinued operations		14			406			302
Total interest in net income	$	(239	)	$	(6,722	)	$	(4,991	)
Impact of subordinated distribution suspension:
Net income/(loss) from continuing operations	$	5		$	140		$	(145	)
Net income from discontinued operations		-			-			-
Interest in net income/(loss)	$	5		$	140		$	(145	)
Interest in net (loss)/income for EPU purposes:
Net (loss) from continuing operations	$	(248	)	$	(6,988	)	$	(5,438	)
Net income from discontinued operations		14			406			302
Interest in net income	$	(234	)	$	(6,582	)	$	(5,136	)
Denominator:
Weighted average units used to compute basic EPU		n/a			1,669			1,240
Effect of dilutive securities — LTIP awards:
Dilutive securities for net income from continuing operations and discontinued operations		n/a			-			-
Weighted average units used to compute diluted EPU		n/a			1,669			1,240

Net income per limited partner unit, basic
Net income per unit from continuing operations		n/a		$	(4.18	)	$	(4.38	)
Net income per unit from discontinued operations		n/a			0.24			0.24
Net income per common unit, basic		n/a		$	(3.94	)	$	(4.14	)
Net income per limited partner unit, diluted
Net income per unit from continuing operations		n/a		$	(4.18	)	$	(4.38	)
Net income per unit from discontinued operations		n/a			0.24			0.24
Net income per common unit, diluted		n/a		$	(3.94	)	$	(4.14	)

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. Since the Partnership incurred total net losses for the three and six months ended June 30, 2016 and 2015, all potential dilutive units were excluded from the diluted EPU calculation for these periods because when an entity incurs a net loss in a period, potential dilutive units shall not be included in the computation of diluted EPU since their effect will always be anti-dilutive.

15. MAJOR CUSTOMERS

The Partnership had revenues or receivables from the following major customers that in each period equaled or exceeded 10% of revenues (Note: customers with “n/a” had revenue below the 10% threshold in any period where this is indicated):

	June 30, 2016		December 31, 2015		Six months ended		Six months ended
	Receivable Balance		Receivable Balance		June 30, 2016 Sales		June 30, 2015 Sales
	(in thousands)
PPL Corporation	$	1,274	$	1,881	$	20,624		16,335
PacifiCorp Energy		1,009		1,969		10,511		11,810
Big Rivers Electric Corporation		686		n/a		10,119		n/a
NRG Energy, Inc. (fka GenOn Energy, Inc.)		n/a		-		n/a		16,336

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 amended and restated senior secured credit facility was based upon a Level 2 measurement utilizing a market approach, which incorporated market-based interest rate information with credit risks similar to the Partnership. The fair value of the Partnership’s amended and restated senior secured credit facility approximates the carrying value at June 30, 2016.

As of June 30, 2016, the Partnership had a nonrecurring fair value measurement related to its Elk Horn asset impairment as described in Note 5. The nonrecurring fair value measurement for the Elk Horn asset impairment described in Note 5 as of June 30, 2016 was a Level 2 measurement. For the year ended December 31, 2015, the Partnership had nonrecurring fair value measurements related to its asset impairment actions. The nonrecurring fair value measurements for the asset impairments for the year ended December 31, 2015 were Level 3 measurements.

17. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

The unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2016 and 2015 excludes approximately $1.2 million and $0.4 million, respectively, of property additions, which are recorded in accounts payable.

In January 2015, the Partnership dissolved the Rhino Eastern joint venture with Patriot. As part of the dissolution, the Partnership retained coal reserves, a prepaid advanced royalty balance and other assets and liabilities. In addition, the Partnership and Patriot agreed to a dissolution payment as part of the dissolution based upon a final working capital adjustment calculation, which is a liability of the Partnership. The Partnership recorded the dissolution of the joint venture by removing the investment in the Rhino Eastern unconsolidated subsidiary and recording the specific assets and liabilities retained in the dissolution. The dissolution of the Rhino Eastern joint venture completed in January 2015 had no impact on the Partnership’s unconsolidated statements of operations and comprehensive income for the three and six months ended June 30, 2015. The unaudited condensed consolidated statement of cash flows for the six months ended June 30, 2015 excludes the removal of the investment in the unconsolidated subsidiary and the recognition of the retained assets and liabilities, which are detailed in the table below.

	(in thousands)
Coal properties (incl asset retirement costs)	$	12,104
Advance royalties, net of current portion		4,706
Other non-current assets - acquired		229
Other non-current assets - written off		(642	)
Accrued expenses and other		(2,012	)
Asset retirement obligations		(1,235	)
Net assets acquired		13,150
Investment in unconsolidated affiliates-Rhino Eastern - written off	$	(13,150	)

18. SEGMENT INFORMATION

The Partnership produces and markets coal from surface and underground mines in Kentucky, West Virginia, Ohio and Utah. The Partnership sells primarily to electric utilities in the United States. The Partnership also leases coal reserves to third parties in exchange for royalty revenues. For the three and six months ended June 30, 2016, 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 coal leasing operations), Northern Appalachia (comprised of both surface and underground mines located in Ohio), Rhino Western (comprised of an underground mine in Utah) and Illinois Basin (comprised of an underground mine in western Kentucky).

The Partnership’s Other category is comprised of the Partnership’s ancillary businesses and its remaining oil and natural gas activities. 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 information provided in the following tables represents the primary measures used to assess segment performance by the Partnership’s chief operating decision maker.

Reportable segment results of operations for the three months ended June 30, 2016 are as follows (Note: “DD&A” refers to depreciation, depletion and amortization):

	Central			Northern		Rhino			Illinois						Total
	Appalachia			Appalachia		Western			Basin			Other			Consolidated
	(in thousands)
Total revenues	$	6,756		$	11,581	$	8,324		$	16,000		$	79		$	42,740
DD&A		1,707			811		1,404			1,867			142			5,931
Interest expense		696			101		102			256			570			1,725
Net income (loss) from continuing operations	$	(122,199	)	$	1,858	$	(30	)	$	(747	)	$	(835	)	$	(121,953	)

Reportable segment results of operations for the six months ended June 30, 2016 are as follows:

	Central			Northern		Rhino			Illinois						Total
	Appalachia			Appalachia		Western			Basin			Other			Consolidated
	(in thousands)
Total revenues	$	13,467		$	20,733	$	17,921		$	30,880		$	168		$	83,169
DD&A		3,635			1,764		2,815			3,680			284			12,178
Interest expense		1,268			230		188			461			1,152			3,299
Net income (loss) from continuing operations	$	(125,948	)	$	5,839	$	(627	)	$	(1,437	)	$	(1,003	)	$	(123,176	)

Reportable segment results of operations for the three months ended June 30, 2015 are as follows:

	Central			Northern		Rhino			Illinois						Total
	Appalachia			Appalachia		Western			Basin			Other			Consolidated
	(in thousands)
Total revenues	$	19,013		$	16,757	$	10,092		$	10,583		$	320		$	56,765
DD&A		3,392			1,958		1,619			1,436			191			8,596
Interest expense		456			122		67			136			532			1,313
Net income (loss) from continuing operations	$	(3,824	)	$	1,505	$	(1,232	)	$	(2,648	)	$	(1,913	)	$	(8,112	)

Reportable segment results of operations for the six months ended June 30, 2015 are as follows:

	Central			Northern		Rhino			Illinois						Total
	Appalachia			Appalachia		Western			Basin			Other			Consolidated
	(in thousands)
Total revenues	$	41,263		$	34,088	$	18,552		$	17,762		$	1,284		$	112,949
DD&A		7,340			3,805		3,229			2,650			424			17,448
Interest expense		847			236		130			255			802			2,270
Net income (loss) from continuing operations	$	(4,054	)	$	2,684	$	(2,529	)	$	(7,188	)	$	(1,587	)	$	(12,674	)

19. SUBSEQUENT EVENTS

On July 7, 2016, the Partnership executed an agreement with the third party that held the approximately $2.8 million of other notes payable, as detailed in Note 9, to settle the debt for $1.1 million of cash consideration. The Partnership paid the $1.1 million in July 2016 and will recognize an approximate $1.7 million gain from the extinguishment of this debt.

For the quarter ended June 30, 2016, the Partnership continued the suspension of the cash distribution for its common units, which was initially suspended for the quarter ended June 30, 2015. No distribution will be paid for common or subordinated units for the quarter ended June 30, 2016. The Partnership’s common units accrue arrearages every quarter when the distribution level is below the minimum level of $0.445 per unit, as outlined in the Partnership’s limited partnership agreement. The Partnership initially lowered its quarterly common unit distribution below the minimum level of $0.445 per unit with the quarter ended September 30, 2014. Thus, the Partnership’s distributions for each of the quarters ended September 30, 2014 through the quarter ended June 30, 2016 were below the minimum level and the current amount of accumulated arrearages as of June 30, 2016 related to the common unit distribution was approximately $114.2 million.

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 included in our Annual Report on Form 10-K for the year ended December 31, 2015 and the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in such 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. Please read 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, 2015 and in Part II, Item 1A, “Risk Factors” in this Quarterly Report on Form 10-Q.

Overview

We are a diversified energy limited partnership formed in Delaware that is focused on coal and energy related assets and activities, including energy infrastructure investments. 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, we have expanded our business to include infrastructure support services, as well as other joint venture investments to provide for the transportation of hydrocarbons and drilling support services in the Utica Shale region. We have also invested in joint ventures that provide sand for fracking operations to drillers in the Utica Shale region and other oil and natural gas basins in the United States.

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, 2015, we controlled an estimated 363.6 million tons of proven and probable coal reserves, consisting of an estimated 310.1 million tons of steam coal and an estimated 53.5 million tons of metallurgical coal. In addition, as of December 31, 2015, we controlled an estimated 436.8 million tons of non-reserve coal deposits.

We operate underground and surface mines located in Kentucky, Ohio, West Virginia and Utah. The number of mines that we operate may vary from time to time depending on a number of factors, including the demand for and price of coal, depletion of economically recoverable reserves and availability of experienced labor.

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

For the three and six months ended June 30, 2016, we generated revenues of approximately $42.8 million and $83.2 million, respectively, and we generated net losses of approximately $121.9 million and $123.2 million, respectively. For the three months ended June 30, 2016, we produced and sold approximately 0.8 million tons of coal, of which approximately 96% were sold pursuant to supply contracts. For the six months ended June 30, 2016, we produced and sold approximately 1.6 million tons of coal, of which approximately 95% were sold pursuant to supply contracts.

Current Liquidity and Outlook

As of June 30, 2016, our available liquidity was $6.7 million, which consisted of the amount available under our amended and restated credit agreement dated July 29, 2011 (as amended and restated, the “Amended and Restated Credit Agreement”). On May 13, 2016, we entered into a fifth amendment of the Amended and Restated Credit Agreement (the “Fifth Amendment”), which extends the term of the Amended and Restated Credit Agreement to July 31, 2017 (see “—Liquidity and Capital Resources—Amended and Restated Credit Agreement” for further details of the Fifth Amendment).

Prior to our entry into the Fifth Amendment, we were unable to demonstrate that we had sufficient liquidity to operate our business over the subsequent twelve months and thus, substantial doubt was raised about our ability to continue as a going concern. Accordingly, our independent registered public accounting firm included an emphasis paragraph with respect to our ability to continue as a going concern in its report on our consolidated financial statements for the year ended December 31, 2015. The presence of the going concern emphasis paragraph in our auditors’ report may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors, lenders and employees, making it difficult to raise additional debt or equity financing to the extent needed and conduct normal operations. As a result, our business, results of operations, financial condition and prospects could be materially adversely affected.

Given the continued weak demand and low prices for met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our credit agreement. If we violate any of the covenants or restrictions in our Amended and Restated Credit Agreement, including the maximum leverage ratio and minimum EBITDA requirements, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our Amended and Restated Credit Agreement. Although we believe our lenders loans are well secured under the terms of our Amended and Restated Credit Agreement, there is no assurance that the lenders would agree to any such waiver. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to further curtail our operations and reduce our spending and to alter our business plan. We may also be required to consider other options, such as selling additional assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time. If we are not able to fund our liquidity requirements for the next twelve months, we may not be able to continue as a going concern. For more information about our liquidity and our credit facility, please read “—Liquidity and Capital Resources.”

We continue to take measures, including the suspension of cash distributions on our common and subordinated units and cost and productivity improvements to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures and meet our financial commitments and debt service obligations.

Recent Developments

Asset Impairment

Our Elk Horn coal leasing company is located in eastern Kentucky and provides us with coal royalty revenues from coal properties owned by Elk Horn and leased to third party operators. The ongoing weakness in the central Appalachia steam coal markets has adversely affected the price and demand for steam coal produced by operators that mine coal on the Elk Horn properties. Thus, Elk Horn’s royalty revenues have also declined as the operators produce less coal and prices for steam are depressed. During the second quarter of 2016, we received an inquiry from a third party interested in purchasing Elk Horn. Based upon the price offered by the third party and the continued deterioration of the central Appalachia steam coal markets that has adversely affected Elk Horn’s financial results, we decided to evaluate the Elk Horn assets for potential impairment as of June 30, 2016. Our impairment analysis determined that a potential impairment existed since the carrying amount of the Elk Horn long-lived asset group exceeded the cash flows that would be generated from the purchase price offered from the third party. Based on a market approach used to estimate the fair value of the Elk Horn long-lived asset group, we recorded total asset impairment charges of approximately $118.7 million for the three and six months ended June 30, 2016.

Sale of our General Partner by Wexford Capital LP

On January 21, 2016, a definitive agreement was completed between Royal Energy Resources, Inc. (“Royal”) and Wexford Capital LP (“Wexford”) where Royal acquired 6,769,112 of our issued and outstanding common units from Wexford. The definitive agreement also included the committed acquisition by Royal within 60 days from the date of the definitive agreement, or March 21, 2016, of all of the issued and outstanding membership interests of Rhino GP LLC, our general partner, as well as 9,455,252 of our issued and outstanding subordinated units from Wexford. Royal is a publicly traded company listed on the OTC market (OTCQB: ROYE) and is focused on the acquisition of coal, natural gas and renewable energy assets that are profitable at current distressed prices.

On March 17, 2016, Royal completed the acquisition of all of the issued and outstanding membership interests of our general partner as well as the 9,455,252 issued and outstanding subordinated units from Wexford. Royal obtained control of, and a majority limited partner interest, in us with the completion of this transaction. Immediately subsequent to the consummation of the transaction, the following members of the board of directors of our general partner tendered their resignations effective immediately: Mark Zand, Philip Braunstein, Ken Rubin, Arthur Amron, Douglas Lambert and Mark Plaumann. As the owner of our general partner, Royal has the right to appoint the members of the board of directors of our general partner and so appointed the following individuals as new directors to fill the vacancies resulting from the resignations: William Tuorto, Ronald Phillips, Michael Thompson, Ian Ganzer, Douglas Holsted, Brian Hughs and David Hanig.

Private Placement of Common Units to Royal

On March 21, 2016, we and Royal entered into a securities purchase agreement (the “Securities Purchase Agreement”) pursuant to which we issued 60,000,000 of our common units to Royal in a private placement at $0.15 per common unit for an aggregate purchase price of $9.0 million. Royal paid us $2.0 million in cash and delivered a promissory note payable to us in the amount of $7.0 million. The promissory note is payable in three installments: (i) $3.0 million on July 31, 2016; (ii) $2.0 million on or before September 30, 2016 and (iii) $2.0 million on or before December 31, 2016. In the event the disinterested members of the board of directors of our general partner determine that we do not need the capital that would be provided by either or both installments set forth in (ii) and (iii) above, in each case, we have the option to rescind Royal’s purchase of 13,333,333 common units and the applicable installment will not be payable (each, a “Rescission Right”). If we fail to exercise a Rescission Right, in each case, we have the option to repurchase 13,333,333 of our common units at $0.30 per common unit from Royal (each, a “Repurchase Option”). The Repurchase Options terminate on December 31, 2017. Royal’s obligation to pay any installment of the promissory note is subject to certain conditions, including that we have entered into an agreement to extend the amended and restated credit agreement to a date no sooner than December 31, 2017. In the event such conditions are not satisfied as of the date each installment is due, Royal has the right to cancel the remaining unpaid balance of the promissory note in exchange for the surrender of such number of common units equal to the principal balance of the promissory note divided by $0.15. On May 13, 2016, Royal paid us the $3.0 million promissory note installment that was due July 31, 2016. The payment was made in relation to the fifth amendment of the Amended and Restated Credit Agreement completed on May 13, 2016, which is discussed further below.

Fourth and Fifth Amendments to Amended and Restated Credit Agreement

On March 17, 2016, our operating company, as borrower, and we and certain of our subsidiaries, as guarantors, entered into an amendment (the “Fourth Amendment”) of our Amended and Restated Credit Agreement. The Fourth Amendment amended the definition of change of control in our Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of our general partner.

On May 13, 2016, we entered into the Fifth Amendment of the Amended and Restated Credit Agreement, which extended the term to July 31, 2017 (see “—Liquidity and Capital Resources—Amended and Restated Credit Agreement” for further details of the Fourth and Fifth Amendments).

Suspension and Delisting of Common Units from the New York Stock Exchange (“NYSE”)

As previously disclosed, on December 17, 2015, the NYSE notified us that that the NYSE had determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million for our common units. The NYSE also suspended the trading of our common units at the close of trading on December 17, 2015.

On January 4, 2016, we filed an appeal with the NYSE to review the suspension and delisting determination of our common units. The NYSE held a hearing regarding our appeal on April 20, 2016 and affirmed its prior decision to delist our common units.

On April 27, 2016, the NYSE filed with the SEC a notification of removal from listing and registration on Form 25 to delist our common units and terminate the registration of our common units under Section 12(b) of the Securities Exchange Act of 1934. The delisting became effective on May 9, 2016. The Partnership’s common units continued to trade on the OTCQB Marketplace under the ticker symbol “RHNOD” until May 16, 2016, at which time the OTCQB ticker symbol reverted to “RHNO.”

We are exploring the possibility of listing our common units on the NASDAQ Stock Market (“NASDAQ”), pending our capability to meet the NASDAQ initial listing standards.

Reverse Unit Split

On April 18, 2016, we completed a 1-for-10 reverse split on our common units and subordinated units. Pursuant to the reverse split, common unitholders received one common unit for every 10 common units owned on April 18, 2016 and subordinated unitholders received one subordinated unit for every 10 subordinated units owned on April 18, 2016. Any fractional units resulting from the reverse unit split were rounded to the nearest whole unit. The reverse unit split was intended to increase the market price per unit of our common units in order to comply with the NYSE’s continued listing standards.

Distribution Suspension

Beginning with the quarter ended June 30, 2015 and continuing through the current quarter ended June 30, 2016, we have suspended the cash distribution for our common units. For the quarters ended September 30, 2014 and December 31, 2014, we announced cash distributions of $0.05 per common unit, or $0.20 per unit on an annualized basis, and for the quarter ended March 31, 2015, we announced cash distributions of $0.02 per common unit, or $0.08 per unit on an annualized basis. Each of these quarters’ distribution levels were lower than the historical quarters’ distribution amounts of $0.445 per common unit, or $1.78 per unit on an annualized basis. The distribution suspension and prior reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow.

Our common units accrue arrearages every quarter when the distribution level is below the minimum level of $0.445 per unit, as outlined in our limited partnership agreement. Since our distributions for the quarters ended September 30, 2014, December 31, 2014 and March 31, 2015 were below the minimum level and we suspended the distribution for the quarters ended June 30, 2015 through June 30, 2016, we have accumulated arrearages at June 30, 2016 related to the common unit distribution of approximately $114.2 million.

Cana Woodford

We had an oil and natural gas investment of approximately 1,900 net mineral acres in the Cana Woodford region of western Oklahoma. During the second quarter of 2015, we received unsolicited offers from third parties to purchase this oil and natural gas investment. We evaluated these offers in contemplation of a potential sale of these mineral rights. Due to the receipt of these offers and our potential sale of these mineral rights, we evaluated the appropriate held for sale accounting criteria to determine if the Cana Woodford mineral rights should be classified as held for sale as of June 30, 2015. Based on this evaluation, we determined these mineral rights met the held for sale criteria at June 30, 2015 and, accordingly, these mineral rights were written down to their estimated fair value. Due to the determination that the mineral rights met the held for sale criteria, we recorded an impairment charge of approximately $2.2 million for the Cana Woodford mineral rights during the three months ended June 30, 2015.

Factors That Impact Our Business

Our results of operations in the near term could be impacted by a number of factors, including (1) our ability to fund our ongoing operations and necessary capital expenditures, (2) the availability of transportation for coal shipments, (3) poor mining conditions resulting from geological conditions or the effects of prior mining, (4) equipment problems at mining locations, (5) adverse weather conditions and natural disasters or (6) 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) our ability to fund our ongoing operations and necessary capital expenditures, (2) changes in governmental regulation, (3) the availability and prices of competing electricity-generation fuels, (4) the world-wide demand for steel, which utilizes metallurgical coal and can affect the demand and prices of metallurgical coal that we produce, (5) our ability to secure or acquire high-quality coal reserves and (6) our ability to find buyers for coal under favorable supply contracts.

We have historically sold a majority of our coal through supply contracts and anticipate that we will continue to do so. As of June 30, 2016, we had commitments under sales contracts to deliver annually scheduled base quantities of coal as follows:

Year	Tons (in thousands)		Number of customers
2016 Q3-Q4		1,702		13
2017		1,826		4
2018		414		2

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

Results of Operations

Segment Information

As of June 30, 2016, we have four reportable business segments: Central Appalachia, Northern Appalachia, Rhino Western and Illinois Basin. Additionally, we have an Other category that includes our ancillary businesses and our remaining oil and natural gas activities. Our Central Appalachia segment consists of two mining complexes: Tug River and Rob Fork, which, as of June 30, 2016, together included one underground mine, three surface mines and three preparation plants and loadout facilities in eastern Kentucky and southern West Virginia. We resumed mining operations at a majority of our Central Appalachia operations during the three months ended March 31, 2016, but certain Central Appalachia mining operations have remained idle as we seek acceptable coal sales contracts that will allow mining to resume at these specific operations. Additionally, our Central Appalachia segment includes our Elk Horn coal leasing operations. Our Northern Appalachia segment consists of the Hopedale mining complex, the Sands Hill mining complex, and the Leesville field. The Hopedale mining complex, located in northern Ohio, included one underground mine and one preparation plant and loadout facility as of June 30, 2016. Our Sands Hill mining complex, located in southern Ohio, included two surface mines, a preparation plant and a river terminal as of June 30, 2016. Our Rhino Western segment includes our underground mine in the Western Bituminous region at our Castle Valley mining complex in Utah. Our Illinois Basin segment includes one underground mine, preparation plant and river loadout facility at our Pennyrile mining complex located in western Kentucky, as well as our Taylorville field reserves located in central Illinois.

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, while also excluding certain non-cash and/or 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.

Summary

The following table sets forth certain information regarding our revenues, operating expenses, other income and expenses, and operational data for the three and six months ended June 30, 2016 and 2015:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(in millions)
Statement of Operations Data:
Total revenues	$	42.8		$	56.8		$	83.2		$	112.9
Costs and expenses:
Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)		33.9			47.3			63.3			93.5
Freight and handling costs		0.5			0.7			1.1			1.2
Depreciation, depletion and amortization		5.9			8.6			12.2			17.4
Selling, general and administrative (exclusive of depreciation, depletion and amortization shown separately above)		4.0			4.9			8.0			9.3
Loss on asset impairments		118.7			2.2			118.7			2.2
(Gain) on sale/disposal of assets-net		-			-			(0.3	)		-
(Loss) from operations		(120.2	)		(6.9	)		(119.8	)		(10.7	)
Interest and other (expense)/income:
Interest expense		(1.7	)		(1.3	)		(3.3	)		(2.3	)
Interest income		-			-			-			-
Equity in net (loss)/income of unconsolidated affiliates		-			0.1			(0.1	)		0.3
Total interest and other (expense)		(1.7	)		(1.2	)		(3.4	)		(2.0	)
Net (loss) from continuing operations		(121.9	)		(8.1	)		(123.2	)		(12.7	)
Net income from discontinued operations		-			-			-			0.7
Net (loss)	$	(121.9	)	$	(8.1	)	$	(123.2	)	$	(12.0	)

Other Financial Data
Adjusted EBITDA from continuing operations	$	4.5		$	4.1		$	11.1		$	9.6
Net income from discontinued operations		-			-			-			0.7
Total Adjusted EBITDA	$	4.5		$	4.1		$	11.1		$	10.3

Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

Summary. For the three months ended June 30, 2016, our total revenues decreased to $42.8 million from $56.8 million for the three months ended June 30, 2015, which is a 24.7% decrease. We sold approximately 0.8 million tons of coal for the three months ended June 30, 2016, which is a 18.5% decrease compared to the tons of coal sold for the three months ended June 30, 2015. The decrease in revenue and tons sold was primarily the result of continued weak demand and low prices in the met and steam coal markets, particularly in Central Appalachia, partially offset by increased sales from our Pennyrile operation in the Illinois Basin. We believe the weak demand in the steam coal markets was primarily driven by a continued over-supply of low-priced natural gas, which electric utilities utilize as a source of electricity generation in lieu of steam coal. We believe the weak demand in the met coal markets was primarily driven by a decrease in worldwide steel production due to ongoing global economic weakness, particularly in China.

Net loss from continuing operations increased for the three months ended June 30, 2016 compared to the three months ended June 30, 2015. We generated a net loss from continuing operations of approximately $121.9 million for the three months ended June 30, 2016 compared to a net loss from continuing operations of approximately $8.1 million for the three months ended June 30, 2015. For the three months ended June 30, 2016, our total net loss from continuing operations was impacted by an asset impairment charge of $118.7 million related to our Elk Horn coal leasing company discussed earlier. For the three months ended June 30, 2015, our total net loss from continuing operations was impacted by an asset impairment charge of $2.2 million related to our Cana Woodford mineral rights discussed earlier.

Adjusted EBITDA from continuing operations increased to $4.5 million for the three months ended June 30, 2016 from $4.1 million for the three months ended June 30, 2015. Adjusted EBITDA from continuing operations increased period to period primarily due to the lower net loss generated year-to-year, once the impact of the asset impairments discussed above are removed from the net losses generated.

Tons Sold. The following table presents tons of coal sold by reportable segment for the three months ended June 30, 2016 and 2015:

	Three months		Three months		Increase/
	ended		ended		(Decrease)
Segment	June 30, 2016		June 30, 2015		Tons			% *
	(in thousands, except %)
Central Appalachia		88.2		233.3		(145.1	)		(62.2	)%
Northern Appalachia		161.2		252.8		(91.6	)		(36.2	)%
Rhino Western		215.1		268.2		(53.1	)		(19.8	)%
Illinois Basin		333.5		224.8		108.7			48.3	%
Total *		798.0		979.1		(181.1	)		(18.5	)%

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

We sold approximately 0.8 million tons of coal for the three months ended June 30, 2016, which was a 18.5% decrease compared to the three months ended June 30, 2015. The decrease in tons sold year-to-year was primarily due to lower sales from our Central Appalachia segment due to weak demand for met and steam coal from this region. Tons of coal sold in our Central Appalachia segment decreased by approximately 62.2% to approximately 0.1 million tons for the three months ended June 30, 2016 compared to the three months ended June 30, 2015, primarily due to a decrease in steam coal tons sold in the three months ended June 30, 2016 compared to 2015 due to ongoing weak market demand for coal from this region. For our Northern Appalachia segment, tons of coal sold decreased by approximately 36.2% for the three months ended June 30, 2016 compared to the three months ended June 30, 2015 as we experienced a decrease in tons sold from our Hopedale complex due to weak demand for coal from this region. Coal sales from our Rhino Western segment decreased by approximately 19.8% for the three months ended June 30, 2016 compared to the same period in 2015 due to decreased customer demand from our Castle Valley operation. For our Illinois Basin segment, tons of coal sold increased by approximately 48.3% for the three months ended June 30, 2016 compared to the three months ended June 30, 2015 as we increased production and sales year-to-year from our Pennyrile mine in western Kentucky to meet our contracted sales commitments.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the three months ended June 30, 2016 and 2015:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2016		June 30, 2015		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	5.6	$	13.7	$	(8.1	)		(59.4	)%
Freight and handling revenues		-		-		-			n/a
Other revenues		1.2		5.3		(4.1	)		(77.6	)%
Total revenues	$	6.8	$	19.0	$	(12.2	)		(64.5	)%
Coal revenues per ton*	$	63.03	$	58.65	$	4.38			7.5	%
Northern Appalachia
Coal revenues	$	9.2	$	14.3	$	(5.1	)		(35.7	)%
Freight and handling revenues		0.6		0.7		(0.1	)		(13.0	)%
Other revenues		1.8		1.8		-			2.2	%
Total revenues	$	11.6	$	16.8	$	(5.2	)		(30.9	)%
Coal revenues per ton*	$	57.21	$	56.77	$	0.44			0.8	%
Rhino Western
Coal revenues	$	8.3	$	10.1	$	(1.8	)		(17.4	)%
Freight and handling revenues		-		-		-			n/a
Other revenues		-		-		-			n/a
Total revenues	$	8.3	$	10.1	$	(1.8	)		(17.5	)%
Coal revenues per ton*	$	38.70	$	37.59	$	1.11			3.0	%
Illinois Basin
Coal revenues	$	16.0	$	10.4	$	5.6			54.5	%
Freight and handling revenues		-		-		-			n/a
Other revenues		-		0.2		(0.2	)		n/a
Total revenues	$	16.0	$	10.6	$	5.4			51.2	%
Coal revenues per ton*	$	47.98	$	46.07	$	1.91			4.1	%
Other**
Coal revenues		n/a		n/a		n/a			n/a
Freight and handling revenues		n/a		n/a		n/a			n/a
Other revenues		0.1		0.3		(0.2	)		(75.5	)%
Total revenues	$	0.1	$	0.3	$	(0.2	)		(75.5	)%
Coal revenues per ton*		n/a		n/a		n/a			n/a
Total
Coal revenues	$	39.1	$	48.5	$	(9.4	)		(19.3	)%
Freight and handling revenues		0.6		0.7		(0.1	)		(13.0	)%
Other revenues		3.1		7.6		(4.5	)		(60.0	)%
Total revenues	$	42.8	$	56.8	$	(14.0	)		(24.7	)%
Coal revenues per ton*	$	49.01	$	49.51	$	(0.50	)		(1.0	)%

*	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 also do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Other category.

Our coal revenues for the three months ended June 30, 2016 decreased by approximately $9.4 million, or 19.3%, to approximately $39.1 million from approximately $48.5 million for the three months ended June 30, 2015. The decrease in coal revenues was primarily due to fewer steam coal tons sold in Central Appalachia, partially offset by increased sales from our Pennyrile mine in the Illinois Basin. Coal revenues per ton was $49.01 for the three months ended June 30, 2016, a decrease of $0.50, or 1.0%, from $49.51 per ton for the three months ended June 30, 2015. This decrease in coal revenues per ton was primarily the result of lower prices for steam coal sold in Central Appalachia, as well as a larger mix of lower priced tons sold from Pennyrile.

For our Central Appalachia segment, coal revenues decreased by approximately $8.1 million, or 59.4%, to approximately $5.6 million for the three months ended June 30, 2016 from approximately $13.7 million for the three months ended June 30, 2015. This decrease was primarily due to fewer steam coal tons sold and a decrease in the price for steam coal tons sold, which reflects the weak coal market conditions for coal from this region. Coal revenues per ton for our Central Appalachia segment increased by $4.38, or 7.5%, to $63.03 per ton for the three months ended June 30, 2016 as compared to $58.65 for the three months ended June 30, 2015, primarily due to a higher mix of higher priced met coal tons sold as steam coal tons decreased year-to-year due to ongoing weak demand for steam coal from this region.

For our Northern Appalachia segment, coal revenues were approximately $9.2 million for the three months ended June 30, 2016, a decrease of approximately $5.1 million, or 35.7%, from approximately $14.3 million for the three months ended June 30, 2015. This decrease was primarily due to a decrease in tons sold from our Hopedale complex in Northern Appalachia due weak demand for coal from the Northern Appalachia region during the three months ended June 30, 2016. Coal revenues per ton for our Northern Appalachia segment was primarily flat at $57.21 per ton for the three months ended June 30, 2016 as compared to $56.77 per ton for the three months ended June 30, 2015.

For our Rhino Western segment, coal revenues decreased by approximately $1.8 million, or 17.4%, to approximately $8.3 million for the three months ended June 30, 2016 from approximately $10.1 million for the three months ended June 30, 2015, primarily due to a decrease in tons sold due to decreased customer demands at our Castle Valley operation. Coal revenues per ton for our Rhino Western segment were $38.70 for the three months ended June 30, 2016, an increase of $1.11, or 3.0%, from $37.59 for the three months ended June 30, 2015. The increase in coal revenues per ton was due to an increase in the contracted sales prices for steam coal sales from our Castle Valley mine for the three months ended June 30, 2016 compared to the same period in 2015.

For our Illinois Basin segment, coal revenues of approximately $16.0 million for the three months ended June 30, 2016 increased by approximately $5.6 million, or 54.5%, compared to $10.4 million for the three months ended June 30, 2015. The increase was due to increased sales from our Pennyrile mine in western Kentucky to fulfill our customer contracts. Coal revenues per ton for our Illinois Basin segment was $47.98 for the three months ended June 30, 2016, an increase of $1.91, or 4.1%, from $46.07 for the three months ended June 30, 2015. The increase in coal revenues per ton was due to higher contracted prices for tons sold.

Other revenues for our Other category decreased to approximately $0.1 million for the three months ended June 30, 2016 as compared to approximately $0.3 million for the three months ended June 30, 2015. This decrease in revenue was primarily due to the decreased business activity in our ancillary businesses and oil and natural gas investments.

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 met coal and steam coal, is presented below. Note that our Northern Appalachia, Rhino Western and Illinois Basin segments currently produce and sell only steam coal.

(In thousands, except per ton data and %)	Three months ended June 30, 2016		Three months ended June 30, 2015		Increase (Decrease) %*
Met coal tons sold		30.7		48.4		(36.6	)%
Steam coal tons sold		57.5		184.9		(68.9	)%
Total tons sold		88.2		233.3		(62.2	)%

Met coal revenue	$	2,569	$	3,961		(35.1	)%
Steam coal revenue	$	2,990	$	9,718		(69.2	)%
Total coal revenue	$	5,559	$	13,679		(59.4	)%

Met coal revenues per ton	$	83.72	$	81.83		2.3	%
Steam coal revenues per ton	$	51.99	$	52.57		(1.1	)%
Total coal revenues per ton	$	63.03	$	58.65		7.5	%

Met coal tons produced		41.8		77.7		(46.2	)%
Steam coal tons produced		70.2		188.5		(62.8	)%
Total tons produced		112.0		266.2		(57.9	)%

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

Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the three months ended June 30, 2016 and 2015:

	Three months		Three months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2016		June 30, 2015		$			%*
	(in millions, except per ton data and %)
Central Appalachia

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	3.0	$	12.8	$	(9.8	)		(76.6	)%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		1.7		3.4		(1.7	)		(49.7	)%
Selling, general and administrative		3.7		4.7		(1.0	)		(20.7	)%
Cost of operations per ton*	$	33.95	$	54.95	$	(21.00	)		(38.2	)%

Northern Appalachia

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	7.8	$	11.7	$	(3.9	)		(32.9	)%
Freight and handling costs		0.5		0.7		(0.2	)		(23.0	)%
Depreciation, depletion and amortization		0.8		2.0		(1.2	)		(58.6	)%
Selling, general and administrative		-		-		-			n/a
Cost of operations per ton*	$	48.66	$	46.26	$	2.40			5.2	%

Rhino Western

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	6.4	$	9.2	$	(2.8	)		(30.7	)%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		1.4		1.6		(0.2	)		(13.3	)%
Selling, general and administrative		-		-		-			n/a
Cost of operations per ton*	$	29.54	$	34.16	$	(4.62	)		(13.5	)%

Illinois Basin

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	13.8	$	10.9	$	2.9			25.9	%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		1.9		1.4		0.5			30.0	%
Selling, general and administrative		0.1		-		0.1			n/a
Cost of operations per ton*	$	41.38	$	48.74	$	(7.36	)		(15.1	)%

Other

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	2.9	$	2.7	$	0.2			6.7	%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		0.1		0.2		(0.1	)		(25.6	)%
Selling, general and administrative		0.2		0.2		-			14.4	%
Cost of operations per ton**		n/a		n/a		n/a			n/a

Total

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	33.9	$	47.3	$	(13.4	)		(28.4	)%
Freight and handling costs		0.5		0.7		(0.2	)		(23.0	)%
Depreciation, depletion and amortization		5.9		8.6		(2.7	)		(31.0	)%
Selling, general and administrative		4.0		4.9		(0.9	)		(18.9	)%
Cost of operations per ton*	$	42.43	$	48.33	$	(5.90	)		(12.2	)%

* 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 and our oil and natural gas investments. 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 $33.9 million for the three months ended June 30, 2016 as compared to $47.3 million for the three months ended June 30, 2015. Our cost of operations per ton was $42.43 for the three months ended June 30, 2016, a decrease of $5.90, or 12.2%, from the three months ended June 30, 2015. Total cost of operations decreased primarily due to lower costs in Central Appalachia and Northern Appalachia as we reduced production in these regions in response to weak market demand, partially offset by increased costs from higher production at our Pennyrile mine in the Illinois Basin. The decrease in the cost of operations on a per ton basis was primarily due to a decrease from our Central Appalachia segment as we produced coal from lower cost operations during the three months ended June 30, 2016 compared to the same period in 2015.

Our cost of operations for the Central Appalachia segment decreased by $9.8 million, or 76.6%, to $3.0 million for the three months ended June 30, 2016 from $12.8 million for the three months ended June 30, 2015. Total cost of operations decreased year-to-year since we decreased production during the three months ended June 30, 2016 in response to weak market conditions. Our cost of operations per ton of $33.95 for the three months ended June 30, 2016 was a reduction of 38.2% compared to $54.95 per ton for the three months ended June 30, 2015, as we produced coal from lower cost operations during the three months ended June 30, 2016.

In our Northern Appalachia segment, our cost of operations decreased by $3.9 million, or 32.9%, to $7.8 million for the three months ended June 30, 2016 from $11.7 million for the three months ended June 30, 2015. The decrease in cost of operations was due to reduced production in this region in response to weak market demand. Our cost of operations per ton was $48.66 for the three months ended June 30, 2016, an increase of $2.40, or 5.2%, compared to $46.26 for the three months ended June 30, 2015. Cost of operations per ton increased slightly primarily due to fixed operating costs being allocated to lower production and sales tons for the three months ended June 30, 2016 compared to the prior period.

Our cost of operations for the Rhino Western segment decreased by $2.8 million, or 30.7%, to $6.4 million for the three months ended June 30, 2016 from $9.2 million for the three months ended June 30, 2015. Total cost of operations decreased for the three months ended June 30, 2016 compared to the same period in 2015 due to decreased tons produced and sold from our Castle Valley operation due to weak customer demand. Our cost of operations per ton was $29.54 for the three months ended June 30, 2016, a decrease of $4.62, or 13.5%, compared to $34.16 for the three months ended June 30, 2015. Cost of operations per ton decreased for the three months ended June 30, 2016 compared to the same period in 2015 due to lower maintenance and other costs incurred at our Castle Valley operation.

Cost of operations in our Illinois Basin segment was $13.8 million while cost of operations per ton was $41.38 for the three months ended June 30, 2016, both of which related to our Pennyrile mining complex in western Kentucky. For the three months ended June 30, 2015, cost of operations in our Illinois Basin segment was $10.9 million and cost of operations per ton was $48.74. The increase in cost of operations was primarily the result of increased production year-to-year at the Pennyrile complex, while cost of operations per ton decreased as we continued to optimize the cost structure at this mining complex.

Cost of operations in our Other category was relatively flat at $2.9 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015.

Freight and Handling. Total freight and handling cost was relatively flat at $0.5 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015.

Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization (“DD&A”) expense for the three months ended June 30, 2016 was $5.9 million as compared to $8.6 million for the three months ended June 30, 2015.

For the three months ended June 30, 2016, our depreciation cost decreased to $5.0 million compared to $7.4 million for the three months ended June 30, 2015. This decrease primarily resulted from lower depreciation costs in our Central Appalachia segment in the current quarter compared to the prior year as we disposed of excess equipment in this region.

For the three months ended June 30, 2016, our depletion cost decreased to $0.5 million compared to $0.7 million for the three months ended June 30, 2015. This decrease resulted from fewer coal tons produced from our higher depletion rate properties in our Central Appalachia segment in the current quarter compared to the prior year.

For the three months ended June 30, 2016, our amortization cost was relatively flat at $0.4 million compared to $0.5 million for the three months ended June 30, 2015.

Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the three months ended June 30, 2016 decreased to $4.0 million as compared to $4.9 million for the three months ended June 30, 2015. This decrease was primarily attributable to lower corporate overhead expenses for the three months ended June 30, 2016 compared to the prior period.

Interest Expense. Interest expense for the three months ended June 30, 2016 increased to $1.7 million as compared to $1.3 million for the three months ended June 30, 2015. This increase was primarily due to higher interest rates on our senior secured credit facility along with the write-off of approximately $0.1 million of our unamortized debt issuance costs during the three months ended June 30, 2016. This write-off was due to an amendment of our credit facility during the three months ended June 30, 2016 that reduced the borrowing capacity from $80 million to $75 million. See the discussion on our credit agreement in “Liquidity and Capital Resources - Amended and Restated Credit Agreement” section that follows for more information on this amendment.

Net Income (Loss) from Continuing Operations. The following table presents net income (loss) from continuing operations by reportable segment for the three months ended June 30, 2016 and 2015:

	Three months ended			Three months ended			Increase
Segment	June 30, 2016			June 30, 2015			(Decrease)
	(in millions)
Central Appalachia	$	(122.2	)	$	(3.8	)	$	(118.4	)
Northern Appalachia		1.8			1.5			0.3
Rhino Western		-			(1.2	)		1.2
Illinois Basin		(0.7	)		(2.7	)		2.0
Other		(0.8	)		(1.9	)		1.1
Total	$	(121.9	)	$	(8.1	)	$	(113.8	)

For the three months ended June 30, 2016, total net loss from continuing operations was a loss of approximately $121.9 million compared to net loss from continuing operations of approximately $8.1 million for the three months ended June 30, 2015. For the three months ended June 30, 2016, our total net loss from continuing operations was impacted by an asset impairment charge of $118.7 million related to our Elk Horn coal leasing company discussed earlier.

For our Central Appalachia segment, net loss from continuing operations was approximately $122.2 million for the three months ended June 30, 2016, a $118.4 million larger net loss as compared to the three months ended June 30, 2015, which was primarily related to the $118.7 million asset impairment charge for Elk Horn discussed earlier. Net income from continuing operations in our Northern Appalachia segment increased by $0.3 million to $1.8 million for the three months ended June 30, 2016 from $1.5 million for the three months ended June 30, 2015. This increase was primarily due to reducing costs at our Northern Appalachia operations. Net income/loss from continuing operations in our Rhino Western segment was at a break-even level for the three months ended June 30, 2016, compared to a net loss from continuing operations of $1.2 million for the three months ended June 30, 2015. This decrease in net loss was primarily the result of lower costs at our Castle Valley operation during the three months ended June 30, 2016 compared to the prior year. For our Illinois Basin segment, we generated a net loss from continuing operations of $0.7 million for the three months ended June 30, 2016, which was an improvement of $2.0 million compared to the three months ended June 30, 2015. This decrease in net loss was primarily the result of increased coal sales at our Pennyrile mining complex as well as lower costs per ton as we continued to optimize the operations at this mining facility. For the Other category, we had a net loss from continuing operations of $0.8 million for the three months ended June 30, 2016 as compared to net loss from continuing operations of $1.9 million for the three months ended June 30, 2015. This decrease in net loss year to year was primarily due to the $2.2 million asset impairment charges incurred for the three months ended June 30, 2015 related to our Cana Woodford oil and gas properties.

Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the three months ended June 30, 2016 and 2015:

	Three months ended			Three months ended			Increase
Segment	June 30, 2016			June 30, 2015			(Decrease)
	(in millions)
Central Appalachia	$	(1.0	)	$	0.1		$	(1.1	)
Northern Appalachia		2.7			3.6			(0.9	)
Rhino Western		1.5			0.5			1.0
Illinois Basin		1.4			(1.1	)		2.5
Other		(0.1	)		1.0			(1.1	)
Total	$	4.5		$	4.1		$	0.4

Adjusted EBITDA from continuing operations for the three months ended June 30, 2016 was $4.5 million, an increase of $0.4 million from the three months ended June 30, 2015. Adjusted EBITDA from continuing operations increased period to period primarily due to the lower net loss generated year-to-year discussed above, once the impact of the asset impairments discussed above are removed from the net losses generated. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA from continuing operations to net income on a segment basis.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Summary. For the six months ended June 30, 2016, our total revenues decreased to $83.2 million from $112.9 million for the six months ended June 30, 2015, which is a 26.4% decrease. We sold approximately 1.6 million tons of coal for the six months ended June 30, 2016, which is a 14.2% decrease compared to the tons of coal sold for the six months ended June 30, 2015. The decrease in revenue and tons sold was primarily the result of continued weak demand and low prices in the met and steam coal markets, particularly in Central Appalachia, partially offset by increased sales from our Pennyrile operation in the Illinois Basin. We believe the weak demand in the steam and met coal markets for the six months ended June 30, 2016 was due to the same factors discussed earlier.

Net loss from continuing operations increased for the six months ended June 30, 2016 compared to the six months ended June 30, 2015. We generated a net loss from continuing operations of approximately $123.2 million for the six months ended June 30, 2016 compared to a net loss from continuing operations of approximately $12.7 million for the six months ended June 30, 2015. For the six months ended June 30, 2016, our total net loss from continuing operations was impacted by an asset impairment charge of $118.7 million related to our Elk Horn coal leasing company discussed earlier, but was also benefited from a prior service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation. Net loss from continuing operations for the six months ended June 30, 2015 was impacted by the $2.2 million asset impairment charge incurred for our Cana Woodford oil and gas properties discussed above.

Adjusted EBITDA from continuing operations increased to $11.1 million for the six months ended June 30, 2016 from $9.6 million for the six months ended June 30, 2015. Adjusted EBITDA from continuing operations increased period to period primarily due to the $3.9 million prior service cost benefit discussed above.

Including the loss from discontinued operations of approximately $0.7 million, our total net loss and Adjusted EBITDA for the six months ended June 30, 2015 were $12.0 million and $10.3 million, respectively. We did not incur a gain or loss from discontinued operations for the six months ended June 30, 2016.

Tons Sold. The following table presents tons of coal sold by reportable segment for the six months ended June 30, 2016 and 2015:

	Six months		Six months		Increase/
	ended		ended		(Decrease)
Segment	June 30, 2016		June 30, 2015		Tons			% *
	(in thousands, except %)
Central Appalachia		188.3		470.2		(281.9	)		(60.0	)%
Northern Appalachia		283.7		503.7		(220.0	)		(43.7	)%
Rhino Western		467.0		497.4		(30.4	)		(6.1	)%
Illinois Basin		649.2		380.8		268.4			70.5	%
Total *		1,588.2		1,852.1		(263.9	)		(14.2	)%

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

We sold approximately 1.6 million tons of coal for the six months ended June 30, 2016, which was a 14.2% decrease compared to the six months ended June 30, 2015. The decrease in tons sold year-to-year was primarily due to lower sales from our Central Appalachia segment due to weak demand for met and steam coal from this region. Tons of coal sold in our Central Appalachia segment decreased by approximately 60% to approximately 0.2 million tons for the six months ended June 30, 2016 compared to the six months ended June 30, 2015, primarily due to a decrease in steam coal tons sold in the six months ended June 30, 2016 compared to 2015 due to ongoing weak market demand for coal from this region. For our Northern Appalachia segment, tons of coal sold decreased by approximately 43.7% for the six months ended June 30, 2016 compared to the six months ended June 30, 2015 as we experienced a decrease in tons sold from our Hopedale complex due to customers delaying their contracted shipments. Coal sales from our Rhino Western segment decreased by approximately 6.1% for the six months ended June 30, 2016 compared to the same period in 2015 due to decreased customer demand from our Castle Valley operation. For our Illinois Basin segment, tons of coal sold increased by approximately 70.5% for the six months ended June 30, 2016 compared to the six months ended June 30, 2015 as we increased production and sales year-to-year from our Pennyrile mine in western Kentucky to meet our contracted sales commitments.

Revenues. The following table presents revenues and coal revenues per ton by reportable segment for the six months ended June 30, 2016 and 2015:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2016		June 30, 2015		$			%*
	(in millions, except per ton data and %)
Central Appalachia
Coal revenues	$	11.2	$	28.9	$	(17.7	)		(61.4	)%
Freight and handling revenues		-		-		-			n/a
Other revenues		2.3		12.4		(10.1	)		(81.4	)%
Total revenues	$	13.5	$	41.3	$	(27.8	)		(67.4	)%
Coal revenues per ton*	$	59.29	$	61.45	$	(2.16	)		(3.5	)%
Northern Appalachia
Coal revenues	$	15.9	$	29.1	$	(13.2	)		(45.4	)%
Freight and handling revenues		1.2		1.2		-			0.3	%
Other revenues		3.6		3.8		(0.2	)		(35.7	)%
Total revenues	$	20.7	$	34.1	$	(13.4	)		(39.2	)%
Coal revenues per ton*	$	55.95	$	57.68	$	(1.73	)		(3.0	)%
Rhino Western
Coal revenues	$	17.9	$	18.5	$	(0.6	)		(3.3	)%
Freight and handling revenues		-		-		-			n/a
Other revenues		-		-		-			n/a
Total revenues	$	17.9	$	18.5	$	(0.6	)		(3.4	)%
Coal revenues per ton*	$	38.37	$	37.27	$	1.10			2.9	%
Illinois Basin
Coal revenues	$	30.8	$	17.5	$	13.3			75.8	%
Freight and handling revenues		-		-		-			n/a
Other revenues		0.1		0.2		(0.1	)		(78.8	)%
Total revenues	$	30.9	$	17.7	$	13.2			73.9	%
Coal revenues per ton*	$	47.49	$	46.05	$	1.44			3.1	%
Other**
Coal revenues		n/a		n/a		n/a			n/a
Freight and handling revenues		n/a		n/a		n/a			n/a
Other revenues		0.2		1.3		(1.1	)		(86.9	)%
Total revenues	$	0.2	$	1.3	$	(1.1	)		(86.9	)%
Coal revenues per ton*		n/a		n/a		n/a			n/a
Total
Coal revenues	$	75.8	$	94.0	$	(18.2	)		(19.4	)%
Freight and handling revenues		1.2		1.2		-			0.3	%
Other revenues		6.2		17.7		(11.5	)		(65.2	)%
Total revenues	$	83.2	$	112.9	$	(29.7	)		(26.4	)%
Coal revenues per ton*	$	47.72	$	50.77	$	(3.05	)		(6.0	)%

*	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 also do not directly relate to coal production. As a result, coal revenues and coal revenues per ton are not presented for the Other category.

Our coal revenues for the six months ended June 30, 2016 decreased by approximately $18.2 million, or 19.4%, to approximately $75.8 million from approximately $94.0 million for the six months ended June 30, 2015. The decrease in coal revenues was primarily due to fewer steam coal tons sold in Central Appalachia, partially offset by increased sales from our Pennyrile mine in the Illinois Basin. Coal revenues per ton was $47.72 for the six months ended June 30, 2016, a decrease of $3.05, or 6.0%, from $50.77 per ton for the six months ended June 30, 2015. This decrease in coal revenues per ton was primarily the result of lower prices for steam coal sold in Central Appalachia, as well as a larger mix of lower priced tons sold from Pennyrile.

For our Central Appalachia segment, coal revenues decreased by approximately $17.7 million, or 61.4%, to approximately $11.2 million for the six months ended June 30, 2016 from approximately $28.9 million for the six months ended June 30, 2015. This decrease was primarily due to fewer steam coal tons sold and a decrease in the price for steam coal tons sold, which reflects the weak coal market conditions for coal from this region. Coal revenues per ton for our Central Appalachia segment decreased by $2.16, or 3.5%, to $59.29 per ton for the six months ended June 30, 2016 as compared to $61.45 for the six months ended June 30, 2015, primarily due to lower prices from weak demand for steam coal sold.

For our Northern Appalachia segment, coal revenues were approximately $15.9 million for the six months ended June 30, 2016, a decrease of approximately $13.2 million, or 45.4%, from approximately $29.1 million for the six months ended June 30, 2015. This decrease was primarily due to a decrease in tons sold from our Hopedale complex in Northern Appalachia due to customers delaying their contracted shipments during the six months ended June 30, 2016. Coal revenues per ton for our Northern Appalachia segment decreased by $1.73, or 3.0%, to $55.95 per ton for the six months ended June 30, 2016 as compared to $57.68 per ton for the six months ended June 30, 2015. This decrease was primarily due to the larger mix of lower priced tons being sold from our Sands Hill complex compared to higher priced tons sold from our Hopedale complex.

For our Rhino Western segment, coal revenues decreased by approximately $0.6 million, or 3.3%, to approximately $17.9 million for the six months ended June 30, 2016 from approximately $18.5 million for the six months ended June 30, 2015, primarily due to a decrease in tons sold due to decreased customer demands at our Castle Valley operation. Coal revenues per ton for our Rhino Western segment were $38.37 for the six months ended June 30, 2016, an increase of $1.10, or 2.9%, from $37.27 for the six months ended June 30, 2015. The increase in coal revenues per ton was due to an increase in the contracted sales prices for steam coal sales from our Castle Valley mine for the six months ended June 30, 2016 compared to the same period in 2015.

For our Illinois Basin segment, coal revenues of approximately $30.8 million for the six months ended June 30, 2016 increased by approximately $13.3 million, or 75.8%, compared to $17.5 million for the six months ended June 30, 2015. The increase was due to increased sales from our Pennyrile mine in western Kentucky to fulfill our customer contracts. Coal revenues per ton for our Illinois Basin segment were $47.49 for the six months ended June 30, 2016, an increase of $1.44, or 3.1%, from $46.05 for the six months ended June 30, 2015. The increase in coal revenues per ton was due to higher contracted prices for tons sold.

Other revenues for our Other category decreased to approximately $0.2 million for the six months ended June 30, 2016 as compared to approximately $1.3 million for the six months ended June 30, 2015. This decrease in revenue was primarily due to the decreased business activity in our ancillary businesses and oil and natural gas investments.

(In thousands, except per ton data and %)	Six months ended June 30, 2016		Six months ended June 30, 2015		Increase (Decrease) %*
Met coal tons sold		47.0		126.7		(62.9	)%
Steam coal tons sold		141.3		343.5		(58.9	)%
Total tons sold		188.3		470.2		(60.0	)%

Met coal revenue	$	3,899	$	10,019		(61.1	)%
Steam coal revenue	$	7,263	$	18,878		(61.5	)%
Total coal revenue	$	11,162	$	28,897		(61.4	)%

Met coal revenues per ton	$	82.99	$	79.09		4.9	%
Steam coal revenues per ton	$	51.41	$	54.95		(6.4	)%
Total coal revenues per ton	$	59.29	$	61.45		(3.5	)%

Met coal tons produced		57.7		175.2		(67.1	)%
Steam coal tons produced		138.7		356.6		(61.1	)%
Total tons produced		196.4		531.8		(63.1	)%

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

Costs and Expenses. The following table presents costs and expenses (including the cost of purchased coal) and cost of operations per ton by reportable segment for the six months ended June 30, 2016 and 2015:

	Six months		Six months
	ended		ended		Increase/(Decrease)
Segment	June 30, 2016		June 30, 2015		$			%*
	(in millions, except per ton data and %)
Central Appalachia

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	6.0	$	25.7	$	(19.7	)		(76.6	)%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		3.6		7.3		(3.7	)		(50.5	)%
Selling, general and administrative		7.5		8.8		(1.3	)		(14.2	)%
Cost of operations per ton*	$	31.84	$	54.58	$	(22.74	)		(41.7	)%

Northern Appalachia

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	10.7	$	24.7	$	(14.0	)		(56.7	)%
Freight and handling costs		1.1		1.2		(0.1	)		(11.5	)%
Depreciation, depletion and amortization		1.8		3.8		(2.0	)		(53.6	)%
Selling, general and administrative		0.1		0.1		-			(33.2	)%
Cost of operations per ton*	$	37.70	$	49.05	$	(11.35	)		(23.1	)%

Rhino Western

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	14.5	$	16.9	$	(2.4	)		(13.9	)%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		2.8		3.2		(0.4	)		(12.8	)%
Selling, general and administrative		-		-		-			n/a
Cost of operations per ton*	$	31.13	$	33.95	$	(2.82	)		(8.3	)%

Illinois Basin

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	26.5	$	20.8	$	5.7			27.2	%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		3.7		2.7		1.0			38.9	%
Selling, general and administrative		0.1		-		0.1			n/a
Cost of operations per ton*	$	40.79	$	54.65	$	(13.86	)		(25.4	)%

Other

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	5.6	$	5.4	$	0.2			3.8	%
Freight and handling costs		-		-		-			n/a
Depreciation, depletion and amortization		0.3		0.4		(0.1	)		(33.1	)%
Selling, general and administrative		0.3		0.4		(0.1	)		(13.6	)%
Cost of operations per ton**		n/a		n/a		n/a			n/a

Total

Cost of operations (exclusive of depreciation, depletion and amortization shown separately below)	$	63.3	$	93.5	$	(30.2	)		(32.3	)%
Freight and handling costs		1.1		1.2		(0.1	)		(11.5	)%
Depreciation, depletion and amortization		12.2		17.4		(5.2	)		(30.2	)%
Selling, general and administrative		8.0		9.3		(1.3	)		(13.8	)%
Cost of operations per ton*	$	39.86	$	50.47	$	(10.61	)		(21.0	)%

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

Cost of Operations. Total cost of operations was $63.3 million for the six months ended June 30, 2016 as compared to $93.5 million for the six months ended June 30, 2015. Our cost of operations per ton was $39.86 for the six months ended June 30, 2016, a decrease of $10.61, or 21.0%, from the six months ended June 30, 2015. Total cost of operations decreased primarily due to lower costs in Central Appalachia and Northern Appalachia as we reduced production in these regions in response to weak market demand, partially offset by increased costs from higher production at our Pennyrile mine in the Illinois Basin. The decrease in the cost of operations on a per ton basis was primarily due to a decrease from our Pennyrile mine in the Illinois Basin as we increased and optimized production during the six months ended June 30, 2016 compared to the same period in 2015, as well as the $3.9 million benefit in Northern Appalachia during the six months ended June 30, 2016 from the prior service cost benefit resulting from the cancellation of the postretirement benefit plan at our Hopedale operation.

Our cost of operations for the Central Appalachia segment decreased by $19.7 million, or 76.6%, to $6.0 million for the six months ended June 30, 2016 from $25.7 million for the six months ended June 30, 2015. Total cost of operations decreased year-to-year since we decreased production during the six months ended June 30, 2016 in response to weak market conditions. Our cost of operations per ton of $31.84 for the six months ended June 30, 2016 was a reduction of 41.7% compared to $54.58 per ton for the six months ended June 30, 2015, as we produced coal from lower cost operations during the six months ended June 30, 2016.

In our Northern Appalachia segment, our cost of operations decreased by $14.0 million, or 56.7%, to $10.7 million for the six months ended June 30, 2016 from $24.7 million for the six months ended June 30, 2015. Our cost of operations per ton was $37.70 for the six months ended June 30, 2016, a decrease of $11.35, or 23.1%, compared to $49.05 for the six months ended June 30, 2015. The decrease in cost of operations and cost of operations per ton was primarily due to the $3.9 million prior service cost benefit during the six months ended June 30, 2016 resulting from the cancellation of the postretirement benefit plan at our Hopedale operation.

Our cost of operations for the Rhino Western segment decreased by $2.4 million, or 13.9%, to $14.5 million for the six months ended June 30, 2016 from $16.9 million for the six months ended June 30, 2015. Our cost of operations per ton was $31.13 for the six months ended June 30, 2016, a decrease of $2.82, or 8.3%, compared to $33.95 for the six months ended June 30, 2015. Total cost of operations and cost of operations per ton decreased for the six months ended June 30, 2016 compared to the same period in 2015 due to lower maintenance and other costs from our Castle Valley operation.

Cost of operations in our Illinois Basin segment was $26.5 million while cost of operations per ton was $40.79 for the six months ended June 30, 2016, both of which related to our Pennyrile mining complex in western Kentucky. For the six months ended June 30, 2015, cost of operations in our Illinois Basin segment was $20.8 million and cost of operations per ton was $54.65. The increase in cost of operations was primarily the result of increased production year-to-year at the Pennyrile complex, while cost of operations per ton decreased as we continued to optimize the cost structure at this mining complex.

Cost of operations in our Other category was relatively flat at $5.6 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015.

Freight and Handling. Total freight and handling cost was relatively flat at $1.1 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015.

Depreciation, Depletion and Amortization. Total depreciation, depletion and amortization (“DD&A”) expense for the six months ended June 30, 2016 was $12.2 million as compared to $17.4 million for the six months ended June 30, 2015.

For the six months ended June 30, 2016, our depreciation cost decreased to $10.3 million compared to $15.0 million for the six months ended June 30, 2015. This decrease primarily resulted from lower depreciation costs in our Central Appalachia segment in the current quarter compared to the prior year as we disposed of excess equipment in this region.

For the six months ended June 30, 2016, our depletion cost decreased to $1.1 million compared to $1.5 million for the six months ended June 30, 2015. This decrease resulted from fewer coal tons produced from our higher depletion rate properties in our Central Appalachia segment in the current quarter compared to the prior year.

For the six months ended June 30, 2016, our amortization cost was relatively flat at $0.8 million compared to $0.9 million for the six months ended June 30, 2015.

Selling, General and Administrative. Selling, general and administrative (“SG&A”) expense for the six months ended June 30, 2016 decreased to $8.0 million as compared to $9.3 million for the six months ended June 30, 2015. This decrease was primarily attributable to lower corporate overhead expenses for the six months ended June 30, 2016 compared to the prior period.

Interest Expense. Interest expense for the six months ended June 30, 2016 increased to $3.3 million as compared to $2.3 million for the six months ended June 30, 2015. This increase was primarily due to higher interest rates on our senior secured credit facility along with the write-off of approximately $0.3 million of our unamortized debt issuance costs during the six months ended June 30, 2016. This write-off was due to the fourth and fifth amendments of our credit facility during the six months ended June 30, 2016 that reduced the borrowing capacity from $100 million to $75 million. See the discussion on our credit agreement in “Liquidity and Capital Resources - Amended and Restated Credit Agreement” section that follows for more information on these amendments.

Net Income (Loss) from Continuing Operations. The following table presents net income (loss) from continuing operations by reportable segment for the six months ended June 30, 2016 and 2015:

	Six months Ended			Six months Ended			Increase
Segment	June 30, 2016			June 30, 2015			(Decrease)
	(in millions)
Central Appalachia	$	(125.9	)	$	(4.1	)	$	(121.8	)
Northern Appalachia		5.8			2.7			3.1
Rhino Western		(0.6	)		(2.5	)		1.9
Illinois Basin		(1.5	)		(7.2	)		5.7
Other		(1.0	)		(1.6	)		0.6
Total	$	(123.2	)	$	(12.7	)	$	(110.5	)

For the six months ended June 30, 2016, total net loss from continuing operations was a loss of approximately $123.2 million compared to net loss from continuing operations of approximately $12.7 million for the six months ended June 30, 2015. For the six months ended June 30, 2016, our total net loss from continuing operations was impacted by an asset impairment charge of $118.7 million related to our Elk Horn coal leasing company discussed earlier, but was also benefited from a prior service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation. Including our income from discontinued operations of approximately $0.7 million, our total net loss for the six months ended June 30, 2015 was approximately $12.0 million.

For our Central Appalachia segment, net loss from continuing operations was approximately $125.9 million for the six months ended June 30, 2016, a $121.8 million larger net loss as compared to the six months ended June 30, 2015, which was primarily related to the $118.7 million asset impairment charge for Elk Horn discussed earlier. Net income from continuing operations in our Northern Appalachia segment increased by $3.1 million to $5.8 million for the six months ended June 30, 2016 from $2.7 million for the six months ended June 30, 2015. This increase was primarily due the prior service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation. Net loss from continuing operations in our Rhino Western segment was a loss of $0.6 million for the six months ended June 30, 2016, compared to a net loss from continuing operations of $2.5 million for the six months ended June 30, 2015. This decrease in net loss was primarily the result of lower costs at our Castle Valley operation during the six months ended June 30, 2016 compared to the prior year. For our Illinois Basin segment, we generated a net loss from continuing operations of $1.5 million for the six months ended June 30, 2016, which was an improvement of $5.7 million compared to the six months ended June 30, 2015. This decrease in net loss was primarily the result of increased coal sales at our Pennyrile mining complex as well as lower costs per ton as we continued to optimize the operations at this mining facility. For the Other category, we had a net loss from continuing operations of $1.0 million for the six months ended June 30, 2016 as compared to a net loss from continuing operations of $1.6 million for the six months ended June 30, 2015. This decrease in results year to year was primarily due to the $2.2 million asset impairment charge incurred during the six months ended June 30, 2015 for our Cana Woodford oil and gas properties discussed earlier.

Adjusted EBITDA from Continuing Operations. The following table presents Adjusted EBITDA from continuing operations by reportable segment for the six months ended June 30, 2016 and 2015:

	Six months Ended			Six months Ended			Increase
Segment	June 30, 2016			June 30, 2015			(Decrease)
	(in millions)
Central Appalachia	$	(2.2	)	$	4.4		$	(6.6	)
Northern Appalachia		7.8			6.7			1.1
Rhino Western		2.4			0.9			1.5
Illinois Basin		2.7			(4.3	)		7.0
Other		0.4			1.9			(1.5	)
Total	$	11.1		$	9.6		$	1.5

Adjusted EBITDA from continuing operations for the six months ended June 30, 2016 was $11.1 million, an increase of $1.5 million from the six months ended June 30, 2015. Adjusted EBITDA from continuing operations increased period to period due to the prior service cost benefit of approximately $3.9 million resulting from the cancellation of the postretirement benefit plan at our Hopedale operation. Adjusted EBITDA for the six months ended June 30, 2015 was $10.3 million once the results from discontinued operations were included. Please read “—Reconciliations of Adjusted EBITDA” for reconciliations of Adjusted EBITDA from continuing operations 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		Illinois
Three months ended June 30, 2016	Appalachia			Appalachia		Western		Basin			Other			Total**
	(in millions)
Net income/(loss) from continuing operations	$	(122.2	)	$	1.8	$	-	$	(0.7	)	$	(0.8	)	$	(121.9	)
Plus:
DD&A		1.7			0.8		1.4		1.9			0.1			5.9
Interest expense		0.7			0.1		0.1		0.2			0.6			1.7
EBITDA from continuing operations†	$	(119.8	)	$	2.7	$	1.5	$	1.4		$	(0.1	)	$	(114.3	)
Plus: Provision for doubtful accounts (1)		0.1			-		-		-			-			0.1
Plus: Non-cash asset impairment (2)		118.7			-		-		-			-			118.7
Adjusted EBITDA from continuing operations†		(1.0	)		2.7		1.5		1.4			(0.1	)		4.5
Net income from discontinued operations		-			-		-		-			-			-
Adjusted EBITDA †	$	(1.0	)	$	2.7	$	1.5	$	1.4		$	(0.1	)	$	4.5

	Central			Northern		Rhino			Illinois
Six months ended June 30, 2016	Appalachia			Appalachia		Western			Basin			Other			Total**
	(in millions)
Net income/(loss) from continuing operations	$	(125.9	)	$	5.8	$	(0.6	)	$	(1.5	)	$	(1.0	)	$	(123.2	)
Plus:
DD&A		3.6			1.8		2.8			3.7			0.3			12.2
Interest expense		1.3			0.2		0.2			0.5			1.1			3.3
EBITDA from continuing operations† **	$	(121.0	)	$	7.8	$	2.4		$	2.7		$	0.4		$	(107.7	)
Plus: Provision for doubtful accounts (1)		0.1			-		-			-			-			0.1
Plus: Non-cash asset impairment (2)		118.7			-		-			-			-			118.7
Adjusted EBITDA from continuing operations†		(2.2	)		7.8		2.4			2.7			0.4			11.1
Net income from discontinued operations		-			-		-			-			-			-
Adjusted EBITDA †	$	(2.2	)	$	7.8	$	2.4		$	2.7		$	0.4		$	11.1

	Central			Northern		Rhino			Illinois
Three months ended June 30, 2015	Appalachia			Appalachia		Western			Basin			Other			Total**
	(in millions)
Net income/(loss) from continuing operations	$	(3.8	)	$	1.5	$	(1.2	)	$	(2.7	)	$	(1.9	)	$	(8.1	)
Plus:
DD&A		3.4			2.0		1.6			1.4			0.2			8.6
Interest expense		0.4			0.1		0.1			0.2			0.5			1.3
EBITDA from continuing operations†	$	-		$	3.6	$	0.5		$	(1.1	)	$	(1.2	)	$	1.8
Plus: Provision for doubtful accounts (1)		0.1			-		-			-			-			0.1
Plus: Non-cash asset impairment (2)		-			-		-			-			2.2			2.2
Adjusted EBITDA from continuing operations†		0.1			3.6		0.5			(1.1	)		1.0			4.1
Net income from discontinued operations		-			-		-			-			-			-
Adjusted EBITDA †	$	0.1		$	3.6	$	0.5		$	(1.1	)	$	1.0		$	4.1

	Central			Northern		Rhino			Illinois
Six months ended June 30, 2015	Appalachia			Appalachia		Western			Basin			Other			Total**
	(in millions)
Net income/(loss) from continuing operations	$	(4.1	)	$	2.7	$	(2.5	)	$	(7.2	)	$	(1.6	)	$	(12.7	)
Plus:
DD&A		7.3			3.8		3.2			2.7			0.4			17.4
Interest expense		0.9			0.2		0.2			0.2			0.8			2.3
EBITDA from continuing operations† **	$	4.1		$	6.7	$	0.9		$	(4.3	)	$	(0.3	)	$	7.1
Plus: Provision for doubtful accounts (1)		0.3			-		-			-			-			0.3
Plus: Non-cash asset impairment (2)		-			-		-			-			2.2			2.2
Adjusted EBITDA from continuing operations†		4.4			6.7		0.9			(4.3	)		1.9			9.6
Net income from discontinued operations		-			-		-			-			-			0.7
Adjusted EBITDA †	$	4.4		$	6.7	$	0.9		$	(4.3	)	$	1.9		$	10.3

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

**	Totals may not foot due to rounding.

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

(1)	During the three and six months ended June 30, 2016, we recorded a provision for doubtful accounts of approximately $0.1 million related to Elk Horn lessee customers in Central Appalachia. During the three and six months ended June 30, 2015, we recorded provisions for doubtful accounts of approximately $0.1 million and $0.3 million, respectively, related to Elk Horn lessee customers in Central Appalachia. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.

(2)	For the three and six months ended June 30, 2016, we recorded an asset impairment loss of approximately $118.7 million for our Elk Horn coal leasing company that was discussed earlier. For the three and six months ended June 30, 2015, we recorded an asset impairment loss of approximately $2.2 million for our Cana Woodford mineral rights since we classified this asset as held for sale as of June 30, 2015. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.

	Three months ended June 30,					Six months ended June 30,
	2016			2015		2016			2015
	(in millions)
Net cash provided by operating activities	$	5.3		$	9.4	$	4.1		$	11.4
Plus:
Increase in net operating assets		-			-		1.0			-
Gain on sale of assets		0.1			-		0.3			0.7
Amortization of deferred revenue		0.6			1.1		0.7			1.7
Amortization of actuarial gain		-			-		4.8			0.1
Interest expense		1.7			1.3		3.3			2.3
Equity in net income of unconsolidated affiliate		-			0.1		-			0.3
Less:
Decrease in net operating assets		1.4			6.4		-			3.4
Accretion on interest-free debt		-			-		-			0.1
Amortization of advance royalties		0.3			0.2		0.6			0.4
Amortization of debt issuance costs		0.4			0.5		1.0			0.7
Loss on retirement of advanced royalties		-			-		0.1			-
Loss on asset impairments		118.7			2.2		118.7			2.2
Provision for doubtful accounts		0.1			0.1		0.1			0.3
Equity-based compensation		0.5			-		0.5			-
Accretion on asset retirement obligations		0.4			0.6		0.7			1.1
Distribution from unconsolidated affiliates		-			-		-			0.2
Equity in net loss of unconsolidated affiliates		0.1			-		0.1			-
EBITDA†	$	(114.2	)	$	1.9	$	(107.6	)	$	8.1
Plus: Loss on asset impairments (1)		118.7			2.2		118.7			2.2
Adjusted EBITDA† **		4.5			4.1		11.1			10.3
Less: Net income from discontinued operations		-			-		-			0.7
Adjusted EBITDA from continuing operations †	$	4.5		$	4.1	$	11.1		$	9.6

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

**	Totals may not foot due to rounding.

(1)	For the three and six months ended June 30, 2016, we recorded an asset impairment loss of approximately $118.7 million for our Elk Horn coal leasing company that was discussed earlier. For the three and six months ended June 30, 2015, we recorded an asset impairment loss of approximately $2.2 million for our Cana Woodford mineral rights since we classified this asset as held for sale as of June 30, 2015. We believe that the isolation and presentation of this specific item to arrive at Adjusted EBITDA is useful because it enhances investors’ understanding of how we assess the performance of our business. We believe the adjustment of this item provides investors with additional information that they can utilize in evaluating our performance. Additionally, we believe the isolation of this item provides investors with enhanced comparability to prior and future periods of our operating results.

Liquidity and Capital Resources

Liquidity

The principal indicators of our liquidity are our cash on hand and availability under our Amended and Restated Credit Agreement. As of June 30, 2016, our available liquidity was $6.7 million, which was comprised of our availability under our credit agreement.

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. Historically, our sources of liquidity included cash generated by our operations, borrowings under our credit agreement and issuances of equity securities. Our ability to access the capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our equity securities, prevailing commodity prices and other macroeconomic factors outside of our control. Failure to obtain financing or to generate sufficient cash flow from operations could cause us to significantly reduce our spending and to alter our short- or long-term business plan. We may also be required to consider other options, such as selling assets or merger opportunities, and depending on the urgency of our liquidity constraints, we may be required to pursue such an option at an inopportune time.

On March 17, 2016, our Operating Company, as borrower, and we and certain of our subsidiaries, as guarantors, entered into a fourth amendment (the “Fourth Amendment”) of our Amended and Restated Credit Agreement. The Fourth Amendment amended the definition of change of control in the Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of the General.

In order to borrow under our senior secured credit facility, we must make certain representations and warranties to our lenders at the time of each borrowing. If we are unable to make these representations and warranties, we would be unable to borrow under our senior secured credit facility, absent a waiver. Furthermore, if we violate any of the covenants or restrictions in our Amended and Restated Credit Agreement, including the maximum leverage ratio and minimum EBITDA requirement, some or all of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. Given the continued weak demand and low prices for met and steam coal, we may not be able to continue to give the required representations or meet all of the covenants and restrictions included in our senior secured credit facility. If we are unable to give a required representation or we violate a covenant or restriction, then we will need a waiver from our lenders in order to continue to borrow under our Amended and Restated Credit Agreement. Although we believe our lenders loans are well secured under the terms of our Amended and Restated Credit Agreement, there is no assurance that the lenders would agree to any such waiver.

We continue to take measures, including the suspension of cash distributions on our common and subordinated units and cost and productivity improvements, to enhance and preserve our liquidity so that we can fund our ongoing operations and necessary capital expenditures and meet our financial commitments and debt service obligations. For the quarter ended June 30, 2016, we continued the suspension of the cash distribution for our common units, which was initially suspended beginning with the quarter ended June 30, 2015. For the quarters ended September 30, 2014 and December 31, 2014, we announced cash distributions of $0.05 per common unit, or $0.20 per unit on an annualized basis, and for the quarter ended March 31, 2015, we announced cash distributions of $0.02 per common unit, or $0.08 per unit on an annualized basis. Each of these quarters’ distribution levels were lower than the previous quarters’ distribution amounts of $0.445 per common unit, or $1.78 per unit on an annualized basis. We have not paid any distribution on our subordinated units for any quarter after the quarter ended March 31, 2012. The distribution suspension and prior reductions were the result of prolonged weakness in the coal markets, which has continued to adversely affect our cash flow.

Cash Flows

Net cash provided by operating activities was $4.1 million for the six months ended June 30, 2016 as compared to cash provided by operating activities of $11.4 million for the six months ended June 30, 2015. This decrease in cash provided by operating activities was primarily the result of ongoing weak coal market conditions discussed above for the six months ended June 30, 2016 as compared to 2015.

Net cash used for investing activities was $4.0 million for the six months ended June 30, 2016 as compared to cash used for investing activities of $6.7 million for the six months ended June 30, 2015. Net cash used for investing activities is primarily related to our capital expenditures necessary for maintaining our mining operations.

Net cash used in financing activities for the six months ended June 30, 2016 was $0.1 million, which was primarily attributable to net repayments on our revolving credit facility this period with the proceeds from limited partner contributions. Net cash used in financing activities for the six months ended June 30, 2015 was $5.2 million, which was primarily attributable to fees paid for the third amendment of our credit facility, as well as distributions paid to unitholders.

Capital Expenditures

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

Actual maintenance capital expenditures for the six months ended June 30, 2016 were approximately $0.6 million. These amounts were primarily used to rebuild, repair or replace older mining equipment. Expansion capital expenditures for the six months ended June 30, 2016 were approximately $3.8 million, which were primarily related to the payments for the final development of our new Riveredge mine on our Pennyrile property in western Kentucky.

Amended and Restated Credit Agreement

On July 29, 2011, we executed the Amended and Restated Credit Agreement. The maximum availability under the amended and restated credit facility was $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 was available for letters of credit. In April 2015, the Amended and Restated Credit Agreement was amended and the borrowing commitment under the facility was reduced to $100.0 million and the amount available for letters of credit was reduced to $50.0 million. As described below, in March 2016 and May 2016, the borrowing commitment under the facility was further reduced to $80.0 million and $75.0 million, respectively, and the amount available for letters of credit was reduced to $30.0 million.

Loans under the senior secured credit facility currently bear interest at a base rate equaling the prime rate plus an applicable margin of 3.50%. The Amended and Restated Credit Agreement also contains letter of credit fees equal to an applicable margin of 5.00% 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 senior secured credit facility at a rate of 1.00% per annum. Borrowings on the line of credit are collateralized by all of our unsecured assets.

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

On March 17, 2016, we entered into the Fourth Amendment of our Amended and Restated Credit Agreement. The Fourth Amendment amended the definition of change of control in the Amended and Restated Credit Agreement to permit Royal to purchase the membership interests of our general partner. The Fourth Amendment reduced the borrowing capacity under the credit facility to a maximum of $80 million and reduced the amount available for letters of credit to $30 million. The Fourth Amendment eliminated the option to borrow funds utilizing the LIBOR rate plus an applicable margin and established the borrowing rate for all borrowings under the facility to be based upon the current PRIME rate plus an applicable margin of 3.50%. The Fourth Amendment eliminated the capability to make Swing Loans under the facility and eliminated our ability to pay distributions to our common or subordinated unitholders. The Fourth Amendment altered the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve-month basis, to 6.75 to 1.00. The leverage ratio shall be reduced by 0.50 to 1.00 for every $10 million of net cash proceeds, in the aggregate, received by us after the date of the Fourth Amendment from a liquidity event; provided, however, that in no event shall the maximum permitted leverage ratio be reduced below 3.00 to 1.00. A liquidity event is defined in the Fourth Amendment as the issuance of any equity by us on or after the Fourth Amendment effective date (other than the Royal equity contribution discussed above), or the disposition of any assets by us. The Fourth Amendment required us to maintain minimum liquidity of $5 million and minimum EBITDA (as defined in the credit agreement), calculated as of the end of the most recent month, on a trailing twelve month basis, of $8 million. The Fourth Amendment limited the amount of our capital expenditures to $15 million, calculated as of end of the most recent month, on a trailing twelve-month basis. The Fourth Amendment required us to provide monthly financial statements and a weekly rolling thirteen-week cash flow forecast to the Administrative Agent.

On May 13, 2016, we entered into the Fifth Amendment of our Amended and Restated Credit Agreement that extended the term to July 31, 2017. Per the Fifth Amendment, the credit facility will be automatically extended to December 31, 2017 if revolving credit commitments are reduced to $55 million or less on or before July 31, 2017. The Fifth Amendment immediately reduced the revolving credit commitments under the credit facility to a maximum of $75 million and maintained the amount available for letters of credit at $30 million. The Fifth Amendment further reduced the revolving credit commitments over time on a dollar-for-dollar basis in amounts equal to each of the following: (i) the face amount of any letter of credit that expires or whose face amount is reduced by any such dollar amount, (ii) the net proceeds received from any asset sales, (iii) the Royal scheduled capital contributions (as outline below), (iv) the net proceeds from the issuance of any equity by us up to $20.0 million (other than equity issued in exchange for any Royal contribution as outlined in the Securities Purchase Agreement or the Royal scheduled capital contributions to us as outlined below), and (v) the proceeds from the incurrence of any subordinated debt. The first $11 million of proceeds received from any equity issued by us described in clause (iv) above shall also satisfy the Royal scheduled capital contributions as outlined below. The Fifth Amendment requires Royal to contribute $2 million each quarter beginning September 30, 2016 through September 30, 2017 and $1 million on December 1, 2017, for a total of $11 million. The Fifth Amendment further reduces the revolving credit commitments as follows:

Date of Reduction		Reduction Amount

September 30, 2016		The lesser of (i) $2 million or (ii) the positive difference (if any) of $2 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)

December 31, 2016		The lesser of (i) $2 million or (ii) the positive difference (if any) of $4 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)

March 31, 2017		The lesser of (i) $2 million or (ii) the positive difference (if any) of $6 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)

June 30, 2017		The lesser of (i) $2 million or (ii) the positive difference (if any) of $8 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)

September 30, 2017		The lesser of (i) $2 million or (ii) the positive difference (if any) of $10 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)

December 1, 2017		The lesser of (i) $1 million or (ii) the positive difference (if any) of $11 million minus the proceeds from the issuance of any of our equity (excluding any Royal equity contributions)

The Fifth Amendment requires that on or before March 31, 2017, we shall have solicited bids for the potential sale of certain non-core assets, satisfactory to the administrative agent, and provided the administrative agent, and any other lender upon its request, with a description of the solicitation process, interested parties and any potential bids. The Fifth Amendment limits any payments by us to our general partner to: (i) the usual and customary payroll and benefits of the our management team so long as our management team remains employees of our general partner, (2) the usual and customary board fees of our general partner, and (3) the usual and customary general and administrative costs and expenses of our general partner incurred in connection with the operation of its business in an amount not to exceed $0.3 million per fiscal year. The Fifth Amendment limits asset sales to a maximum of $5 million unless we receive consent from the lenders. The Fifth Amendment alters the maximum leverage ratio, calculated as of the end of the most recent month, on a trailing twelve-month basis, as follows:

Period		Ratio

For the month ending April 30, 2016, through the month ending May 31, 2016		7.50 to 1.00

For the month ending June 30, 2016, through the month ending August 31, 2016		7.25 to 1.00

For the month ending September 30, 2016, through the month ending November 30, 2016		7.00 to 1.00

For the month ending December 31, 2016, through the month ending March 31, 2017		6.75 to 1.00

For the month ending April 30, 2017, through the month ending June 30, 2017		6.25 to 1.00

For the month ending July 31, 2017, through the month ending November 30, 2017		6.0 to 1.00

For the month ending December 31, 2017		5.50 to 1.00

The leverage ratios above shall be reduced by 0.50 to 1.00 for every $10 million of aggregate proceeds received by us from: (i) the issuance of our equity (excluding any Royal capital contributions) and/or (ii) the proceeds received from the sale of assets, provided that the leverage ratio shall not be reduced below 3.50 to 1.00. The Fifth Amendment removes the $5.0 million minimum liquidity requirement and requires us to have any deposit, securities or investment accounts with a member of the lending group.

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 amended and restated credit agreement. We then use bank letters of credit to secure our surety bonding obligations as a lower cost alternative than securing those bonds with a committed bonding facility pursuant to which we are required to provide bank letters of credit in an amount of up to 25% of the aggregate bond liability. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

As of June 30, 2016, we had $27.8 million in letters of credit outstanding, of which $22.4 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, 2015. There have been no significant changes in these policies and estimates as of June 30, 2016.

Recent Accounting Pronouncements

Refer to Part-I— Item 1. Note 2 of the notes to the unaudited condensed consolidated financial statements for a discussion of recent accounting pronouncements, which is incorporated herein by reference. There are no known future impacts or material changes or trends of new accounting guidance beyond the disclosures provided in Note 2.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2016 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended June 30, 2016, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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, 2015, 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, 2015. 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.

None.

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosure

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K for the three months ended June 30, 2016 is included in Exhibit 95.1 to this report.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number		Description

2.1		Membership Transfer Agreement between Rhino Eastern JV Holding Company LLC, Rhino Energy WV LLC, and Rhino Eastern LLC dated December 31, 2014, incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-34892) filed on January 7, 2015

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		Third Amended and Restated Agreement of Limited Partnership of Rhino Resource Partners LP, dated as of December 30, 2015, incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-34892) filed on December 30, 2015

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

4.2		Registration Rights Agreement, dated as of March 21, 2016, by and between Rhino Resource Partners LP and Royal Energy Resources, Inc., incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-34892) filed on March 23, 2016

10.1		Fifth Amendment to Amended and Restated Credit Agreement, dated May 13, 2016 by and among Rhino Energy LLC, PNC Bank, National Association, as Administrative Agent, and the guarantors and lenders party thereto, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File No. 001-34892), filed on May 16, 2016

31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

32.1*		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

32.2*		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

95.1*		Mine Health and Safety Disclosure pursuant to §1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act for the three months ended June 30, 2016

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		XBRL Taxonomy Definition Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

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

SIGNATURES

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

	RHINO RESOURCE PARTNERS LP

	By:	Rhino GP LLC, its General Partner

Date: August 11, 2016	By:	/s/ Joseph E. Funk
		Joseph E. Funk
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: August 11, 2016	By:	/s/ Richard A. Boone
		Richard A. Boone
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

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