Magnum Hunter Resources 10-Q 2012 Q2 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

For the quarterly period ended June 30, 2012

-OR-

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

For the transition period from                to

Commission file number 001-32997

MAGNUM HUNTER RESOURCES CORPORATION

(Name of registrant as specified in its charter)

Delaware	86-0879278
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

777 Post Oak Boulevard, Suite 650, Houston, Texas 77056

(Address of principal executive offices)

(832) 369-6986

(Issuer’s telephone number)

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

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).  Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):

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

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

As of August 8, 2012, there were 168,277,258 shares of the registrant’s common stock ($0.01 par value) outstanding.

MAGNUM HUNTER RESOURCES CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED JUNE 30, 2012

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited):	1
Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	1
Condensed Consolidated Statements of Operations for the Six Months Ended June 30, 2012 and 2011	2
Consolidated Statement of Other Comprehensive Income (Loss)	3
Condensed Consolidated Statements of Shareholders’ Equity for the Six Months Ended June 30, 2012	4
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Part II. OTHER INFORMATION	47
Item 1. Legal Proceedings	47
Item 1A. Risk Factors	47
Item 6. Exhibits	48
SIGNATURES	52

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except shares and per-share data)

	June 30,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	24,762		$	14,851
Accounts receivable	51,315			48,083
Derivative assets	10,971			5,732
Inventory	11,630			—
Prepaids and other current assets	2,447			6,254
Assets held for sale — current	—			2,749
Total current assets	101,125			77,669
PROPERTY AND EQUIPMENT (Net of Accumulated Depletion and Depreciation):
Oil and natural gas properties, successful efforts accounting	1,484,918			962,965
Gas gathering and other equipment	148,637			112,169
Total property and equipment, net	1,633,555			1,075,134
OTHER ASSETS:
Deferred financing costs, net of amortization of $6,468 and $958, respectively	18,758			10,642
Derivatives and other long term assets	11,495			1,913
Intangible assets, net	10,001			—
Goodwill	30,602			—
Assets held for sale — long term	—			3,402
Total assets	$	1,805,536		$	1,168,760
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of notes payable	$	3,430		4,565
Accounts payable	135,453			136,698
Accrued liabilities	11,476			5,635
Revenue payable	14,150			10,781
Derivatives and other current liabilities	5,632			7,149
Liabilities associated with assets held for sale — current	—			2,847
Total current liabilities	170,141			167,675
OTHER LIABILITIES:
Senior notes payable	443,971			—
Notes payable, less current portion	162,351			285,824
Asset retirement obligation	22,336			20,089
Deferred tax liability	91,448			95,299
Derivatives and other long term liabilities	6,469			8,954
Liabilities associated with assets held for sale — long term	—			267
Total liabilities	896,716			578,108
COMMITMENTS AND CONTINGENCIES (Note 13)
REDEEMABLE PREFERRED STOCK:
Series C Cumulative Perpetual Preferred Stock, cumulative dividend rate 10.25% per annum, 4,000,000 authorized, 4,000,000 issued & outstanding as of June 30, 2012 and December 31, 2011, respectively, with liquidation preference of $25.00 per share	100,000			100,000
Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, cumulative distribution rate of 8.0% per annum, 7,163,043 and none issued & outstanding as of June 30, 2012 and December 31, 2011, respectively, with liquidation preference of $131,800	127,393			—
SHAREHOLDERS’ EQUITY:
Preferred Stock, 10,000,000 shares authorized	—			—
Series D Cumulative Perpetual Preferred Stock, cumulative dividend rate 8.0% per annum, 5,750,000 authorized, 2,546,307 and 1,437,558 issued & outstanding as of June 30, 2012 and December 31, 2011, respectively, with liquidation preference of $50.00 per share	127,315			71,878
Common stock, $0.01 par value; 250,000,000 shares authorized, 167,813,192 and 130,270,295 shares issued and 167,813,192 and 129,803,374 outstanding as of June 30, 2012 and December 31, 2011, respectively	1,677			1,298
Exchangeable common stock, par value $0.01 per share, 2,016,122 and 3,693,871 issued and outstanding as of June 30, 2012 and December 31, 2011, respectively	20			37
Additional paid in capital	725,238			569,690
Accumulated deficit	(171,737		)	(140,070		)
Accumulated other comprehensive loss	(13,346		)	(12,463		)
Treasury stock at cost, 761,652 shares	(1,310		)	(1,310		)
Unearned common stock in KSOP at cost, 153,300 shares	(604		)	(604		)
Total Magnum Hunter Resources Corporation shareholders’ equity	667,253			488,456
Non-controlling interest	14,174			2,196
Total shareholders’ equity	681,427			490,652
Total liabilities and shareholders’ equity	$	1,805,536		$	1,168,760

The accompanying notes are an integral part of these unaudited consolidated financial statements

1

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except shares and per-share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
REVENUE:
Oil and gas sales	$	53,682		$	26,046		$	104,854		$	40,007
Field operations and other	6,618			3,486			12,642			4,062
Total revenue	60,300			29,532			117,496			44,069
EXPENSES:
Lease operating expenses	11,985			6,562			23,226			9,559
Severance taxes and marketing	3,812			1,801			7,535			2,796
Exploration	385			358			730			673
Field operations	4,178			1,645			7,016			2,419
Impairment of unproved oil and gas properties	9,023			—			17,694			—
Depreciation, depletion and accretion	29,991			10,734			56,719			16,202
General and administrative	12,592			23,640			27,791			30,423
Total expenses	71,966			44,740			140,711			62,072
OPERATING LOSS	(11,666		)	(15,208		)	(23,215		)	(18,003		)
OTHER INCOME AND (EXPENSE):
Interest income	60			1			67			4
Interest expense	(19,932		)	(3,922		)	(25,316		)	(4,705		)
Gain (loss) on derivative contracts	21,867			2,668			20,452			(674		)
Other income and (expense)	(739		)	88			(371		)	88
Total other income and (expense)	1,256			(1,165		)	(5,168		)	(5,287		)
Loss from continuing operations before income taxes and non-controlling interest	(10,410		)	(16,373		)	(28,383		)	(23,290		)
Income tax benefit	3,001			197			3,811			197
Net (income) attributable to non-controlling interest	(48		)	(84		)	(22		)	(117		)
Net loss attributable to Magnum Hunter Resources Corporation from continuing operations	(7,457		)	(16,260		)	(24,594		)	(23,210		)
Income from discontinued operations	—			1,220			354			1,480
Gain on sale of discontinued operations	—			—			4,325			—
Net loss	(7,457		)	(15,040		)	(19,915		)	(21,730		)
Dividend on Preferred Stock	(7,158		)	(3,457		)	(11,752		)	(6,065		)
Net loss attributable to common shareholders	$	(14,615	)	$	(18,497	)	$	(31,667	)	$	(27,795	)
Weighted average number of common shares outstanding Basic and diluted	151,464,372			112,619,793			142,293,282			94,233,091
Loss from continuing operations	$	(0.10	)	$	(0.17	)	$	(0.25	)	$	(0.31	)
Income from discontinued operations	$	—		$	0.01		$	0.03		$	0.02
Loss per common share	$	(0.10	)	$	(0.16	)	$	(0.22	)	$	(0.29	)

The accompanying notes are an integral part of these unaudited consolidated financial statements

2

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)

(In thousands, except shares and per-share data)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Net loss	$	(7,457	)	$	(15,040	)	$	(19,915	)	$	(21,730	)
Foreign currency translation	(4,119		)	(3,222		)	(617		)	(3,222		)
Unrealized gain (loss) on available for sale investments	(189		)	8			(265		)	8
Total comprehensive loss	$	(11,765	)	$	(18,254	)	$	(20,797	)	$	(24,944	)

The accompanying notes are an integral part of these unaudited consolidated financial statements

3

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(In thousands)

	Number	Number of Shares		Number of								Additional						Accumulated Other						Unearned						Total
	of Shares	of Exchangeable		Shares of Series D	Common		Exchangeable			Series D		Paid in			Accumulated			Comprehensive			Treasury			Common shares			Noncontrolling			Shareholders’
	of Common	Common Stock		Preferred Stock	Stock		Common Stock			Preferred Stock		Capital			Deficit			Income			Stock			in KSOP			Interest			Equity
BALANCE, January 1, 2012	129,803	3,694		1,438	$	1,298	$	37		$	71,878	$	569,690		$	(140,070	)	$	(12,463	)	$	(1,310	)	$	(604	)	$	2,196		$	490,652
Restricted stock issued to employees and directors	63	—		—	1		—			—		118			—			—			—			—			—			119
Share based compensation	—	—		—	—		—			—		8,572			—			—			—			—			—			8,572
Issued shares of Series D Preferred Stock for cash	—	—		1,108	—		—			55,437		(4,554		)	—			—			—			—			—			50,883
Issued shares of Cmmon Stock for cash	35,000	—		—	350		—			—		148,325			—			—			—			—			—			148,675
Issued shares of Common Stock upon warrant exercise	9	—		—	—		—			—		22			—			—			—			—			—			22
Issued shares of common stock upon stock option exercise	841	—		—	8		—			—		1,166			—			—			—			—			—			1,174
Dividends Preferred Stock	—	—		—	—		—			—		—			(11,752		)	—			—			—			—			(11,752		)
Issued shares of common stock for acquisition of assets	297	—		—	3		—			—		1,899			—			—			—			—			—			1,902
Issued shared of common stock upon exchange of MHR
Exchangeco Corporation’s exchangeable shares	1,678	(1,678	)	—	17		(17		)	—		—			—			—			—			—			—			—
Purchase of outstanding noncontrolling interest in a subsidary	—	—		—	—		—			—		—			—			—			—			—			(497		)	(497		)
Issued Common units of Eureka Hunter Holdings for asset acquisition	—	—		—	—		—			—		—			—			—			—			—			12,453			12,453
Net loss	—	—		—	—		—			—		—			(19,915		)	—			—			—			22			(19,893		)
Other comprehensive income:	—	—		—	—		—			—		—			—			—			—			—			—			—
Foreign currency translation	—	—		—	—		—			—		—			—			(617		)	—			—			—			(617		)
Unrealized loss on available for sale securities	—	—		—	—		—			—		—			—			(266		)	—			—			—			(266		)
BALANCE, June 30, 2012	167,691	2,016		2,546	$	1,677	$	20		$	127,315	$	725,238		$	(171,737	)	$	(13,346	)	$	(1,310	)	$	(604	)	$	14,174		$	681,427

The accompanying notes are an integral part of these unaudited consolidated financial statements

4

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Six Months Ended
	June 30,
	2012			2011
Cash flows from operating activities
Net loss	$	(19,915	)	$	(21,730	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Noncontrolling interest	22			117
Depletion, depreciation, and accretion	56,860			16,344
Asset impairment	17,693			—
Share based compensation	8,691			12,014
Cash paid for plugging wells	(101		)	—
Gain on sale of assets	(3,988		)	(1,559		)
Unrealized (gain) loss on derivative contracts	(14,714		)	166
Unrealized loss on available for sale securities	265			—
Amortization of deferred financing costs included in interest expense	10,086			2,812
Deferred taxes	(3,811		)	(197		)
Changes in operating assets and liabilities:
Accounts receivable	(2,530		)	(7,205		)
Inventory	(1,231		)	(3,302		)
Prepaid expenses and other current assets	(991		)	(418		)
Accounts payable	(10,340		)	12,923
Revenue payable	3,356			5,129
Accrued liabilities	9,313			(5,136		)
Net cash provided by operating activities	48,665			9,958
Cash flows from investing activities
Capital expenditures and advances	(224,925		)	(131,840		)
Cash paid in acquisitions, net of cash received of $0 and $2,500, respectively	(434,322		)	(78,523		)
Change in restricted cash and deposits	(256		)	(5,450		)
Proceeds from sales of assets	783			1,824
Net cash used in investing activities	(658,720		)	(213,989		)
Cash flows from financing activities
Net proceeds from the sale of common stock	148,675			—
Net proceeds from sale of preferred shares	50,883			88,531
Proceeds from sale of Series A Preferred units in Eureka Hunter Holdings	127,393			—
Proceeds from exercise of warrants and options	1,197			19,727
Preferred stock dividend paid	(9,531		)	(6,065		)
Principal repayments of debt	(466,209		)	(119,477		)
Proceeds from borrowings on debt	320,000			228,044
Proceeds from borrowings on term loans	21,684			—
Proceeds from issuing Senior Notes	443,971			—
Payment of deferred financing costs	(18,209		)	(2,846		)
Change in other long-term liabilities	145			310
Net cash provided by financing activities	619,999			208,224
Effect of exchange rate changes on cash	(33		)	3
Net increase in cash and cash equivalents	9,911			4,196
Cash and cash equivalents, beginning of period	14,851			554
Cash and cash equivalents, end of period	$	24,762		$	4,750
Supplemental disclosure of cash flow information
Cash paid for interest	$	10,434		$	1,619
Non-cash transactions
Common stock issued for acquisitions	$	1,902		$	345,537
Non-cash consideration received from sale of assets	$	7,706		$
Debt assumed in acquisition	$	—		$	71,895
Exchangeable common stock issued for acquisition of NuLoch Resources	$	—		$	31,642

The accompanying notes are an integral part of these unaudited consolidated financial statements

5

NOTE 1 — BASIS OF PRESENTATION

The accompanying unaudited interim financial statements of Magnum Hunter Resources Corporation (the “Company” or “Magnum Hunter”) have been prepared in accordance with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission, and should be read in conjunction with the audited financial statements and notes thereto contained in the Company’s annual report on Form 10-K, as amended, for the year ended December 31, 2011.  In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of the financial position and the results of operations for the interim periods presented have been reflected herein.  The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.  Notes to the consolidated financial statements that would substantially duplicate the disclosure contained in the audited consolidated financial statements as reported in the 2011 annual report on Form 10-K, as amended, have been omitted.

Income or Loss per Share

Basic income or loss per common share is net income or loss available to common stockholders divided by the weighted average of common shares outstanding during the period.  Diluted income or loss per common share is calculated in the same manner, but also considers the impact to net income and common shares outstanding for the potential dilution from in-the-money common stock options and warrants, and convertible debentures and preferred stock.

We have issued potentially dilutive instruments in the form of restricted common stock granted and not yet issued, common stock warrants, and common stock options.  The total number of potentially dilutive securities at June 30, 2012 was 29,253,460.  There were 15,846,191 potentially dilutive securities outstanding at June 30, 2011.  We did not include the potentially dilutive securities in our calculation of diluted loss per share during either period because to include them would be anti-dilutive due to our net loss during those periods.

The following table summarizes the types of potentially dilutive securities outstanding as of June 30, 2012 and 2011:

	June 30,
	2012	2011
	(in thousands)
Warrants	13,516	284
Restricted Shares granted, not yet issued	19	25
Common Stock Options	15,718	15,537

NOTE 2 — LIQUIDITY

At June 30, 2012, we had cash and cash equivalents of $24.8 million, of which $16.6 million was held by Eureka Hunter and was only available for use by Eureka Hunter Holdings, LLC (“Eureka Hunter”), and a working capital deficit of $68.6 million.  For the three months ended June 30, 2012, we had net loss attributable to common shareholders of $14.6 million and an operating loss from continuing operations of $11.6 million, including a $9.0 million impairment of long-lived assets.

We depend on our credit agreements, as described in Note 9, to fund a portion of our operating and capital needs.  Under our senior revolving credit agreement, our borrowing base at June 30, 2012, based upon our proved reserves, was $212.5 million, and our remaining borrowing capacity was $112.5 million on June 30, 2012.  Pursuant to the terms of our senior revolving credit agreement our borrowing base has been increased to $260 million as of August 8, 2012, an increase of $47.5 million.

At June 30, 2012, we were in compliance with all of our covenants contained in our senior revolving credit agreement as described in Note 9.

At June 30, 2012, Eureka Hunter Pipeline, LLC was not in compliance with the covenants contained in the Eureka Hunter Credit Facilities that require Eureka Hunter to maintain certain ratios of debt to EBITDA and interest coverage.  We have received a waiver of the covenants at June 30, 2012.  In addition, we have executed an amendment for future ratios of debt to EBITDA and interest coverage through December 31,2012.  These adjustments were necessary primarily due to the delay in the completion of the Mobley Processing Plant. Based on the amended facility, management believes it is probable we will be in compliance with Eureka Hunter Credit Facility covenants for each quarter at least through June 30, 2013.

6

We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) debt available under our credit agreements and (iv) our ability to access the capital markets, provide sufficient means to conduct our operations, meet our contractual obligations, including our debt covenant requirements and undertake our capital expenditure program for the twelve months ending June 30, 2013.

NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Presentation

The consolidated financial statements include the accounts of Magnum Hunter and our wholly-owned subsidiaries, Eagle Ford Hunter, Inc., Triad Hunter, LLC, Alpha Hunter Drilling, LLC, Hunter Real Estate, LLC, NGAS Hunter, LLC, Magnum Hunter Production, Inc., Magnum Hunter Resources GP, LLC, Magnum Hunter Resources LP, MHR Callco Corporation, MHR Exchangeco Corporation, Williston Hunter Canada, Inc., Williston Hunter, Inc., Williston Hunter ND, LLC, NGAS Gathering, LLC, Sentra Corporation, Energy Hunter Securities, Inc., Bakken Hunter, LLC, and MHR Services, LLC.  We also have consolidated our 87.5% controlling interest in PRC Williston, LLC, or PRC, and our 65.9% controlling interest in Eureka Hunter Holdings, LLC, and its subsidiaries, Eureka Hunter Pipeline, LLC, and TransTex Hunter, LLC, Eureka Hunter Land, LLC, with noncontrolling interests recorded for the outside interest in those majority owned subsidiaries. The consolidated financial statements also reflect the interest of Magnum Hunter Production, Inc. in various managed drilling partnerships.  We account for the interests in these partnerships using the proportionate consolidation method.  All significant intercompany balances and transactions have been eliminated.

Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America.  The preparation of our financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.  These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances.  Actual results could differ from those estimates under different assumptions and conditions.  Significant estimates are required for proved oil and gas reserves which may have a material impact on the carrying value of an oil and gas property.

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operations.  We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

Reclassification of Prior-Year Balances

Certain prior-year balances in the consolidated financial statements have been reclassified to correspond with current-year classifications.  As a result of the sale of Hunter Disposal, LLC, we reclassified the gain on sale and all prior operating income and related interest expense for this property as discontinued operations.

Regulated Activities

Energy Hunter Securities, Inc. is a registered broker-dealer and member of the Financial Industry Regulatory Authority.  Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Because it does not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities, Inc. is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness.  At June 30, 2012, Energy Hunter Securities, Inc. had net capital of $95,000 and aggregate indebtedness of $35,000.

Sentra Corporation’s gas distribution billing rates are regulated by Kentucky’s Public Service Commission based on recovery of purchased gas costs.  We account for its operations based on the provisions of ASC 980-605, Regulated Operations—Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators.  We did not have any gas transmission, compression and processing revenue which included gas utility sales from Sentra Corporation’s regulated operations during the six months ended June 30, 2012 and 2011.

Other Comprehensive Income

The functional currency of the countries in which we operate is the U.S. Dollar in the United States and the Canadian Dollar in Canada.  For purposes of consolidation, we translate the assets and liabilities of our Canadian subsidiary into U.S. Dollars at current exchange rates while revenues and expenses are translated at the average rates in effect for the period.  The related translation gains and losses are included in accumulated other comprehensive income within stockholders’ equity on our consolidated balance sheets. During the six months ended June 30, 2012 and 2011, we recognized a translation loss of $617,000 and $3.2 million, net of the related income taxes, respectively.

7

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance.  We recorded $17.7 million in unproved property impairment during the six months ended June 30, 2012, comprising $5.0 million in our Appalachian region, $9.1 million in our Williston Basin region, and 3.6 million in our Table Land region, due to expiring acreage that we chose not to develop.  We recorded none for the six months ended June 30, 2011.

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and the liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually and when impairment indicators arise. Goodwill of $30.6 million was recorded in our midstream segment during 2012 as a result of our acquisition of the assets of Transtex Gas Services, LP, discussed in Note 5, Acquisitions.

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules.  We regularly review all new pronouncements to determine their impact, if any, on our financial statements.

In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements.  Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  This guidance became effective for us beginning with the quarter ended March 31, 2012, and requires retrospective application to earlier periods presented.  Our condensed consolidated statements of income and comprehensive income for the three and six months ended June 30, 2012 and 2011 contain the required disclosure.  The implementation of this accounting pronouncement also resulted in increased disclosure in Note 15.

In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure.  Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed.  It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in shareholders’ equity.  This guidance became effective for us beginning with the quarter ended March 31, 2012.  The adoption of this accounting pronouncement did not have an effect on the fair value measurement, but rather expanded upon existing disclosures.

In December 2011, the FASB issued an amendment to the accounting guidance for disclosure of arrangements that permit offsetting assets and liabilities.  The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement.  The amendment will be effective for us, beginning on January 1, 2013, and must be applied retrospectively.  We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2011 Annual Report on Form 10-K, as amended.

NOTE 4 — FAIR VALUE OF FINANCIAL INSTRUMENTS

Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The standards also establish a framework for measuring fair value and a valuation hierarchy based upon the transparency of inputs used in the valuation of an asset or liability.  Classification within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The valuation hierarchy contains three levels:

· Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets

· Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable

· Level 3 — Significant inputs to the valuation model are unobservable

We used the following fair value measurements for certain of our assets and liabilities as of June 30, 2012 and December 31, 2011:

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Level 1 Classification:

Available for Sale Securities

At June 30, 2012, and December 31, 2011, the Company held common stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT with quoted prices in active markets.  Accordingly, the fair market value measurements of these securities have been classified as Level 1.

Level 2 Classification:

Derivative Instruments

At June 30, 2012 and December 31, 2011, the Company had commodity derivative financial instruments in place.  The Company does not apply hedge accounting; therefore, the changes in fair value subsequent to the initial measurement are recorded as income or expense.  The estimated fair value amounts of the Company’s derivative instruments have been determined at discrete points in time based on relevant market information which resulted in the Company classifying such derivatives as Level 2.  Although the Company’s derivative instruments are valued using public indexes, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange.  See Note 7 — Financial Instruments and Derivatives, for additional information.

As of June 30, 2012 and December 31, 2011, the Company’s derivative contracts were with major financial institutions, all of which are senior lenders to the Company, and have investment grade credit ratings, which are believed to have a minimal credit risk.  As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above.  However, the Company does not anticipate such nonperformance and monitors the credit worthiness of its counterparties on an ongoing basis.

The following tables present recurring financial assets and liabilities which are carried at fair value as of June 30, 2012 and December 31, 2011:

	Fair Value Measurements on a Recurring Basis
	June 30, 2012(In thousands)
	Level 1		Level 2		Level 3
Available for sale securities	$	232	$	—	$	—
Commodity derivatives	$	—	$	12,972	$	—
Total assets at fair value	$	232	$	12,972	$	—
Commodity derivatives	$	—	$	3,246	$	—
Total liabilities at fair value	$	—	$	3,246	$	—

	Fair Value Measurements on a Recurring Basis
	December 31, 2011(In thousands)
	Level 1		Level 2		Level 3
Available for sale securities	$	497	$	—	$	—
Commodity derivatives	$	—	$	6,924	$	—
Total assets at fair value	$	497	$	6,924	$	—
Commodity derivatives	$	—	$	11,912	$	—
Total liabilities at fair value	$	—	$	11,912	$	—

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NOTE 5 — ACQUISITIONS

Eagle Operating Asset Acquisition

On March 30, 2012, the Company, through its wholly owned subsidiary, Williston Hunter ND, LLC, a Delaware limited liability company (“Williston Hunter”), closed on the purchase of certain assets of Eagle Operating, Inc. (“Eagle”), effective April 1, 2011.  Total consideration was $52.9 million consisting of $51.0 million in cash and 296,859 shares of Magnum Hunter restricted common stock valued at $1.9 million based on a price of $6.41 per share.

The fair value of the assets acquired approximated the $52.9 million of consideration paid.

The following table summarizes the purchase price and the fair values of the net assets acquired from Eagle at the date of acquisition as determined as of June 30, 2012 (in thousands, except share information):

Fair value of total purchase price:
296,859 shares of common stock issued on March 30, 2012 at $6.41 per share	$	1,903
Cash	50,973
Total	$	52,876
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	54,832
Asset retirement obligation	(1,956		)
Total	$	52,876

Utica Shale Asset Acquisition

On February 17, 2012, the Company closed on the acquisition of leasehold mineral interests located predominately in Noble County, Ohio for a total purchase price of $24.8 million.  The Utica Acreage consists of approximately 15,558 gross (12,186 net) acres.

The fair value of the assets acquired approximated the $24.8 million of consideration paid.

The following table summarizes the purchase price and the fair values of the net assets acquired at the date of acquisition as determined as of June 30, 2012 (in thousands):

Fair value of total purchase price:
Cash	$	24,826
Total	$	24,826
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	24,826
Total	$	24,826

Baytex Energy USA Asset Acquisition

On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC, closed on the acquisition of certain assets of Baytex Energy USA, Ltd, an affiliate of Baytex Energy Corporation, for a total purchase price of $312.0 million.  The purpose of the acquisition is to build the Company’s reserve base in a key shale area and increase the Company’s production rate in the current period.  The acquired assets include all of Baytex’s non-operated working interest in oil and gas properties and wells located in Divide and Burke Counties,

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North Dakota, within an area subject to that certain Operating Agreement, dated January 1, 2010 (the “Operating Agreement”), among Samson Resources Company, as operator, Baytex Energy Corporation, and Williston Hunter, Inc., a wholly-owned subsidiary of Magnum Hunter.  As a result of the acquisition, Williston Hunter currently owns an approximate 47.5% non-operated working interest in the acquired assets.  The preliminary valuations of the assets acquired are set forth below.

The fair value of the assets acquired approximated the $312.0 million of consideration paid.

The following table summarizes the purchase price and the fair values of the net assets acquired at the date of acquisition as determined as of June 30, 2012 (in thousands):

Fair value of total purchase price:
Cash	$	312,018
Total	$	312,018
Amounts recognized for assets acquired and liabilities assumed:
Oil and gas properties	$	312,294
Asset retirement obligation		(276	)
Total	$	312,018

TransTex Gas Services, LP Asset Acquisition

On April 2, 2012, the Company, through its majority owned subsidiary, Eureka Hunter Holdings, LLC, and its wholly owned subsidiary, Eureka Hunter Acquisition Sub, LLC (now TransTex Hunter, LLC), closed on their purchase of certain assets of TransTex Gas Services, LP under the asset purchase agreement dated March 21, 2012 which resulted in the recognition of approximately $30.6 million in goodwill.  The Company expects all of the goodwill to be deductible for tax purposes.  The purpose of the acquisition is to build midstream assets.  The total purchase price paid for the acquired assets was $58.5 million, comprising $46.8 million in cash and 585,000 Series A Common Units representing membership interests in Eureka Hunter Holdings, LLC with a value of $11.7 million.  As a result of this transaction, the company recorded a noncontrolling interest in this subsidiary.  The value of the units transferred as partial consideration for the acquisition totaling $12.5 million as of date of acquisition was determined utilizing a discounted future cash flow analysis.  The preliminary valuations of the assets acquired are set forth below.

Fair value of total purchase price:
Cash	$	46,800
Series A Common Units	11,700
Total	$	58,500
Amounts recognized for assets acquired and liabilities assumed:
Working Capital	$	5,057
Equipment and other fixed assets	11,227
Other assets	1,122
Goodwill	30,602
Other Intangibles	10,492
	$	58,500

The consolidated statement of operations includes revenue from the assets acquired from Eagle Operating of $1.8 million for the three months ended June 30, 2012, and an operating loss from those assets of $278,000 for the three months ended June 30, 2012. The consolidated statement of operations includes revenue from the assets acquired from Baytex Energy USA of $2.6 million and an operating loss of $515,000 for the three months ended June 30, 2012. The consolidated statement of operations includes revenues from the assets acquired from TransTex Gas Services, LP, of $2.3 million and an operating loss from those assets of $421,000 for the three months ended June 30, 2012.

The following unaudited summary, prepared on a pro forma basis, presents the preliminary results of operations for the three and six month periods ended June 30, 2012, and 2011, as if the acquisitions of the Eagle Operating assets, the Utica Shale assets, the Baytex Energy USA assets, the TransTex Gas Services assets and the transactions involving the issuance of Eureka Hunter Holdings, LLC 8% Series A Preferred Units (See Note 11 — Shareholders’ Equity) had occurred as of the beginning of 2011.  The pro forma information includes the effects of adjustments for operating income and expense, interest expense, depreciation and depletion expense, and dividend expense.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of each period presented, nor are they necessarily indicative of future consolidated results.

	Three Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,			Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands, except per-share data)
Total operating revenue	$	65,083		$	43,912		$	131,047		$	85,273
Total operating costs and expenses	75,587			66,868			152,275			108,520
Operating loss	(10,504		)	(22,956		)	(21,228		)	(23,247		)
Interest expense and other	(3,161		)	(9,917		)	(10,131		)	(23,458		)
Net loss attributable to Magnum Hunter	(13,665		)	(32,873		)	(31,359		)	(46,705		)
Dividends on preferred stock	(9,472		)	(6,202		)	(14,042		)	(11,555		)
Net loss attributable to common stock holders	$	(23,137	)	$	(39,075	)	$	(45,401	)	$	(58,260	)
Loss per common share, basic and diluted	$	(0.12	)	$	(0.26	)	$	(0.27	)	$	(0.45	)

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NOTE 6 — DISCONTINUED OPERATIONS

On February 17, 2012, the Company, through its wholly owned subsidiary, Triad Hunter, LLC, sold 100% of the equity ownership interest of Hunter Disposal, LLC, for total consideration of $9.9 million comprising cash of $2.2 million, 1,846,722 common shares of GreenHunter Energy, Inc., valued at $3.3 million based on a closing price of $1.79 per share, 88,000 shares of GreenHunter Energy, Inc. 10% Series C Preferred Stock, valued at $2.2 million based on a stated value of $25 per share, and a promissory note of $2.2 million which is convertible, at the option of the Company, into 880,000 shares of GreenHunter Energy common stock based on the conversion price of $2.50 per share.  The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital to reflect the effective date of the sale of December 31, 2011.  GreenHunter Energy is a related party as described in Note 12.  The operating results of Hunter Disposal, LLC, for the six months ended June 30, 2012 and the three and six months ended June 30, 2011, have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below:

	Three Months Ended June 30,			Six Months Ended June 30,			Six Months Ended June 30,
	2011			2012			2011
	(in thousands)
Field operations and other revenue	$	2,808		$	2,400		$	3,591
Operating expenses	(1,582		)	(2,047		)	(2,100		)
Other income (expense)	(6		)	1			(11		)
Gain on sale of discontinued operations	—			4,325			—
Income from discontinued operations	$	1,220		$	4,679		$	1,480

NOTE 7 — FINANCIAL INSTRUMENTS AND DERIVATIVES

We enter into certain commodity derivative instruments which are effective in mitigating commodity price risk associated with a portion of our future monthly natural gas and crude oil production and related cash flows.  Our oil and gas operating revenues and cash flows are impacted by changes in commodity product prices, which are volatile and cannot be accurately predicted.  Our objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of our future crude oil sales from the risk of significant declines in commodity prices, which helps insure our ability to fund our capital budget.  We have not designated any of our commodity derivatives as hedges under ASC 815.

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As of June 30, 2012, we had the following derivative instruments in place:

			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Collars	Jul 2012 - Dec 2012	11,910	$4.58 - $6.42
	Jan 2013 - Dec 2013	12,500	$4.50 - $5.96
Swaps	Jul 2012 - Dec 2012	16,100	$3.53
	Jan 2013 - Dec 2013	15,500	$3.52
Ceilings sold (call)	Jan 2014 - Dec 2014	16,000	$5.91

			Weighted Avg
Crude Oil	Period	Bbls/day	Price per Bbl
Collars	Jul 2012 - Dec 2012	2,950	$81.80 - $98.76
	Jan 2013 - Dec 2013	2,763	$81.38 - $97.61
	Jan 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Three-way collars (1)	Jul 2012 - Dec 2012	50	$55.00 - $75.00 - $108.00
	Jan 2013 - Dec 2013	2,000	$60.63 - $80.00 - $100.00
Three-way collar (2)	Jan 2013 - Dec 2013	763	$65.00 - $91.25 - $101.25
Ceilings sold (call)	Jul 2012 - Dec 2012	688	$100.30
Ceilings purchased (call)	Jul 2012 - Dec 2012	688	$91.25
Floors sold (put)	Jul 2012 - Dec 2012	1,400	$80.00
	Jan 2013 - Dec 2013	763	$65.00
	Jan 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00
Floors purchased (put)	Jul 2012 - Dec 2012	1,553	$93.52

(1) These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.

(2) This three-way collar is a combination of three options: a sold call, a purchased call and a sold put.

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The following table summarizes the fair value of our derivative contracts as of the dates indicated:

		Gross Derivative Assets				Gross Derivative Liabilities
Derivatives not designated as hedging				December 31,					December 31,
instruments	Balance Sheet Classification	June 30, 2012		2011		June 30, 2012			2011
		(in thousands)
Commodity
	Current Assets - Derivatives	$	10,971	$	5,732	$	—		$	—
	Derivatives and Other Long Term Assets	2,001		1,192		—			—
	Derivative and other Current Liabilities	—		—		—			(5,800		)
	Derivative and other Long Term Liabilities	—		—		(3,246		)	(6,112		)
Total Commodity		$	12,972	$	6,924	$	(3,246	)	$	(11,912	)

	Three Months Ended June 30, 2012 (in thousands)		Six Months Ended June 30, 2012 (in thousands)
Realized gain	$	4,251	$	5,738
Unrealized gain	17,616		14,714
Net gain	$	21,867	$	20,452

	Three Months Ended June 30, 2011 (in thousands)			Six Months Ended June 30, 2011 (in thousands)
Realized loss	$	(517	)	$	(508	)
Unrealized gain (loss)	3,185			(166		)
Net gain (loss)	$	2,668		$	(674	)

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

The Company records a liability for the fair value of an asset’s retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset.  We have included estimated future costs of abandonment and dismantlement in our successful efforts amortization base and amortize these costs as a component of our depreciation, depletion, and accretion expense in the accompanying consolidated financial statements.

The following table summarizes the Company’s asset retirement obligation transactions during the six month period ended June 30, 2012:

	Six Months Ended
	June 30, 2012
	(in thousands)
Asset retirement obligation at beginning of period	$	20,584
Assumed in Eagle Operating acquisition	1,956
Assumed in Baytex Energy USA, Ltd Acquisition	276
Liabilities incurred	186
Liabilities settled	(39		)
Accretion expense	790
Revisions in estimated liabilities	65
Effect of foreign currency translation	(2		)
Asset retirement obligation at end of period	23,816
Less: current portion	(1,480		)
Asset retirement obligation at end of period	$	22,336

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NOTE 9 — NOTES PAYABLE

Notes payable at June 30, 2012 consisted of the following:

	June 30, 2012
	(in thousands)
Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount	$	443,971
Various equipment and real estate notes payable with maturity dates January 2015 - April 2021, interest rates of 4.25% - 5.88%	15,781
Eureka Hunter Pipeline, LLC second lien term loan due August 16, 2018, interest rate of 12.5%	50,000
Senior revolving credit facility due April 13, 2016, interest rate of 3.0% at June 30, 2012	100,000
	$	609,752
Less: current portion	(3,430		)
Total Long-Term Debt	$	606,322

The following table presents the approximate annual maturities of debt:

	(in thousands)
2012	$	1,609
2013	3,704
2014	2,465
2015	4,111
Thereafter	597,863
Total	$	609,752

On February 14, 2012, the Company entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement.  The Fifth Amendment increased the borrowing base on the Senior Revolving Credit Facility from $200 million to $235 million.

On February 14, 2012, the Company entered into the Second Amendment to the Second Lien Term Loan Credit Agreement.  The Second Amendment amends certain provisions of the Second Lien Term Loan Credit Agreement to correspond to the amendments made pursuant to the Fifth Amendment to the Second Amended and Restated Credit Agreement.

On May 2, 2012, the Company entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement, as amended.  Pursuant to the sixth amendment to the credit facility, our borrowing base under our senior revolving credit agreement was increased from $235.0 million to $275.0 million, then pursuant to the issuance of the $450.0 million 9.75% Senior Notes the borrowing base was decreased from $275.0 million to $187.5 million, then pursuant to the closing of the Baytex Acquisition the borrowing base was increased from $187.5 million to $212.5 million.  The Seventh Amendment to the Second Amended and Restated Credit Agreement reduced the current ratio covenant to 0.85 for June 30, 2012 which increased to 1.0 with the aforementioned bond transaction.

On May 16, 2012, the Company successfully completed the issuance and sale of $450.0 million aggregate principal amount of its 9.75% Senior Notes due May 15, 2020.  The Senior Notes are unsecured and are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of the Company’s domestic subsidiaries, and may be guaranteed by certain future domestic subsidiaries of the Company.  A portion of the proceeds were used to retire the Company’s term loan of $100.0 million.

At June 30, 2012, we were in compliance with all of our covenants contained in the senior revolving credit agreement.

At June 30, 2012, Eureka Hunter Pipeline, LLC was not in compliance with the covenants contained in the Eureka Hunter Credit Facilities that require Eureka Hunter Pipeline to maintain certain ratios of debt to EBITDA and interest coverage.  We have received a waiver of the covenants at June 30, 2012 and entered into the amendment described below for September 30, 2012 and December 31, 2012 which increased the maximum debt to EBITDA ratio and decreased the minimum interest coverage ratios.  These amendments were necessary primarily due to the delay in the completion of the Mobley Processing Plant. Based on an amendment to the Eureka Hunter Credit Facilities, management believes it is probable Eureka Hunter will be in compliance

15

with the covenant based upon the amended facility.  We must also be in compliance with the covenant for the quarterly measurement dates following June 30, 2012.  Management believes it is probable we will be in compliance with these covenants for each quarter at least through June 30, 2013.

On June 29, 2012, Eureka Hunter Pipeline, LLC, entered into a Limited Waiver and Third Amendment to Second Lien Term Loan Agreement.  The Third Amendment amends the Second Lien Term Loan Agreement (as defined below) by reducing the minimum Interest Coverage Ratio (as such term is defined in the Second Lien Term Loan Agreement) to 0.85:1.00 for the fiscal quarters ending September 30, 2012 and December 31, 2012, and by increasing the maximum Total Leverage Ratio (as such term is defined in the Second Lien Term Loan Agreement) to 9.50:1.00 and 8.5:1.00 for the fiscal quarters ending September 30, 2012 and December 31, 2012, respectively. The lenders under the Second Lien Term Loan Agreement also agreed to waive any events of default occurring as a result of Eureka Hunter Pipeline’s failure to comply with such ratios during the fiscal quarter ended June 30, 2012. Finally, the Third Amendment modified the interest rate provisions in the Second Lien Term Loan Agreement so that after June 29, 2012 all interest shall be payable in cash.  The reduced minimum Interest Coverage Ratio shall increase back to 1.00:1.00, and the increased maximum Total Leverage Ratio shall decrease back to 6:50:1:00, if Eureka Hunter Pipeline receives funding prior to December 31, 2012 under its First Lien Credit Agreement with SunTrust Bank, unless such credit agreement is amended in a manner satisfactory to PennantPark.

NOTE 10 — SHARE BASED COMPENSATION

Under the amended and restated 2006 Stock Incentive Plan, our common stock, common stock options, and stock appreciation rights may be granted to employees and other persons who contribute to the success of Magnum Hunter.  Currently, 20,000,000 shares of our common stock are authorized to be issued under the plan, and 3,158,143 shares have been issued as of June 30, 2012.

We recognized share-based compensation expense of $4.1 million and $8.7 million for the three and six months ended June 30, 2012, and we recognized $10.7 million and $12.0 million for the three and six months ended June 30, 2011.

A summary of common stock option and stock appreciation rights activity for the six months ended June 30, 2012 is presented below:

			Weighted Avg
			Exercise Price
Outstanding at beginning of period	12,566,199		$	5.64
Granted	4,769,250		$	6.08
Exercised	(841,200	)	$	1.40
Cancelled	(744,848	)	$	7.51
Outstanding at end of period	15,749,401		$	5.91
Exercisable at end of period	9,017,777		$	5.86

A summary of the Company’s non-vested common stock options and stock appreciation rights as of June 30, 2012 is presented below.

Non-vested Common Stock Options	Shares
Non-vested at beginning of period	5,650,782
Granted	4,769,250
Vested	(3,085,560	)
Cancelled	(596,598	)
Non-vested at end of period	6,737,874

Total unrecognized compensation cost related to the non-vested common stock options was $21.1 million and $21.8 million as of June 30, 2012 and 2011, respectively.  The cost at June 30, 2012, is expected to be recognized over a weighted-average period of 2.38 years.  At June 30, 2012, the aggregate intrinsic value for common stock options was $5.3 million, the weighted average remaining contract life was 6.58 years, and the average fair value at the grant date of the options was $4.26 per option.

Total unrecognized compensation cost related to the above non-vested, restricted shares amounted to $561 thousand and $973 thousand as of June 30, 2012 and 2011, respectively.  The cost at June 30, 2012, is expected to be recognized over a weighted-average period of 1.42 years.

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NOTE 11 — SHAREHOLDERS’ EQUITY

Common Stock

During the six months ended June 30, 2012, the Company issued 62,679 shares of the Company’s common stock in connection with share-based compensation which had fully vested to senior management and directors of the Company.

On March 30, 2012, the Company issued 296,859 restricted shares of the Company’s common stock valued at approximately $1.9 million based on a price of $6.41 per share as partial consideration for the acquisition of the assets of Eagle Operating.  See Note 5 — Acquisitions for additional information.

During the six months ended June 30, 2012, the Company issued 8,719 shares of the Company’s common stock upon the exercise of warrants for total proceeds of approximately $22 thousand.

During the six months ended June 30, 2012, the Company issued 841,200 shares of the Company’s common stock upon the exercise of fully vested common stock options for proceeds of approximately $1.2 million.

During the six months ended June 30, 2012, the Company issued 1,677,749 shares of the Company’s common stock upon exchange of 1,677,749 shares of MHR Exchangeco Corporation’s exchangeable shares.

On May 16, 2012, the Company issued 35,000,000 shares of the Company’s common stock in an underwritten public offering at a price of $4.50 per share for total proceeds of $157.5 million.  The net proceeds of the offering, after deducting underwriting discounts and commissions and estimated offering expenses, were approximately $148.7 million.

During the six months ended June 30, 2012, the Company acquired the interest in a subsidiary which the Company did not previously own.  The company acquired the non-controlling interest valued at $497,000.

Series D Cumulative Preferred Stock

During the six months ended June 30, 2012, the Company sold 1,108,749 shares of our 8.0% Series D Cumulative Perpetual Preferred Stock with a liquidation preference of $50.00 per share under the At the Market (“ATM “) sales agreement for net proceeds of $50.9 million.  The Series D Preferred Stock cannot be converted into common stock of the Company but may be redeemed by the Company, at the Company’s option, on or after March 14, 2014 for par value or $50.00 per share or in certain circumstances, prior to such date as a result of a change in control.

Eureka Hunter Holdings, LLC, 8% Series A Preferred Units

On March 21, 2012, the Company sold 3,000,000 Preferred Units of Eureka Hunter Holdings, LLC (“Eureka Holdings”), a majority-owned subsidiary of the Company, to Ridgeline Midstream Holdings, LLC (“Ridgeline”), an affiliate of ArcLight Capital Partners, LLC.  The preferred units sold represent 16.6% of the ownership of Eureka Holdings on a basis as converted to Series A Common Units of Eureka Holdings.  The preferred units sold were valued at $60.0 million.  Eureka Hunter Holdings will pay cumulative distributions quarterly on the Series A Preferred Units at a fixed rate of 8% per annum of the initial liquidation preference.  The distribution rate is increased to 10% if any distribution is not paid when due.  The Board of Directors of Eureka Hunter Holdings may elect to pay up to 75% of the dividends owed during the quarter ended March 31, 2012 through the quarter ending March 31, 2013 in the form of “paid-in-kind” units and up to 50% during the quarter ending June 30, 2013 through the quarter ending March 31, 2014.  The Series A Preferred Units can be converted into Series A Common Units of Eureka Holdings upon demand by Ridgeline at any time or by Eureka Holdings upon the consummation of an initial public offering, provided that Eureka Holdings converts no less that 50% of the Preferred Units into Common Units at that time.  The Company can redeem all outstanding Series A Preferred units at their liquidation preference any time after March 21, 2017.  Holders of the Series A Preferred units can force redemption of all outstanding Series A Preferred units any time after March 21, 2020, at a redemption rate of the higher of the liquidation value and an internal investment rate of return calculation.  The Eureka Hunter Holdings, LLC 8% Series A Preferred units are recorded as temporary equity because a forced redemption by the holders of the preferred units is outside the Company’s control.

On April 2, 2012, the Company issued 2,340,000 Series A Convertible Preferred Units of Eureka Hunter Holdings to acquire the assets of TransTex Gas Services, LP.  The units transferred had a value of $46.8 million.

On June 20, 2012, Ridgeline invested an additional $25.0 million in Series A Preferred Units of Eureka Hunter Holdings.

NOTE 12 — RELATED PARTY TRANSACTIONS

We rented an airplane for business use at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans, our Chairman and CEO.  Airplane rental expenses totaled $64,125 and $81,225 for the three and six months ended June 30, 2012, respectively and $105,000 and $228,000 for the three and six months ended June 30, 2011, respectively.

17

We obtained accounting services and use of office space from GreenHunter Energy, Inc., an entity for which Mr. Evans is a director, an officer and major shareholder and for which Mr. Ormand, our Chief Financial Officer and a director, is also a director.  This agreement has terminated and all accounting services are now performed by Magnum Hunter personnel.  Professional services expenses totaled $0 for the three and six months ended June 30, 2012, and $28,000 and $46,000 for the three and six months ended June 30, 2011, respectively.

During the six months ended June 30, 2012 and 2011, the Company paid rent of $18,000 and $9,000, respectively, pertaining to a lease for a corporate apartment from an executive of the Company which is being used by other Company employees.  The lease terminated in May of 2012 and the Company did not renew it.

During the six months ended June 30, 2012, Eagle Ford Hunter, Triad Hunter, and Hunter Disposal, LLC, wholly owned subsidiaries of the Company, rented storage tanks for disposal water and equipment from GreenHunter Energy, Inc.  Rental costs totaled $878,000 and approximately $1.6 million for the three and six months ended June 30, 2012, respectively, and $0 for the three and six months ended June 30, 2011.  As of June 30, 2012, our net accounts payable to GreenHunter Energy, Inc. was $754,000 for these leases.

On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, LLC, to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Energy, Inc.  The terms and conditions of the equity purchase agreement between the parties were approved by the audit committee or an independent special committee for each party.  Total consideration for the sale was approximately $9.9 million comprising $2.2 million in cash, 1,846,722 shares of GreenHunter restricted common stock with a fair value of $3.3 million based on a closing price of $1.79 per share, 88,000 shares of GreenHunter Energy, Inc. 10% Series C cumulative preferred stock with a stated value of $2.2 million, and a $2.2 million convertible promissory note due to the Company.  In connection with the sale, Triad Hunter, LLC, entered into agreements with Hunter Disposal, LLC and GreenHunter Water, LLC for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water, LLC.  See Note 6 — Discontinued Operations for additional information.

Mr. Evans, our Chairman and Chief Executive Officer, is a 4.0% limited partner in TransTex Gas Services, LP, which limited partnership received consideration of 585,000 Series A common units of Eureka Hunter Holdings, LLC, and cash of $46.8 million upon the Company’s acquisition of certain of its assets.  In addition, Eureka Hunter and TransTex agreed to provide the limited partners of TransTex the opportunity to purchase additional Class A common units in lieu of a portion of the cash distribution they would otherwise have received.  Certain limited partners purchased such units, including Mr. Evans, who purchased 27,641 Class A common units of Eureka Hunter Holdings, LLC, for $553,000 at the same purchase price offered to all TransTex investors.

NOTE 13 — COMMITMENTS AND CONTINGENCIES

We had no material changes to our commitments and contingencies for the six month period ended June 30, 2012.

NOTE 14 — SEGMENT REPORTING

The Oilfield Services, Midstream, and Upstream functions best define the operating segments of the Company that are reported separately.  The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment.  The Upstream segment is organized and operates to explore for and produce crude oil and natural gas.  The Company has significant operations both in the United States and in Canada in the upstream segment.  The Oilfield Services segment is organized and operates to sell services to third party producers of crude oil and natural gas as well as to affiliate’s and subsidiaries of the Company. The Midstream segment operates a network of pipelines that gathers natural gas.  These segments are broadly understood across the petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Company because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Company’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete financial information is available.

18

The following tables set forth operating activities by segment for the three and six months ended June 30, 2012 and 2011, respectively.

	For the Three Months Ended June 30, 2012
	(in thousands)
	Corporate						Canadian						Oilfield			Intersegment
	Unallocated			U.S. Upstream			Upstream			Midstream			Services			Eliminations			Total
Oil and gas sales	$	—		$	46,209		$	7,473		$	—		$	—		$	—		$	53,682
Gas gathering and processing	—			1,343			—			3,466			—			—			4,809
Oilfield services	—			—			—			—			1,391			(434		)	957
Gas marketing	—			—			—			733			—			—			733
Other	—			104			1			14			—			—			119
Total revenue	—			47,656			7,474			4,213			1,391			(434		)	60,300
Lease operating expenses	—			11,866			901			—			—			(782		)	11,985
Severance taxes and marketing	—			3,252			560			—			—			—			3,812
Exploration	—			387			(2		)	—			—			—			385
Gas gathering and processing	—			640			—			1,258			—			348			2,246
Oilfield services	—			—			—			—			1,219			—			1,219
Gas marketing	—			—			—			713			—			—			713
Impairment of oil & gas properties	—			5,443			3,580			—			—			—			9,023
Depreciation, depletion, and accretion	—			24,243			4,799			700			249			—			29,991
General and administrative	7,227			2,868			1,620			795			82			—			12,592
Total expenses	7,227			48,699			11,458			3,466			1,550			(434		)	71,966
Interest income	55			1			767			—			—			(763		)	60
Interest expense	(17,502		)	(893		)	—			(2,225		)	(75		)	763			(19,932		)
Gain (loss) on derivative contracts	21,867			—			—			—			—			—			21,867
Other income and (expense)	—			(246		)	—			(493		)	—			—			(739		)
Total other income and (expense)	4,420			(1,138		)	767			(2,718		)	(75		)	—			1,256
Loss from continuing operations before non-controlling interest	(2,807		)	(2,181		)	(3,217		)	(1,971		)	(234		)	—			(10,410		)
Income tax benefit	—			2,206			795			—			—			—			3,001
Net income attributable to non-controlling interest	—			(48		)	—			—			—			—			(48		)
Net loss from continuing operations	(2,807		)	(23		)	(2,422		)	(1,971		)	(234		)	—			(7,457		)
Net loss	$	(2,807	)	$	(23	)	$	(2,422	)	$	(1,971	)	$	(234	)	$	—		$	(7,457	)

19

	For the Three Months Ended June 30, 2011
	(in thousands)
	Corporate						Canadian					Oilfield			Intersegment
	Unallocated			U.S. Upstream			Upstream			Midstream		Services			Eliminations			Total
Oil and gas sales	$	—		$	24,990		$	1,056		$	—	$	—		$	—		$	26,046
Gas gathering and processing	—			364			—			271		—			—			635
Oilfield services	—			—			—			—		1,764			(553		)	1,211
Other	—			119			—			1,512		9			—			1,640
Total revenue	—			25,473			1,056			1,783		1,773			(553		)	29,532
Lease operating expenses	—			6,502			328			—		—			(268		)	6,562
Severance taxes and marketing	—			1,801			—			—		—			—			1,801
Exploration	—			358			—			—		—			—			358
Gas gathering and processing	—			—			—			75		—			—			75
Oilfield services	—			316			—			—		1,538			(284		)	1,570
Depreciation, depletion, and accretion	—			9,509			681			437		107			—			10,734
General and administrative	20,800			2,197			406			122		115			—			23,640
Total expenses	20,800			20,683			1,415			634		1,760			(552		)	44,740
Interest income	—			1			513			—		—			(513		)	1
Interest expense	(3,775		)	(598		)	(28		)	—		(32		)	511			(3,922		)
Gain (loss) on derivative contracts	2,668			—			—			—		—			—			2,668
Other income and (expense)	—			84			4			—		—			—			88
Total other income and (expense)	(1,107		)	(513		)	489			—		(32		)	(2		)	(1,165		)
Income (loss) from continuing operations before income taxes and non-controlling interest	(21,907		)	4,277			130			1,149		(19		)	(3		)	(16,373		)
Income tax benefit (expense)	—			229			(32		)	—		—			—			197
Net income attributable to non controlling interest	—			(84		)	—			—		—			—			(84		)
Net income (loss) from continuing operations	(21,907		)	4,422			98			1,149		(19		)	(3		)	(16,260		)
Income from discontinued operations	—			—			—			—		1,220			—			1,220
Net income (loss)	$	(21,907	)	$	4,422		$	98		$	1,149	$	1,201		$	(3	)	$	(15,040	)

20

	For the Six Months Ended June 30, 2012
	(in thousands)
	Corporate						Canadian						Oilfield			Intersegment
	Unallocated			U.S. Upstream			Upstream			Midstream			Services			Eliminations			Total
Oil and gas sales	$	—		$	88,328		$	16,526		$	—		$	—		$	—		$	104,854
Gas gathering and processing	—			2,819			—			4,627			—			—			7,446
Oilfield services	—			—			—			—			6,260			(1,645		)	4,615
Gas marketing	—			—			—			733			—			—			733
Other	—			106			1			17			(276		)	—			(152		)
Total revenue	—			91,253			16,527			5,377			5,984			(1,645		)	117,496
Lease operating expenses	—			22,640			2,231			—			—			(1,645		)	23,226
Severance taxes and marketing	—			6,337			1,198			—			—			—			7,535
Exploration	—			730			—			—			—			—			730
Gas gathering and processing	—			1,358			—			1,378			—			—			2,736
Oilfield services	—			—			—			—			3,567			—			3,567
Gas marketing	—			—			—			713			—			—			713
Impairment of oil & gas properties	—			14,114			3,580			—			—			—			17,694
Depreciation, depletion, and accretion	—			45,485			9,618			1,168			448			—			56,719
General and administrative	18,050			6,188			2,313			1,107			133			—			27,791
Total expenses	18,050			96,852			18,940			4,366			4,148			(1,645		)	140,711
Interest income	55			2			1,536			—			—			(1,526		)	67
Interest expense	(21,495		)	(1,681		)	(1		)	(3,507		)	(158		)	1,526			(25,316		)
Gain (loss) on derivative contracts	20,452			—			—			—			—			—			20,452
Other income and (expense)	—			123			(1		)	(493		)	—			—			(371		)
Total other income and (expense)	(988		)	(1,556		)	1,534			(4,000		)	(158		)	—			(5,168		)
Income (loss) from continuing operations before non controlling interest	(19,038		)	(7,155		)	(879		)	(2,989		)	1,678			—			(28,383		)
Income tax benefit	—			3,598			213			—			—			—			3,811
Net income attributable to non controlling interest	—			(22		)	—			—			—			—			(22		)
Net income (loss) from continuing operations	(19,038		)	(3,579		)	(666		)	(2,989		)	1,678			—			(24,594		)
Income from discontinued operations	—			—			—			—			354			—			354
Gain on sale of discontinued operations	—			4,325			—			—			—			—			4,325
Net income (loss)	$	(19,038	)	$	746		$	(666	)	$	(2,989	)	$	2,032		$	—		$	(19,915	)

21

	For the Six Months Ended June 30, 2011(in thousands)
	Corporate						Canadian					Oilfield			Intersegment
	Unallocated			U.S. Upstream			Upstream			Midstream		Services			Eliminations			Total
Oil and gas sales	$	—		$	38,951		$	1,056		$	—	$	—		$	—		$	40,007
Gas gathering and processing	—			646			—			572		—			—			1,218
Oilfield services	—			—			—			—		2,708			(1,504		)	1,204
Other	—			119			—			1,512		9			—			1,640
Total revenue	—			39,716			1,056			2,084		2,717			(1,504		)	44,069
Lease operating expenses	—			9,656			328			—		—			(425		)	9,559
Severance taxes and marketing	—			2,796			—			—		—			—			2,796
Exploration	—			673			—			—		—			—			673
Gas gathering and processing	—			—			—			176		—			—			176
Oilfield services	—			685			—			—		2,637			(1,079		)	2,243
Depreciation, depletion, and accretion	—			14,437			681			873		211			—			16,202
General and administrative	26,876			2,677			406			229		235			—			30,423
Total expenses	26,876			30,924			1,415			1,278		3,083			(1,504		)	62,072
Interest income	3			1			513			—		—			(513		)	4
Interest expense	(4,518		)	(603		)	(28		)	—		(67		)	511			(4,705		)
Gain (loss) on derivative contracts	(674		)	—			—			—		—			—			(674		)
Other income and (expense)	—			84			4			—		—			—			88
Total other income and (expense)	(5,189		)	(518		)	489			—		(67		)	(2		)	(5,287		)
Income (loss) from continuing operations before income taxes and non-controlling interest	(32,065		)	8,274			130			806		(433		)	(2		)	(23,290		)
Income tax benefit (expense)	—			229			(32		)	—		—			—			197
Net income attributable to non-controlling interest	—			(117		)	—			—		—			—			(117		)
Net income (loss) from continuing operations	(32,065		)	8,386			98			806		(433		)	(2		)	(23,210		)
Income from discontinued operations	—			—			—			—		1,480			—			1,480
Net income (loss)	$	(32,065	)	$	8,386		$	98		$	806	$	1,047		$	(2	)	$	(21,730	)

NOTE 15 — CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS

The Company and certain of its wholly-owned subsidiaries, Eagle Ford Hunter, Inc., Triad Hunter, LLC, NGAS Hunter, LLC, Williston Hunter ND, LLC, and Bakken Hunter, LLC (collectively, “Guarantor Subsidiaries”), may fully and unconditionally guarantee the obligations of the Company under any debt securities that it may issue pursuant to a universal shelf registration statement, on a joint and several basis, on Form S-3.  Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (the “Non Guarantor Subsidiaries”) as of June 30, 2012 and December 31, 2011, and for the three and six months ended June 30, 2012 and 2011, was as follows:

22

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Balance Sheets

(in thousands)

	As of June 30, 2012
											Magnum Hunter
	Magnum Hunter										Resources
	Resources		Guarantor		Non Guarantor						Corporation
	Corporation		Subsidiaries		Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets	$	28,884	$	38,592	$	33,649		$	—		$	101,125
Intercompany accounts receivable	842,765		—		—			(842,765		)	—
Property and equipment (using successful efforts accounting)	12,646		1,226,262		394,647			—			1,633,555
Investment in subsidiaries	487,353		—		—			(487,353		)	—
Other assets	18,110		7,930		44,816			—			70,856
Total Assets	$	1,389,758	$	1,272,784	$	473,112		$	(1,330,118	)	$	1,805,536
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	34,249	$	104,028	$	31,864		$	—		$	170,141
Intercompany accounts payable	—		458,211		384,554			(842,765		)	—
Long-term liabilities	552,498		92,681		81,396			—			726,575
Redeemable preferred stock	100,000		—		127,393			—			227,393
Shareholders’ equity	703,011		617,864		(152,095		)	(487,353		)	681,427
Total Liabilities and Stockholders’ Equity	$	1,389,758	$	1,272,784	$	473,112		$	(1,330,118	)	$	1,805,536

	As of December 31, 2011
										Magnum Hunter
	Magnum Hunter									Resources
	Resources		Guarantor		Non Guarantor					Corporation
	Corporation		Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets	$	25,401	$	39,927	$	12,341	$	—		$	77,669
Intercompany accounts receivable	602,773		—		—		(602,773		)	—
Property and equipment (using successful efforts accounting)	13,288		724,288		337,558		—			1,075,134
Investment in subsidiaries	244,500		—		126,655		(371,155		)	—
Other assets	9,152		3,838		2,967		—			15,957
Total Assets	$	895,114	$	768,053	$	479,521	$	(973,928	)	$	1,168,760
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	21,111	$	114,462	$	32,102	$	—		$	167,675
Intercompany accounts payable	—		241,339		361,434		(602,773		)	—
Long-term liabilities	253,319		93,925		63,189		—			410,433
Redeemable preferred stock	100,000		—		—		—			100,000
Shareholders’ equity	520,684		318,327		22,796		(371,155		)	490,652
Total Liabilities and Stockholders’ Equity	$	895,114	$	768,053	$	479,521	$	(973,928	)	$	1,168,760

23

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of Operations

(in thousands)

	For the Three Months Ended June 30, 2012
													Magnum Hunter
	Magnum Hunter												Resources
	Resources			Guarantor			Non Guarantor						Corporation
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	254		$	52,579		$	7,901		$	(434	)	$	60,300
Expenses	3,322			56,142			11,680			(434		)	70,710
Loss from continuing operations before equity in net income of subsidiary	(3,068		)	(3,563		)	(3,779		)	—			(10,410		)
Equity in net income of subsidiary	(6,757		)	—			—			6,757			—
Net income (loss) from continuing operations before income taxes and non-controlling interest	(9,825		)	(3,563		)	(3,779		)	6,757			(10,410		)
Income tax benefit	—			3,598			(597		)	—			3,001
Net income attributable to non-conrolling interest	—			—			(48		)	—			(48		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	(9,825		)	35			(4,424		)	6,757			(7,457		)
Income from discontinued operations	—			—			—			—			—
Gain on sale of discontinued operations	—			—			—			—			—
Net income (loss)	(9,825		)	35			(4,424		)	6,757			(7,457		)
Dividends on preferred stock	(4,790		)	—			(2,368		)	—			(7,158		)
Net income (loss) attributable to common shareholders	$	(14,615	)	$	35		$	(6,792	)	$	6,757		$	(14,615	)

	For the Three Months Ended June 30, 2011
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor		Non Guarantor						Corporation
	Corporation			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Revenues	$	319		$	21,747	$	8,019		$	(553	)	$	29,532
Expenses	22,412			17,352		6,692			(551		)	45,905
Loss from continuing operations before equity in net income of subsidiary	(22,093		)	4,395		1,327			(2		)	(16,373		)
Equity in net income of subsidiary	7,055			—		—			(7,055		)	—
Net income (loss) from continuing operations before income taxes and non-controlling interest	(15,038		)	4,395		1,327			(7,057		)	(16,373		)
Income tax benefit	—			—		197						197
Net income attributable to non-conrolling interest	—			—		(84		)	—			(84		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	(15,038		)	4,395		1,440			(7,057		)	(16,260		)
Income from discontinued operations	—			1,220		—			—			1,220
Net income (loss)	(15,038		)	5,615		1,440			(7,057		)	(15,040		)
Dividends on preferred stock	(3,457		)	—		—			—			(3,457		)
Net income (loss) attributable to common shareholders	$	(18,495	)	$	5,615	$	1,440		$	(7,057	)	$	(18,497	)

24

	For the Six Months Ended June 30, 2012
													Magnum Hunter
	Magnum Hunter												Resources
	Resources			Guarantor			Non Guarantor						Corporation
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	466		$	88,976		$	29,699		$	(1,645	)	$	117,496
Expenses	20,100			93,307			34,117			(1,645		)	145,879
Loss from continuing operations before equity in net income of subsidiary	(19,634		)	(4,331		)	(4,418		)	—			(28,383		)
Equity in net income of subsidiary	(2,649		)	—			—			2,649			—
Net income (loss) from continuing operations before income taxes and non-controlling interest	(22,283		)	(4,331		)	(4,418		)	2,649			(28,383		)
Income tax benefit	—			3,598			213			—			3,811
Net income attributable to non-conrolling interest	—			—			(22		)	—			(22		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	(22,283		)	(733		)	(4,227		)	2,649			(24,594		)
Income from discontinued operations	—			354			—			—			354
Gain on sale of discontinued operations	—			4,325			—			—			4,325
Net income (loss)	(22,283		)	3,946			(4,227		)	2,649			(19,915		)
Dividends on preferred stock	(9,384		)	—			(2,368		)	—			(11,752		)
Net income (loss) attributable to common shareholders	$	(31,667	)	$	3,946		$	(6,595	)	$	2,649		$	(31,667	)

	For the Six Months Ended June 30, 2011
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor		Non Guarantor						Corporation
	Corporation			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Revenues	$	615		$	33,862	$	11,096		$	(1,504	)	$	44,069
Expenses	32,882			25,713		10,267			(1,503		)	67,359
Loss from continuing operations before equity in net income of subsidiary	(32,267		)	8,149		829			(1		)	(23,290		)
Equity in net income of subsidiary	10,539			—		—			(10,539		)	—
Net income (loss) from continuing operations before income taxes and non-controlling interest	(21,728		)	8,149		829			(10,540		)	(23,290		)
Income tax benefit	—			—		197						197
Net income attributable to non-conrolling interest	—			—		(117		)	—			(117		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	(21,728		)	8,149		909			(10,540		)	(23,210		)
Income from discontinued operations	—			1,480		—			—			1,480
Net income (loss)	(21,728		)	9,629		909			(10,540		)	(21,730		)
Dividends on preferred stock	(6,065		)	—		—			—			(6,065		)
Net income (loss) attributable to common shareholders	$	(27,793	)	$	9,629	$	909		$	(10,540	)	$	(27,795	)

25

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of Cash Flows
(in thousands)

	For the Six Months Ended June 30, 2012
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor			Non Guarantor					Corporation
	Corporation			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Cash flow from operating activities	$	(478,941	)	$	551,288		$	(23,682	)	$	—	$	48,665
Cash flow from investing activities	(361		)	(550,926		)	(107,433		)	—		(658,720		)
Cash flow from financing activities	475,668			(1,864		)	146,195			—		619,999
Effect of exchange rate changes on cash	—			—			(33		)	—		(33		)
Net increase (decrease) in cash	(3,634		)	(1,502		)	15,047			—		9,911
Cash at beginning of period	18,758			(6,573		)	2,666			—		14,851
Cash at end of period	$	15,124		$	(8,075	)	$	17,713		$	—	$	24,762

	For the Six Months Ended June 30, 2011
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor			Non Guarantor					Corporation
	Corporation			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Cash flow from operating activities	$	(109,839	)	$	87,677		$	32,120		$	—	$	9,958
Cash flow from investing activities	(94,296		)	(88,113		)	(31,580		)	—		(213,989		)
Cash flow from financing activities	208,397			124			(297		)	—		208,224
Effect of exchange rate changes on cash	—			—			3			—		3
Net decrease in cash	4,262			(312		)	246			—		4,196
Cash at beginning of period	1,556			(1,094		)	92			—		554
Cash at end of period	$	5,818		$	(1,406	)	$	338		$	—	$	4,750

26

NOTE 16 — INTANGIBLE ASSETS

Intangible assets consist primarily of the assigned fair value associated with the acquired gas gathering and processing contracts and customer relationships in the TransTex Gas Services, LP acquisition.

The following table summarizes our intangible assets:

	June 30,			December 31,
	2012			2011
Intangible Assets	$	—		$	—
Additions	10,492			—
Total intangible assets	$	10,492		$	—
Accumulated amortization	(491		)	—
Intangible Assets, net	$	10,001		$	—

NOTE 17 — SUBSEQUENT EVENTS

We sold an additional 348,645 shares of our Series D Cumulative Perpetual Preferred Stock at prices ranging from $43.80 per share to $45.06 per share for net proceeds of approximately $15.1 million, pursuant to our ATM sales agreement subsequent to June 30, 2012, through the date of this report.  There are a total of 2,894,952 shares of Series D Preferred Stock outstanding as of the date of this report.

On August 8, 2012, the Company entered into the Ninth Amendment to the Second Amended and Restated Credit Facility. The amendment increased the Company’s borrowing base by $47.5 million, from $212.5 million to $260.0 million.  The amendment also allows for the maximum borrowings under the Senior Notes to be raised $550.0 million, and it allows the total dividends paid to holders of Series C and Series D preferred stock to be raised to $25.0 million in a calendar year.

27

Item 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our financial condition. This section should be read in conjunction with management’s discussion and analysis contained in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011, filed with the Securities and Exchange Commission (“SEC”).  Our consolidated financial statements and the accompanying notes included elsewhere in this Quarterly Report on Form 10-Q contain additional information that should be referred to when reviewing this material.  Certain statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed in this report.  A glossary containing the meaning of the oil and gas industry terms used in this management’s discussion and analysis follows the “Results of Operations” table in this Item 2.

Cautionary Statements Regarding Forward-looking Statements

Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements.  The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future reserves, production, revenues, income and capital spending.  When we use the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project” or their negatives, other similar expressions or the statements that include those words, it usually is a forward-looking statement.

The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management.  These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors.  Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control.  In addition, management’s assumptions about future events may prove to be inaccurate.  We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur.  Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors detailed below and discussed in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011, and subsequent filings.  All forward-looking statements speak only as of the date of this report.  We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise.  These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

·global economic and financial market conditions,

·our business strategy,

·estimated quantities of oil and gas reserves,

·uncertainty of commodity prices in oil and gas,

·disruption of credit and capital markets,

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·our financial position,

·our cash flow and liquidity,

·replacing our oil and gas reserves,

·our inability to retain and attract key personnel,

·uncertainty regarding our future operating results,

·uncertainties in exploring for and producing oil and gas,

·high costs, shortages, delivery delays or unavailability of drilling rigs, equipment, labor or other services,

·disruptions to, capacity constraints in or other limitations on the pipeline systems which deliver our gas and other processing and transportation considerations,

·our inability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations,

·competition in the oil and gas industry,

·marketing of oil, gas and natural gas liquids,

·exploitation of our current asset base or property acquisitions,

·the effects of government regulation and permitting and other legal requirements,

·plans, objectives, expectations and intentions contained in this report that are not historical, and

·other factors discussed in our 2011 Annual Report on Form 10-K, as amended, for the year ended December 31, 2011,  and subsequent filings, including this Quarterly Report on Form 10-Q.

General and Business Overview

We are an independent oil and gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids, primarily in the states of West Virginia, Ohio, Texas, Kentucky and North Dakota and in Saskatchewan, Canada.  We are also engaged in midstream operations involving the gathering of natural gas through our ownership and operation of a gas gathering system in West Virginia and Ohio, referred to as our Eureka Hunter Pipeline System. We are presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus/Utica Shales in West Virginia and Ohio, the Eagle Ford Shale in south Texas and the Williston Basin/Bakken Shale in North Dakota and Saskatchewan, Canada.

Our business strategy is to exploit our inventory of lower risk drilling locations and acquire undeveloped leases and long-lived proved reserves with significant exploitation and development opportunities primarily located in unconventional resource plays.  Over the past three years, we have substantially increased our assets and production base through a combination of acquisitions, joint ventures and ongoing development drilling efforts; our percentage of operated properties has increased significantly; our inventory of acreage and drilling locations in resource plays has grown dramatically; and our management team has been expanded.  We are focused on the further development and exploitation of our core unconventional resource plays, the acquisition of additional operated properties in our core operating regions, and selective expansion of our midstream operations.

29

Recent Events

Fifth Amendment to Second Amended and Restated Credit Agreement and Second Amendment to Second Lien Credit Agreement

On February 14, 2012, the Company entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement, as amended. Pursuant to the Fifth Amendment, the Company’s borrowing base was increased to $235 million from $200 million.

On February 14, 2012, the Company entered into the Second Amendment to the Second Lien Term Loan Credit Agreement.  The Second Amendment amends certain provisions of the Second Lien Term Loan Credit Agreement to correspond to the amendments made pursuant to the Fifth Amendment to the Second Amended and Restated Credit Agreement.

Sixth Amendment to Second Amended and Restated Credit Agreement and Seventh Amendment to Second Amended and Restated Credit Agreement

On May 2, 2012, the Company entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement, as amended.  Pursuant to the sixth amendment to the credit facility, our borrowing base under our senior revolving credit agreement was increased from $235.0 million to $275.0 million, then pursuant to the issuance of the $450.0 million 9.75% Senior Notes the borrowing base was decreased from $275.0 million to $187.5 million, then pursuant to the closing of the Baytex Acquisition the borrowing base was increased from $187.5 million to $212.5 million.  The Seventh Amendment to the Second Amended and Restated Credit Agreement reduced the current ratio covenant to 0.85 to 1.1 for June 30, 2012 which increased to 1.0 with the aforementioned bond transaction.

Third Amendment to Second Lien Term Loan Agreement

On June 29, 2012, Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline”), entered into a Limited Waiver and Third Amendment to Second Lien Term Loan Agreement.  The Third Amendment amends the Second Lien Term Loan Agreement by reducing the minimum Interest Coverage Ratio (as such term is defined in the Second Lien Term Loan Agreement) to 0.85:1.00 for the fiscal quarters ending September 30, 2012 and December 31, 2012, and by increasing the maximum Total Leverage Ratio (as such term is defined in the Second Lien Term Loan Agreement) to 9.50:1.00 and 8.5:1.00 for the fiscal quarters ending September 30, 2012 and December 31, 2012, respectively. The lenders under the Second Lien Term Loan Agreement also agreed to waive any events of default occurring as a result of Eureka Hunter Pipeline’s failure to comply with such ratios during the fiscal quarter ended June 30, 2012. Finally, the Third Amendment modified the interest rate provisions in the Second Lien Term Loan Agreement so that after June 29, 2012 all interest shall be payable in cash.  The reduced minimum Interest Coverage Ratio shall increase back to 1.00:1.00, and the increased maximum Total Leverage Ratio shall decrease back to 6:50:1:00, if Eureka Hunter Pipeline receives funding prior to December 31, 2012 under its First Lien Credit Agreement with SunTrust Bank, unless such credit agreement is amended in a manner satisfactory to PennantPark.

We sold an additional 348,645 shares of our Series D Cumulative Perpetual Preferred Stock at prices ranging from $43.80 per share to $45.06 per share for net proceeds of approximately $15.1 million, pursuant to our ATM sales agreement subsequent to June 30, 2012, through the date of this report.  There are a total of 2,894,952 shares of Series D Preferred Stock outstanding as of the date of this report.

On August 8, 2012, the Company entered into the Ninth Amendment to the Second Amended and Restated Credit Facility. The amendment increased the Company’s borrowing base by $47.5 million, from $212.5 million to $260.0 million.

Utica Shale Acquisition

On February 17, 2012, Triad Hunter, LLC, a wholly-owned subsidiary of the Company, closed on an acquisition of leasehold mineral interests located predominantly in Noble County, Ohio referred to as the Utica Acreage, for a total purchase price of $24.8 million.  The Utica Acreage consists of approximately 15,558 gross (12,186 net) acres predominantly located in Noble County, Ohio.  The net price paid per acre for this acquisition was $2,037.

The Utica Acreage is in close proximity to Triad Hunter’s existing acreage position in Washington and Noble Counties, Ohio, and now provides Triad Hunter approximately 18,187 gross (14,815 net) acres in in these two counties, and a total of 61,151 net acres that are presently prospective for the Utica Shale.

Sale of Hunter Disposal, LLC

On February 17, 2012, the Company, through its wholly owned subsidiary, Triad Hunter, LLC, closed on the sale of 100% of the equity ownership interest of Hunter Disposal, LLC.  The sale was made to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Energy, Inc., an entity for which Mr. Evans is a director, an officer and major shareholder and for which Ronald Ormand, our Chief Financial Officer and a director, is also a director.  The terms and conditions of the equity purchase agreement between the parties were approved by the audit committee or an independent special committee for each party.  The total sales price for this acquisition was approximately $9.9 million ($8.5 million after adjustments for working capital since the effective date of December 31, 2011).  The consideration received included a combination of cash, GreenHunter Energy restricted common stock, GreenHunter Energy 10% cumulative preferred stock, and a promissory note due to the Seller.  In connection with the sale, Triad Hunter entered into agreements with Hunter Disposal, LLC and GreenHunter Water, LLC for future wastewater hauling and disposal capacity in Kentucky, Ohio and West Virginia and a five-year tank rental agreement with GreenHunter Water, LLC.

Series A Convertible Preferred Unit Purchase Agreement

On March 21, 2012, Eureka Hunter Holdings, LLC, a Delaware limited liability company (“Eureka Hunter Holdings”), entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with Company and Ridgeline Midstream Holdings, LLC (“Ridgeline”), a Delaware

30

limited liability company and an affiliate of ArcLight Capital Partners, LLC. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of Series A Convertible Preferred Units representing membership interests of Eureka Hunter Holdings (the “Preferred Units”).  Eureka Hunter Holdings is a majority-owned subsidiary of Magnum Hunter and the holding company for Magnum Hunter’s midstream operations, including its existing pipeline operation in West Virginia and Ohio conducted through Eureka Hunter Pipeline, LLC, a subsidiary of Eureka Holdings (“Eureka Hunter Pipeline”), and the below-described gas treating business and assets acquired (the “TransTex Acquisition”) by a wholly owned subsidiary of Magnum Hunter and Eureka Hunter Holdings from TransTex Gas Services LP, a Delaware limited partnership (“TransTex”) on April 2, 2012.

Contemporaneous with the execution of the Unit Purchase Agreement, Ridgeline purchased 3,000,000 Preferred Units for the aggregate purchase price of $60 million, the net proceeds of which were used to fund a special one-time distribution by Eureka Hunter Holdings to Magnum Hunter to reimburse it for certain prior capital expenditures incurred by Magnum Hunter with respect to the assets of Eureka Hunter Pipeline and Eureka Hunter Land, LLC, a Delaware limited liability company and wholly owned subsidiary of Eureka Pipeline.  Upon consummation of Ridgeline’s $60 million initial investment, Eureka Hunter Holdings was owned 83.4% by Magnum Hunter, all in the form of Class A Common Units (the “Common Units”), and 16.6% by Ridgeline, all in the form of Preferred Units (on an as-converted basis).  Further, Ridgeline purchased an additional 2,340,000 Preferred Units for the aggregate purchase price of $46.8 million upon consummation of the TransTex Acquisition, which closed on April 2, 2012.  The net proceeds from this investment by Ridgeline were used to fund a distribution by Eureka Holdings to Magnum Hunter to reimburse it for certain capital expenditures with respect to the assets acquired for cash in the TransTex Acquisition.  The remaining capital commitment would be $93.2 million, which, subject to Eureka Hunter Holdings requesting funds and the satisfaction of certain conditions, may be funded over the course of the two years following the closing of the TransTex Acquisition.  The remainder of the $200 million commitment from Ridgeline is required to be used for the development of Eureka Hunter Holdings’ midstream operations.  Upon Ridgeline’s funding in connection with the TransTex Acquisition, its ownership position in Eureka Hunter Holdings represents, on an as-converted basis, approximately 25.4% of the ownership interest in Eureka Hunter Holdings with Magnum Hunter and TransTex owning 71.8% and 2.8% of Eureka Hunter Holdings, respectively, all in the form of Class A Common Units and some additional common units were purchased by individual TransTex partners, including Gary Evans, the Chairman and Chief Executive Officer of Magnum Hunter.

On June 20, 2012, Ridgeline invested an additional $25.0 million in 1,250,000 Series A Preferred Units of Eureka Hunter Holdings.

Acquisition of Williston Basin Properties

On March 30, 2012, the Company, through its wholly owned subsidiary, Williston Hunter ND a Delaware limited liability company, closed on the purchase of certain assets of Eagle Operating, Inc. (“Eagle”), effective April 1, 2011.  Total consideration was $52.9 million consisting of $51.0 million in cash and 296,859 shares of Magnum Hunter restricted common stock valued at $1.9 million based on a price of $6.41 per share.

Baytex Asset Acquisition

On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC (“Bakken Hunter”), closed on the acquisition of certain Bakken/Three Forks Sanish properties located in the Williston Basin of North Dakota from Baytex Energy USA Ltd., a subsidiary of Baytex Energy Corp. for $312.0 million, as adjusted for certain customary adjustments.

The purchase agreement provides that the effective date of the purchase of the assets is March 1, 2012, and all proceeds and certain costs and expenses attributable to the assets acquired shall be apportioned between Baytex and Bakken Hunter according to such date.  Property expenses relating to the assets acquired, including capital expenditures for new wells, paid by Baytex that are attributable to the period after the effective date, and Baytex’s costs for assignments to it of properties pursuant to an election made by it after the effective date under the area of mutual interest provision in the Operating Agreement, which properties will become part of the assets acquired, shall be apportioned to Bakken Hunter.  Bakken Hunter assumed obligations accruing after the closing date under certain agreements relating to the assets, and certain environmental liabilities, subject to the pre-closing environmental defect mechanism in the purchase agreement.

Private Placement

On May 16, 2012, the Company successfully completed the issuance and sale of $450,000,000 aggregate principal amount of its 9.75% Senior Notes due 2020 (the “Senior Notes”).  The Senior Notes are unsecured and are fully and unconditionally guaranteed (the “Guarantees”), jointly and severally, on a senior unsecured basis by certain of the Company’s domestic subsidiaries, and may be guaranteed by certain future domestic subsidiaries of the Company.  The Senior Notes and the Guarantees were offered and sold inside the United States to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933, as amended (the (“Securities Act”), and outside the United States to non-U.S. persons in reliance on Regulation S under the Securities Act.  The Senior

31

Notes and the guarantees have not been registered under the Securities Act or applicable state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state laws.

The Senior Notes were issued at a price of 98.646% of their face amount and will provide net proceeds to the Company, after fees and expenses, of $444.0 million.  The Company is using the net proceeds of this offering, together with other sources of liquidity, (i) to finance a portion of the $312.0 million acquisition of oil properties in the Williston Basin from Baytex, which closed on May 22, 2012, (ii) to pay off all amounts outstanding under the Company’s existing Term Loan, (iii) to repay outstanding debt under the Company’s Revolving Credit Facility, (iv) to increase the Company’s 2012 upstream capital budget from $150 million to $325 million (92% of capital budget focused on Williston Basin and Eagle Ford) and (v) for general corporate purposes.

The Senior Notes were issued pursuant to an indenture entered into on May 16, 2012 among the Company, the guarantors, Wilmington Trust, National Association, as the Trustee, and Citibank, N.A., as the Paying Agent, Registrar and Authenticating Agent.  The terms of the Senior Notes are governed by the Indenture, which contains affirmative and negative covenants that, among other things, limit the Company’s and the guarantors’ ability to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness or make certain other restricted payments; transfer or sell assets; make loans and other investments; create or permit to exist certain liens; enter into agreements that restrict dividends or other payments or other payments or distributions from restricted subsidiaries to the Company; consolidate merge or transfer all or substantially all of their assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

The Senior Notes will mature on May 15, 2020, and interest on the Senior Notes will be paid semi-annually in arrears on May 15 and November 15 of each year, commencing on November 15, 2012.

The indenture also contains customary events of default.  Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the Senior Notes.  Upon the occurrence of certain other events of default, the trustee of the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

The Senior Notes are redeemable by the Company at any time on or after May 15, 2016, at the redemption prices set forth in the indenture. The Senior Notes are redeemable by the Company prior to May 15, 2016, at the redemption prices plus a “make-whole” premium set forth in the indenture. The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before May 15, 2015 with net proceeds that the Company raises in equity offerings at a redemption price set forth in the indenture, so long as at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture (excluding Senior Notes held by the Company) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.  If the Company experiences certain change of control events, each holder of Senior Notes may require the Company to repurchase all or a portion of the Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued and unpaid interest up to, but not including the date of repurchase.

Common Stock Offering

On May 16, 2012, the Company closed its underwritten public offering of 35,000,000 shares of its common stock, par value $0.01 per share (“the common stock”) at a price of $4.50 per share.  The net proceeds of the offering, after deducting underwriting discounts and commissions and estimated offering expenses, were approximately $148.7 million.

Equity Financings.  In addition to the $148.7 million in net proceeds from our offering of common stock, we have raised substantial cash in the total amount of $194.9 million in gross proceeds through equity transactions in 2012 through August 8, 2012.  Those transactions included:

·$1.2 million in net proceeds from the exercise of warrants and common stock options for 2012 through August 8, 2012;

·$66.3 million in net proceeds from the issuance of our 8.0% Series D Preferred Stock for 2012 through August 8, 2012; and

·$127.4 million in net proceeds from the sale of 5,340,000 Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC, through August 8, 2012.

We plan to continue raising both preferred and common equity in the future depending on our capital expenditures program and market conditions.

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Results of Operations

The following table sets forth summary information regarding oil, natural gas, and NGLs, revenues, production, average product prices and average production costs and expenses for the three and six months ended June 30, 2012, and 2011, respectively.  See a glossary of terms used below the table.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Oil and gas revenue and production	2012		2011		2012		2011
Revenues (in thousands)
Oil – US	$	35,300	$	16,437	$	61,760	$	26,780
Oil – Canada	7,357		866		16,295		866
Gas – US	9,297		7,516		23,086		11,135
Gas – Canada	114		184		224		184
NGLs – US	1,612		1,037		3,482		1,036
NGLs – Canada	2		6		7		6
Total oil and gas sales	$	53,682	$	26,046	$	104,854	$	40,007
Production
Oil (mbbls) – US	398		170		668		290
Oil (mbbls) – Canada	92		9		186		9
Gas (mmcfs) – US	3,828		1,413		8,225		2,116
Gas (mmcfs) – Canada	60		55		125		55
NGL (mboe) – US	44		26		85		26
NGL (mboe) – Canada	—		—		—		—
Total (mboe)		1,182		450		2,330		687
Total (boe/d)	12,984		4,947		12,804		3,795
Average prices
Oil (per bbl) – US	$	88.71	$	96.56	$	92.55	$	92.45
Oil (per bbl) – Canada	80.49		93.79		87.38		93.79
Gas (per mcf) – US	2.43		5.32		2.81		5.26
Gas (per mcf) –Canada	1.89		3.35		1.80		3.35
NGL (per boe) – US	36.63		39.91		41.12		39.91
NGL (per boe) – Canada	20.79		36.81		28.84		36.81
Total average price (per boe)	$	45.43	$	57.85	$	44.99	$	58.25
Costs and expenses (per boe)
Lease operating expense	$	10.14	$	14.58	$	9.97	$	13.92
Severance tax and marketing	3.23		4.00		3.23		4.07
Exploration expense	0.33		0.80		0.31		0.98
General and administrative expense (see Footnote 1 below)	10.66		52.51		11.93		44.29
Depletion, depreciation and accretion	25.38		23.84		24.34		23.59
Midstream and oilfield service segments (in thousands)
Oilfield services segment revenue	$	1,391	$	1,773	$	5,984	$	2,717
Midstream operations segment revenue	4,213		1,783		5,377		2,084
Oilfield services segment expense	1,550		1,760		4,148		3,083
Midstream operations segment expense	3,466		634		4,366		1,278

(1)  General and administrative expense includes:

(i) acquisition related expenses of $1.8 million for the three months in 2012 ($1.56 per boe) and $6.1 million ($13.54 per boe) for the three months in 2011,

(ii) acquisition related expenses of $2.6 million ($1.10 per boe) for the six months in 2012 and $7.8 million ($11.40 per boe) for the six months in 2011,

(iii) non-cash stock compensation of $4.0 million ($3.45 per boe) for the three months in 2012 and $10.6 million ($23.61 per boe) for the three months in 2011, and

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(iv) non-cash stock compensation of $8.7 million ($3.73 per boe) for the six months in 2012 and $12.0 million ($17.49 per boe) for the six months in 2011.

Glossary of terms used:

Bbl.  One stock tank barrel, of 42 US gallons liquid volume, used herein to reference oil or condensate.

MBbl.  Thousand barrels of oil or condensate.

Mcf.  Thousand cubic feet of natural gas.

MMBtu.  Million British thermal units.

MGal.  Thousand gallons of natural gas liquids.

MMcf.  Million cubic feet of natural gas.

Boe.  Barrels of oil equivalent, converts at rate of six Mcf equals one Boe and forty-two gallons of natural gas liquids equals one Boe.

MBoe.  Thousand barrels of oil equivalent.

/d.  “Per day” when used with volumetric units or dollars.

Three Months Ending June 30, 2012 and 2011

Oil and gas production.  Oil and gas production increased 162% to 1,182 MBoe for the three months ended June 30, 2012, from 450 MBoe for the three months ended June 30, 2011.  Production for the 2012 period was approximately 45% oil and 55% natural gas compared to 46% oil and 54% natural gas for the 2011 period, and 35% oil and 65% natural gas for the first quarter of 2012.  Our average daily production on a Boe basis increased 162% to 12,984 Boe per day for the 2012 period compared to 4,947 Boe per day for the 2011 period.  Our oil production increased by 34%, or 125 MBoe, during the second quarter of 2012 compared to the first quarter of 2012 as a result of the Company’s shift in its capital expenditures program toward oil and liquids and as a result of the Baytex acquisition.  The increase in production is primarily attributable to organic growth of the Company through the ongoing drilling program in its unconventional resource plays as well as the acquisitions done by the Company in the Williston Basin area during May of 2012.

US Upstream segment.  Production increased in the US Upstream operating segment by 150%, to 1,080 Mboe, for the three months ended June 30, 2012 from 432 Mboe for the three months ended June 30, 2011.  Production for 2012 during the second quarter on a Boe basis was 41% oil and 59% natural gas compared to 45% oil and 55% natural gas for the second quarter of 2011.  Our average daily production increased by 150% to 11,868 Boepd during 2012 period compared to 4,743 Boepd for 2011.  This increase in production for the US Upstream segment in 2012 compared to 2011 is primarily attributable to organic growth of the Company through the ongoing drilling program in the Eagle Ford Shale and Williston Basin as well as the acquisitions done by the Company in the Williston Basin area during May of 2012.

Canadian Upstream segment — Williston Basin/Bakken/Three Forks Sanish/Madison.  Production increased from the Canadian Upstream operating segment 447%, to 102 Mboe, for the three months ended June 30, 2012 from 19 Mboe for the three months ended June 30, 2011.  Production for the 2012 period on a Boe basis was 90% oil and 10% natural gas compared to 51% oil and 49% natural gas for the 2011 period.  Our average daily production increased by 447% to 1,116 Boepd during the second quarter of 2012 compared to 204 Boepd for 2011.  This increase in production for the Canadian Upstream segment in 2012 compared to 2011 is primarily attributable to organic growth through the Company’s ongoing drilling programs in the Tableland Field as well as the inclusion of a full three months of production in the current year compared to two months during 2011.

Oil and gas sales.  Oil and gas sales increased $27.6 million, or 106%, for the three months ended June 30, 2012, to $53.7 million from $26.0 million for the three months ended June 30, 2011.  The increase in oil and gas sales principally resulted from increased production as described above.  The average price we received for our oil production decreased $9.24 per barrel (10%) to $87.17 per barrel, while the average price received for gas production decreased $2.83 per Mcf (54%) to $2.42 per Mcf.  Our average price for gas decreased due to market trends in the price for natural gas.  Of the $27.6 million increase in oil and gas sales, approximately ($5.2  million), or (19%), was attributable to a decrease in price per Boe of $12.42, while approximately $32.8 million, or 119% of the increase in oil and gas sales was attributable to the increase in production volumes.  The prices we receive for our products are generally tied to commodity index prices.  We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices.  (See the discussion of commodity derivative activities in Note 7 to our condensed consolidated financial statements.)

Field operations revenues.  Field operations revenues include the revenues from the Company’s oilfield services segment and midstream segment.  These revenues increased by 255%, or $4.7 million, for the three months ended June 30, 2012 to $6.5

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million from $1.8 million for the three months ended June 30, 2011.  This increase is primarily due to a higher volume of activity in our midstream segment as discussed below.

Oilfield services revenue.  Oilfield services revenue decreased by 22%, or $382,000, for the three months ended June 30, 2012 to $1.4 million from $1.8 million for the three months ended June 30, 2011.  Oilfield services revenues for the three months ended June 30, 2012 were primarily drilling services.

Midstream operations revenue.  Revenue from the Eureka Hunter midstream segment increased by $2.4 million, or 135%, for the three months ended June 30, 2012, to $4.2 million from $1.8 million for the three months ended June 30, 2011.  The increase in revenues resulted from the increased volume of natural gas products gathered by the pipeline network and gathering system,  as well as revenue of $2.3 million related to its gas treating equipment and earned $733,000 of gas marketing revenue.

Other revenues.  We recorded a gain on sale of assets of $100,000 for the three months ended June 30, 2012, from the sale of equipment out of the Appalachian region of upstream operations. We also recorded $19,000 of other revenues during the three months ended June 30, 2012.

Lease operating expense.  Our lease operating expenses increased $5.4 million, or 83%, for the three months ended June 30, 2012, to $12.0 million ($10.14 per Boe) from $6.6 million ($14.58 per Boe) for the three months ended June 30, 2011.  The decline in operating expense per Boe is due to the effect of adding new production, principally in the Eagle Ford Shale and Williston Basin, at lower cost per unit produced when compared to the per unit operating cost in our older, legacy fields.

Severance taxes and marketing.  Our severance taxes increased $2.0 million, or 115%, for the three months ended June 30, 2012, to $3.8 million from $1.8 million for the three months ended June 30, 2011.  The increase in severance taxes was attributable to the increase in oil and gas production.  Marketing expenses decreased by $18,000, or 54%, for the three months ended June 30, 2012, to $15,000 from $33,000 for the three months ended June 30, 2011, due to expenses incurred by our midstream segment related to contracts for marketing gas for third party producers.

Exploration.  We incurred $385,000 of exploration expense for the three months ended June 30, 2012, compared to $358,000 for the three months ended June 30, 2011.  The increase was caused by the high amount of expense incurred due to the acquisitions done in the Williston Basin during the three months ended June 30, 2012.

Impairment of oil and gas properties.We provided for an impairment to the carrying value of approximately $9.0 million which consisted of $5.4 million of our North Dakota unproved oil and gas properties and $3.6 million of our Canadian unproved oil and gas properties which expired undrilled prior to June 30, 2012.

Field operations expenses.  Field operating expense increased by $2.5 million for the three months ended June 30, 2012, or 111%.  This increase is primarily caused by the increase in oilfield service expense and midstream operations discussed below.

Oilfield services expenses.  Oilfield services expenses decreased by 12%, or $210,000, for the three months ended June 30, 2012 to $1.6 million from $1.8 million for the three months ended June 30, 2011.  Oilfield services expenses for the three months ended comprise expenses incurred in drilling operations.

Midstream operations expenses.  Expenses incurred by Eureka Hunter Holdings increased by 447%, or approximately $2.8 million, to $3.5 million for the three months ended June 30, 2012 from $634,000 for the three months ended June 30, 2011.  The increase is primarily due to the increase in pipeline activities being managed by Eureka Hunter Holdings compared to the prior year as well as gas treating expenses incurred by TransTex Hunter.

Depletion, depreciation and accretion.  Our depletion, depreciation and accretion expense (“DD&A”)  increased $19.2 million, or 179%, to $30.0 million for the three months ended June 30, 2012, from $10.7 million for the three months ended June 30, 2011 due to increased production in the 2012 period described above.  Our DD&A per Boe increased by $1.54, or 6%, to $25.38 per Boe for the three months ended June 30, 2012, compared to $23.84 per Boe for the three months ended June 30, 2011.  The increase in DD&A per Boe was primarily attributable to the higher cost to drill and equip our new Eagle Ford, Marcellus, and Bakken Shale wells, which require horizontal drilling and more expensive completion techniques than traditional, vertically-drilled wells.

General and administrative.  Our general and administrative expenses (“G&A”) decreased $11.0 million, or 47%, to $12.6 million ($10.66 per Boe) for the three months ended June 30, 2012, from $23.6 million ($52.51 per Boe) for the three months ended June 30, 2011.  G&A decreased overall during the 2012 period primarily due to decreases in share based compensation expense and consulting expense of the Company from the second quarter of 2011 through the second quarter of 2012.  Non-cash stock compensation totaled approximately $4.1 million ($3.45 per Boe) and $10.6 million ($23.61 per Boe) for the three months ended June

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30, 2012 and 2011, respectively.  The three months ended June 30, 2012 also included transaction costs of $1.8 million ($1.56 per Boe) related to the acquisitions of assets in the North Dakota region done in the three months ended June 30, 2012.  The three months ended June 30, 2011, included acquisition related costs of approximately $6.1 million ($13.54 per Boe) which were for legal, consulting and other costs related to the acquisition of NGAS and NuLoch which closed in April and May of 2011, respectively.  We expect overall G&A costs to increase in the aggregate in 2012, but to continue to decline on a Boe basis due to the ongoing expansion activities of the Company.

Interest expense, net.  Our interest expense, net of interest income, increased approximately $16.0 million, or 407% to $19.9 million for the three months ended June 30, 2012, from $3.9 million for the three months ended June 30, 2011.  This increase was the result of our higher average debt level during 2012 as well as fees and amortization of $9.4 million in the 2012 period.  For the three months ended June 30, 2012, interest expense included $4.2 million in fees related to the bridge loan and $5.2 million in accelerated amortization recorded as a result of the reduction of the borrowing base of the Senior Credit Facility and the termination of the term loan.  All of these charges were incurred as a result of the refinancing effected through our the Senior Notes offering.  During the three months ended June 30, 2011, we incurred a $2.3 million non-cash write off of the unamortized balance of deferred financing fees upon entering into the Senior Credit Facility in April of 2011.

Commodity derivative activities.  Realized gains and losses from our commodity derivative activity increased our earnings by approximately $4.3 million and decreased our earnings by approximately $517,000 for the three months ended June 30, 2012 and 2011, respectively.  Realized gains and losses are derived from the relative movement of oil and gas prices on the products we sell in relation to the range of prices in our derivative contracts for the respective three month periods.  The unrealized gain on commodity derivatives was approximately $17.6 million for the 2012 period and $3.2 million for the 2011 period.  As commodity prices increase, the fair value of the open portion of those positions decreases.  As commodity prices decrease, the fair value of the open portion of those positions increases.  Historically, we have not designated our derivative instruments as cash-flow hedges.  We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives.  We record all changes in realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts.”  Our gain or loss from realized and unrealized derivative contracts was a gain of approximately $21.9 million and approximately $2.7 million for the three months ended June 30, 2012 and 2011, respectively.  (See Note 7 to our condensed consolidated financial statements for more information.)

Income tax benefit.  The Company recorded an income tax benefit of $3.0 million for the three months ended June 30, 2012, to reflect the change in the deferred tax liability of the Company’s Williston Hunter and Magnum Hunter Production subsidiaries.

Net income (loss) attributable to non-controlling interest.  Net loss attributable to non-controlling interest was approximately $48,000 for the three months ended June 30, 2012 versus a net gain of $84,000 for same period in 2011.  This represents 12.5% of the gain or loss incurred by our subsidiary, PRC Williston, LLC.  We record a non-controlling interest in the results of operations of this subsidiary because we are contractually obligated to make distributions to the holders of this interest whenever we make distributions to ourselves from the subsidiary company.

Loss from Continuing Operations.  We had a loss from continuing operations of $7.5 million for the 2012 period versus a loss of $16.3 million for the 2011 period, a decrease of $8.8 million, or 54%.  This was due to the $30.8 million increase in revenues offset by a $5.4 million increase in lease operating expense, a $2.0 million increase in severance taxes and marketing, an unproved property impairment charge of $9.0 million, a decrease in G&A of $11.0 million, an increase in field operations expense of $2.5 million, an increase in DD&A of $19.3 million, and increase in interest expense of $16.0 million, and an increase in gain on fair value of derivatives of $19.2 million.

Income from Discontinued Operations.  On February 17, 2012, we closed on a sale of Hunter Disposal, LLC, previously a wholly owned subsidiary.  We have reclassified $1.2 million of net operating income (net of interest expense) of the divested subsidiary to discontinued operations for the three month period ended June 30, 2011.

Dividends on Preferred Stock.  Total dividends on our Series C and Series D Preferred Stock were approximately $7.2 million for the three months ended June 30, 2012.  Dividends were $3.5 million for the three months ended June 30, 2011.  The Series C Preferred Stock had a stated value of $100 million at both June 30, 2012 and 2011 and carries a cumulative dividend rate of 10.25% per annum.  The Series D Preferred Stock had a stated value of $127.3 million and $64.9 million at June 30, 2012 and 2011, respectively and carries a cumulative dividend rate of 8.0% per annum.  The Series A Preferred Units of Eureka Hunter Holdings had a stated value of $127.4 million and $0 at June 30, 2012 and 2011, respectively, and carry a dividend rate of 8% per annum.

Net Loss attributable to Common Shareholders.  Net loss attributable to common shareholders was $14.6 million in the 2012 period versus $18.5 million in the 2011 period.  Our net loss per common share, basic and diluted was $0.10 per share for the three months ended June 30, 2012, compared to net loss of $0.16 per share for the 2011 period.  Our weighted average shares outstanding increased by approximately 38.8 million shares, or 34%, from 112,619,793 shares in the 2011 period to

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151,464,372 during the 2012 period.  Our net loss per share from continuing operations was $0.10 per share for the three months ended June 30, 2012, versus a net loss of $0.16 per share for the 2011 period.  We had income from discontinued operations of $1.2 million ($0.01 per share) in the 2011 period from Hunter Disposal, LLC.

Six Months Ending June 30, 2012 and 2011

Oil and gas production.  Oil and gas production increased 239% to 2,330 MBoe for the six months ended June 30, 2012, from 687 MBoe for the six months ended June 30, 2011.  Production for the 2012 period was approximately 40% oil and 60% natural gas compared to 47% oil and 53% natural gas for the 2011 period.  Our average daily production on a Boe basis increased 237% to 12,804 Boe per day for the 2012 period compared to 3,795 Boe per day for the 2011 period.  The increase in production is primarily attributable to organic growth from the success of the Company’s ongoing drilling program as well as the acquisitions done by the Company in the Williston Basin area during May of 2012.

US Upstream segment.  Production increased in the US Upstream operating segment by 218%, to 2,123 Mboe, for the six months ended June 30, 2012 from 668 Mboe for the six months ended June 30, 2011.  Production for 2012 on a Boe basis was 35% oil and NGLs and 65% natural gas compared to 47% oil and 53% natural gas for 2011.  Our average daily production increased by 216% to 11,664 Boepd during 2012 compared to 3,692 Boepd for 2011.  The increase in production is primarily attributable to organic growth from the success of the Company’s ongoing drilling program as well as the acquisitions done by the Company in the Williston Basin area during May of 2012.

Canadian Upstream segment — Williston Basin/Bakken/Three Forks Sanish/Madison.  Production increased from the Canadian Upstream operating segment 1,017%, to 207 Mboe, for the six months ended June 30, 2012 from 19 Mboe for the six months ended June 30, 2011.  Production for 2012 on a Boe basis was 90% oil and 10% natural gas compared to 51% oil and 49% natural gas for 2011.  Our average daily production increased by 1,011% to 1,140 Boepd during 2012 compared to 204 Boepd for 2011.  This increase in production for the Canadian Upstream segment in 2012 compared to 2011 is primarily attributable to organic growth through the Company’s ongoing drilling programs in the Tableland Field as well as reflecting a full six months of production in the current year compared to two months during 2011.

Oil and gas sales.  Oil and gas sales increased $64.8 million, or 162%, for the six months ended June 30, 2012, to $104.9 million from $40.0 million for the six months ended June 30, 2011.  The increase in oil and gas sales principally resulted from increased production as described above.  The average price we received for our oil production decreased $1.07 per barrel (1%) to $91.42 per barrel, while the average price received for gas production decreased $2.42 per Mcf (46%) to $2.79 per Mcf.  Our average price received for oil and gas production decreased due to market trends in the prices for these commodities.  Of the $64.8 million increase in oil and gas sales, approximately ($3.1 million), or (5%), was attributable to a decrease in price per Boe of $12.42, while approximately $68.0 million, or 105% of the increase in oil and gas sales was attributable to the increase in production volumes.  The prices we receive for our products are generally tied to commodity index prices.  We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices.  (See the discussion of commodity derivative activities in Note 7 to our condensed consolidated financial statements.)

Field operations revenues.  Field operations revenues include the revenues from our oilfield services segment and our midstream segment.  These revenues increased by $10.4 million for the six months ended June 30, 2012, or 255%.  This increase is primarily caused by the increase in oilfield service revenue and midstream operations discussed below.

Oilfield services revenue.  Oilfield services revenue increased by 120%, or $3.6 million, for the six months ended June 30, 2012 to $6.0 million from $2.7 million for the six months ended June 30, 2011.  Oilfield services revenues for the six months ended June 30, 2012 were primarily drilling services.

Midstream operations revenue.  Revenue from the Eureka Hunter Holdings midstream segment increased by $3.3 million, or 158%, for the six months ended June 30, 2012, to $5.4 million from $2.1 million for the year ended June 30, 2011.  The increase in revenues resulted from the increased volume of natural gas products gathered by the pipeline network and gathering system, $733,000 of revenue from marketing gas to third parties, and $2.3 million of revenues from its gas treating services.

Other revenues.  We recorded a net loss on sale of assets of $174,000 for the six months ended June 30, 2012, from the sale of a drilling rig by our oilfield services segment and various equipment from the Appalachian region of our upstream segment.  For the six months ended June 30, 2011, we recorded a gain on sale of assets of $1.6 million from the sale of assets in the Appalachian region.

Lease operating expense.  Our lease operating expenses increased $13.7 million, or 143%, for the six months ended June 30, 2012, to $23.2 million ($9.97 per Boe) from $9.6 million ($13.92 per Boe) for the six months ended June 30, 2011.  The decline in

37

operating expense per Boe is due to the effect of adding new production, principally in our unconventional resources, at lower cost per unit produced when compared to the per unit operating cost in our older, legacy fields.

Severance taxes and marketing.  Our severance taxes increased $4.8 million, or 80%, for the six months ended June 30, 2012, to $7.4 million from $2.7 million for the six months ended June 30, 2011.  All of the increase in severance taxes was attributable to the increase in oil and gas production.  Marketing expenses decreased by $46,000, or 33%, for the six months ended June 30, 2012, to $93,000 from $139,000 for the six months ended June 30, 2011, due to production declines at our existing Williston Basin properties.

Exploration.  We incurred $730,000 of exploration expense for the six months ended June 30, 2012, compared to $673,000 for the six months ended June 30, 2011.  We experienced higher geological and geophysical costs in the 2012 period resulting from the assets acquired by the Company in the second quarter of 2012.

Impairment of oil and gas properties.  We provided for an impairment to the carrying value of approximately $17.7 million in total, including $9.1 million of North Dakota unproved oil and gas properties and $5.0 million of our Appalachian acreage, which expired undrilled prior to June 30, 2012; and, we wrote off $3.6 million of expired leases in our Canadian properties.

Field operations expenses.  Field operating expense increased by $4.6 million for the six months ended June 30, 2012, or 190%.  This increase is primarily caused by the increase in oilfield service expense and midstream operations discussed below.

Oilfield services expenses.  Oilfield services expenses increased by 34%, or $1.0 million, for the six months ended June 30, 2012 to $4.1 million from $3.1 million for the six months ended June 30, 2011.  Oilfield services expenses for the three months ended comprise expenses incurred in drilling operations.

Midstream operations expenses.  Expenses incurred in gas gathering operations increased by 241%, or $3.1 million, for the six months ended June 30, 2012 to $4.4 million from $1.3 million for the six months ended June 30, 2011.  The increase is due primarily to the increase in pipeline activities being managed by Eureka Hunter Holdings compared to the prior year, as well as $713,000 of expenses incurred related to contracts for marketing gas for third parties.

Depletion, depreciation and accretion.  Our DD&A increased $40.5 million, or 250%, to $56.7 million for the six months ended June 30, 2012, from $16.2 million for the six months ended June 30, 2011 due to increased production in the 2012 period described above.  Our DD&A per Boe increased by $0.75, or 6%, to $24.34 per Boe for the six months ended June 30, 2012, compared to $23.59 per Boe for the six months ended June 30, 2011.  The increase in DD&A expense per Boe was primarily attributable to the higher cost to drill and equip our new Eagle Ford, Marcellus, and Bakken Shale wells, which are horizontally drilled wells and which require more expensive completion techniques than traditional, vertically-drilled wells.

General and administrative.  Our G&A decreased $2.6 million, or 9%, to $27.8 million ($11.93 per Boe) for the six months ended June 30, 2012, from $30.4 million ($44.29 per Boe) for the six months ended June 30, 2011.  G&A decreased overall during the 2012 period due to lower acquisition costs and stock compensation recognized in the six months ended June 30, 2012 compared to the six months ended June 30, 2011.  Non-cash stock compensation totaled approximately $8.7 million ($3.73 per Boe) and $12.0 million ($17.49 per Boe) for the six months ended June 30, 2012 and 2011, respectively.  The six months ended June 30, 2012 also included transaction costs of $2.6 million ($1.10 per Boe) related to acquisition activity.  The six months ended June 30, 2011, included acquisition related costs of approximately $7.8 million ($11.40 per Boe) which were for legal, consulting and other costs related to the acquisition of NGAS and NuLoch which closed in April and May of 2011, respectively.  We expect overall G&A costs to increase in the aggregate in 2012, but to continue to decline on a Boe basis due to the ongoing expansion activities of the Company.

Interest expense, net.  Our interest expense, net of interest income, increased approximately $20.5 million, or 437% to $25.2 million for the six months ended June 30, 2012, from $4.7 million for the six months ended June 30, 2011.  This increase was the result of our higher average debt level during 2012 as well as fees and non-cash amortization of deferred financing costs and payment of bridge fees which was $9.4 million as a result of our senior notes offering.  For the six months ended June 30, 2012, interest expense included $4.2 million in fees related to the bridge loan and $5.2 million in accelerated amortization recorded as a result of the reduction of the borrowing base of the Senior Credit Facility and the termination of the term loan.   During the six months ended June 30, 2011, we incurred a $2.3 million non-cash write off of the unamortized balance of deferred financing fees upon entering into the Senior Credit Facility in April of 2011.

Commodity derivative activities.  Realized gains and losses from our commodity derivative activity increased our earnings by approximately $5.7 million and decreased our earnings by approximately $508,000 for the six months ended June 30, 2012 and 2011, respectively.  Realized gains and losses are derived from the relative movement of oil and gas prices on the products we sell in relation

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to the range of prices in our derivative contracts for the respective six month periods.  The unrealized gain on commodity derivatives was approximately $14.7 million for the 2012 period and a loss of approximately $166,000 for the 2011 period.  As commodity prices increase, the fair value of the open portion of those positions decreases.  As commodity prices decrease, the fair value of the open portion of those positions increases.  Historically, we have not designated our derivative instruments as cash-flow hedges.  We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives.  We record all changes in realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts.”  Our gain or loss from realized and unrealized derivative contracts was a gain of approximately $20.5 million and a loss of approximately $675,000 for the six months ended June 30, 2012 and 2011, respectively.  (See Note 7 to our condensed consolidated financial statements for more information.)

Income tax benefit.  The Company recorded an income tax benefit of $3.8 million for the six months ended June 30, 2012, to reflect the change in the deferred tax liability of the Company’s Williston Hunter subsidiary.

Net income attributable to non-controlling interest.  Net income attributable to non-controlling interest was approximately $22,000 for the six months ended June 30, 2012 versus $117,000 for same period in 2011.  This represents 12.5% of the gain or loss incurred by our subsidiary, PRC Williston, LLC.  We record a non-controlling interest in the results of operations of this subsidiary because we are contractually obligated to make distributions to the holders of this interest whenever we make distributions to ourselves from the subsidiary company.

Loss from Continuing Operations.  We had a loss from continuing operations of $24.6 million for the 2012 period versus a loss of $23.2 million for the 2011 period, an increase of $1.4 million, or 6%.  This was due to an increase in revenues of $73.4 million offset by increases in lease operating expense of $13.7 million, severance taxes of $4.8 million, DD&A of $40.5 million, interest expense of $20.5 million, and gain on fair value of derivatives of $21.1 million.

Income from Discontinued Operations.  On February 17, 2012, we closed on a sale of Hunter Disposal, LLC, previously a wholly owned subsidiary.  We have reclassified $354,000 and $1.5 million of net operating income (net of interest expense) of the divested subsidiary to discontinued operations for the six month period ended June 30, 2012 and 2011, respectively.  We have also reclassified the gain on sale of $4.3 million to discontinued operations for the six months ended June 30, 2012.

Dividends on Preferred Stock.  Total dividends on our Series C and Series D Preferred Stock were approximately $11.8  million for the six months ended June 30, 2012.  Dividends were $6.1 million for the six months ended June 30, 2011.  The Series C Preferred Stock had a stated value of $100 million at both June 30, 2012 and 2011 and carries a cumulative dividend rate of 10.25% per annum.  The Series D Preferred Stock had a stated value of $127.3 million and $64.9 million at June 30, 2012 and 2011, respectively and carries a cumulative dividend rate of 8.0% per annum.  The Series A Preferred Units of Eureka Hunter Holdings had a stated value of $131.8 million and $0 at June 30, 2012 and 2011, respectively, and carry a cumulative dividend rate of 8% per annum.

Net Loss attributable to Common Shareholders.  Net loss attributable to common shareholders was $31.7 million in the 2012 period versus $27.8 million in the 2011 period.  Our net loss per common share, basic and diluted was $0.22 per share for the six months ended June 30, 2012, compared to net loss of $0.29 per share for the 2011 period.  Our weighted average shares outstanding increased by approximately 48.1 million shares, or 51%, from 94,233,091 shares in the 2011 period to 142,293,282 during the 2012 period.  Our net loss per share from continuing operations was $0.25 per share for the six months ended June 30, 2012, versus a net loss of $0.31 per share for the 2011 period.  We had income from discontinued operations of $1.5 million ($0.02 per share) in the 2011 period from Hunter Disposal, LLC.

Liquidity and Capital Resources

We generally rely on cash generated from operations, borrowings under our revolving credit facility and, to the extent that credit and capital market conditions will allow, public and private equity and debt offerings to satisfy our liquidity needs.  Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our revolving credit facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.  We cannot predict whether additional liquidity from equity or debt financings beyond our revolving credit facility will be available, or acceptable on our terms, or at all, in the foreseeable future.

Our cash flow from operations is driven by commodity prices, production volumes and the effect of commodity derivatives.  Prices for oil and gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control.  Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices will cause a decrease in our production volumes and exploration and

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development expenditures.  Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.

At June 30, 2012, Eureka Hunter Pipeline, LLC was not in compliance with the covenants contained in the Eureka Hunter Credit Facilities that require Eureka Hunter to maintain certain ratios of debt to EBITDA and interest coverage.  We have received a waiver of the covenants at June 30, 2012.  In addition, we have executed an amendment for future ratios of debt to EBITDA and interest coverage through December 31, 2012.  These adjustments were necessary primarily due to the delay in the completion of the Mobley Processing Plant. Based on the amended facility, management believes it is probable we will be in compliance with Eureka Hunter Credit Facility covenants for each quarter at least through June 30, 2013.

We intend to fund 2012 capital expenditures, excluding any acquisitions, primarily out of internally-generated cash flows and borrowings under our revolving credit facility for upstream operations.  We may also raise additional funds in the public debt markets, through sales of our Series D Preferred Stock and equity markets.  As of June 30, 2012, we had $112.5 million available to borrow under our revolving credit facility.  On August 8, 2012, we increased our borrowing base by $47.5 million from $212.5 million to $260.0 million, at which time we had $115.0 million available to borrow. The Company is anticipating further increases in the borrowing base under the senior credit facility due to the increase in reserves from our organic drilling programs.  We intend to fund our activities in our Eureka Hunter Midstream operations through our Eureka Hunter Credit Facilities and the ArcLight investment.

For the six months ended June 30, 2012, our primary sources of cash were from operating activities, financing activities, and cash on hand at the beginning of the year.  Approximately $48.7 million of cash from operating activities, $444.0 million of proceeds from issuing the Senior Notes, $199.6 million of cash from sale of common and preferred stock and the proceeds from exercises of warrants, along with our $320.0 million of borrowings under our revolving credit facility, $21.7 million of borrowings under term loans, and $14.9 million of cash on hand were used to fund our acquisitions and drilling program, repay debt under our revolving credit facility, and pay deferred financing costs on our amended and restated credit facility.

For the six months ended June 30, 2011, our primary sources of cash were from financing activities.  Approximately $108.3 million of cash from the sale of preferred stock and the proceeds from exercises of warrants, along with our $228.0 million of borrowings under our senior credit facility, and $554,000 of cash on hand were used to fund our acquisitions and drilling program and repay debt under our senior credit facility.

The following table summarizes our sources and uses of cash for the periods noted:

	Six Months Ended June 30,
	2012			2011
	(In thousands)
Cash flows provided by operating activities	$	48,665		$	9,958
Cash flows used in investing activities	(658,720		)	(213,989		)
Cash flows provided by financing activities	619,999			208,224
Effect of foreign currency exchange rates	(33		)	3
Net increase (decrease) in cash and cash equivalents	$	9,911		$	(4,196	)

Operating Activities

Our cash flow from operating activities was $48.7 million for the six months ended June 30, 2012 compared to $10.0 million for the six months ended June 30, 2011, an increase of $38.7 million.  This increase was due to increased oil and gas sales from the success of our drilling program as well as from our acquisitions done during 2011 and 2012.

Investing Activities

Our cash flows used in investing activities for the six months ended June 30, 2012 were $658.7 million, principally from acquisition and drilling activities.  We used $312.0 million in cash acquiring Bakken shale oil and gas properties from Baytex, $50.9 million acquiring Williston Basin oil and gas properties from Eagle Operating, $24.8 million in cash for the Utica Shale property acquisition, and $219.5 million in cash for drilling and other capital expenditures under our 2012 capital expenditures budget.  Also during

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the six months ended June 30, 2012, we received $783,000 in cash proceeds, net of working capital adjustments, from the sale of Hunter Disposal, LLC.

Our cash flows used in investing activities for the six months ended June 30, 2011 were $214.0 million, which primarily were a result of the acquisition activity undertaken by the Company during the quarter.  The Company used $60.4 million in cash in the NGAS acquisition, net of cash acquired of $1.9 million and $18.1 million in cash in the NuLoch acquisition, net of cash acquired of $640,000.  During the six months ended June 30, 2011, we used $5.5 million of cash for deposits on equipment, and we received proceeds from the sale of assets of $1.8 million.  During the six months ended June 30, 2011, we used $131.8 million in for capital expenditures which includes $20.0 million in the acquisition of the Wetzel County assets from Windsor Marcellus, LLC, $4.9 million cash in the third phase of the acquisition of assets from PostRock Energy Corporation, and $105.0 million for capital expenditures under our 2011 capital expenditures budget as described below.

Financing Activities

Our cash flows from financing activities for the six months ended June 30, 2012 were $620.0 million.  We issued $444.0 million of Senior Notes.  We used the proceeds from the offering to repay principal of $362.0 million of our senior revolving credit facility and retired the term note of $100.0 million.  We repaid $2.6 million on other equipment loans, and repaid $1.6 million on various equipment loans. Eureka Hunter Pipeline also borrowed $19.0 million under its credit facility.  Other sources of cash from financing activities in the 2012 period were $50.9 million from the issuance of our Series D Preferred Stock and $127.4 million from the issuance of Series A Preferred Units of Eureka Holdings, of which $60 million was distributed to Magnum Hunter. We also received $1.2 million in proceeds from exercise of stock options and warrants.  In the 2012 period we also incurred $18.2 million of deferred finance cost on loans and paid $9.5 million in dividends on our preferred stock.

We borrowed $228.0 million under our senior revolving credit facility and made principal repayments of $119.0 million during the six months ended June 30, 2011.  In the 2011 period, we realized $5.8 million from the exercise of common stock options and warrants.  We issued 1,190,544 shares of our Series C Cumulative Perpetual Preferred Stock during the six months ended June 30, 2011, for net proceeds of $29.1 million, and we issued 1,298,095 shares of our Series D Preferred Stock for net proceeds of $59.5 million in 2011.

We believe that cash flows from operations and borrowings under our revolving credit facility and other debt agreements and sales of Series D preferred stock will finance all of our capital needs through 2012.  We may also use our revolving credit facility for possible acquisitions and temporary working capital needs.  Further, we may decide to access the public or private equity or debt markets for potential acquisitions, working capital or other liquidity needs, if such financing is available on acceptable terms.  In June 2011, we filed a shelf registration statement with the SEC registering up to $500 million of common stock, preferred stock warrants and debt securities, which replaced a prior shelf registration statement.  This registration statement was declared effective by the SEC on January 18, 2012.

2012 Capital Expenditures

The following table summarizes our estimated capital expenditures excluding acquisitions for 2012.  We intend to fund 2012 capital expenditures, excluding any acquisitions, partially out of internally-generated cash flows and, as necessary, borrowings under our senior revolving credit facility.  We will also need to obtain additional funding through the public debt and equity markets to fulfill our capital spending plans.

	Year Ending
	December 31,
	2012
	(In thousands)
Upstream Operations
Williston Basin drilling	$	170,000
Appalachian Basin drilling	25,000
Eagle Ford Shale drilling	130,000
Total Upstream capital expenditures	325,000
Midstream Operations (Eureka Hunter Holdings, LLC) (1)	50,000
Total 2012 capital expenditures	$	375,000

(1)Funded through Eureka Hunter Credit Facilities and ArcLight Investment.

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Our capital expenditure budget for 2012 is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the results of our development and exploration efforts, the availability of sufficient capital resources for drilling prospects, our financial results, the availability of leases on reasonable terms and our ability to obtain permits for the drilling locations.

Amendments to Credit Agreements

On February 14, 2012, the Company entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement.  The Fifth Amendment increased the borrowing base on the Senior Revolving Credit Facility from $200 million to $235 million.

On February 14, 2012, the Company entered into the Second Amendment to the Second Lien Term Loan Credit Agreement.  The Second Amendment amends certain provisions of the Second Lien Term Loan Credit Agreement to correspond to the amendments made pursuant to the Fifth Amendment to the Second Amended and Restated Credit Agreement.

On May 2, 2012, the Company entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement, as amended.  Pursuant to the sixth amendment to the credit facility, our borrowing base under our senior revolving credit agreement was increased from $235.0 million to $275.0 million, then pursuant to the issuance of the $450.0 million 9.75% Senior Notes the borrowing base was decreased from $275.0 million to $187.5 million, then pursuant to the closing of the Baytex Acquisition the borrowing base was increased from $187.5 million to $212.5 million.  The Seventh Amendment to the Second Amended and Restated Credit Agreement reduced the current ratio covenant to 0.85 for June 30, 2012.

On June 29, 2012, Eureka Hunter Pipeline, entered into the Limited Waiver and Third Amendment to the Second Lien Term Loan Credit Agreement.  The Third Amendment amends the agreement by reducing the minimum interest coverage ratio to 0.85:1.00 for the fiscal quarters ending September 30, 2012 and December 31, 2012, and by increasing the maximum total leverage ratio to 9.50:1.00 and 8.5:1.00 for the fiscal quarters ending September 30, 2012 and December 31, 2012, respectively.  The lenders under the Second Lien Term Loan Credit Agreement also agreed to waive any events of default occurring as a result of Eureka’s failure to comply with such ratios during the fiscal quarter ended June 30, 2012.  Finally, the Third Amendment modified the interest rate provisions in the Second Lien Term Loan Credit Agreement so that after June 29, 2012, all interest shall be payable in cash.    The reduced minimum Interest Coverage Ratio shall increase back to 1.00:1.00, and the increased maximum Total Leverage Ratio shall decrease back to 6:50:1:00, if Eureka Hunter Pipeline receives funding prior to December 31, 2012 under its First Lien Credit Agreement with SunTrust Bank, unless such credit agreement is amended in a manner satisfactory to PennantPark.

Related Party Transactions

We rented an airplane for business use at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans, our Chairman and Chief Executive Officer.  Airplane rental expenses totaled $64,125 and $81,225 for the three months and six months ended June 30, 2012, and $105,000 and $228,000, for the three and six months ended June 30, 2011, respectively.

We obtained accounting services and use of office space from GreenHunter Energy, Inc., an entity for which Mr. Evans is a director, an officer and major shareholder and for which Mr. Ormand, our Chief Financial Officer and director, is also a director.  This agreement has terminated and all accounting services are now controlled by Magnum Hunter personnel.  Professional services expenses totaled $0 for the three and six months ended June 30, 2012 and $28,000 and $46,000 2011 for the three and six month ended June 30, 2011, respectively.

During the six months ended June 30, 2012 and 2011, the Company paid rent of $18,000 and $0 for the three and six months ended June 30, 2012 and $0 and $9,000 for the three and six month ended June 30, 2011, respectively, pertaining to a lease for a corporate apartment from an executive of the Company which is being used by other Company employees.  This agreement terminates in May of 2012 and the Company did not renew it.

During the six months ended June 30, 2012, Eagle Ford Hunter, Triad Hunter, and Hunter Disposal, LLC, wholly owned subsidiaries of the Company, rented storage tanks for disposal water and equipment from GreenHunter Energy, Inc.  Rental costs totaled $878,000 and approximately $1.6 million for the three months and six months ended June 30, 2012 respectively and $0 for the three and six months ended June 30, 2011.  As of June 30, 2012, our net accounts payable to GreenHunter Energy, Inc. was $754,000 for these leases.

On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, LLC, to GreenHunter Water, LLC, a wholly-owned subsidiary of GreenHunter Energy, Inc.  The terms and conditions of the equity purchase agreement between the parties were approved by the audit committee or an independent special committee for each party.  Total consideration for the sale was approximately $9.9 million comprising $2.2 million in cash, 1,846,722 shares of GreenHunter Energy, Inc. restricted common stock with a fair value of $3.3 million based on a closing price of $1.79, 88,000 shares of GreenHunter Energy, Inc. 10% Series C cumulative preferred stock with a stated value of $2.2 million, and a $2.2 million convertible promissory note due to the Company.  In connection with the sale, Triad Hunter, LLC, entered into agreements with Hunter Disposal, LLC and GreenHunter Water, LLC for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water, LLC.  See note 6 — Discontinued Operations for additional information.

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Mr. Evans, our Chairman and Chief Executive Officer, was a 4.0% limited partner TransTex Gas Services, LP, which limited partnership received consideration of 585,000 Series A common units of Eureka Hunter Holdings, and cash of $46.8 million upon the Company’s acquisition of certain its assets.  In addition, Eureka Hunter Holdings and TransTex agreed to provide the limited partners of TransTex the opportunity to purchase additional Class A common units in lieu of a portion of the cash distribution they would otherwise receive.  Certain limited partners purchased such units, including Mr. Evans, who purchased 27,641 Class A common units of Eureka Hunter Holdings, for $553,000 at the same purchase price offered to all TransTex investors.

Contractual Commitments

Our contractual commitments consist of long-term debt, accrued interest on long-term debt, operating lease obligations, drilling contracts, asset retirement obligations, and employment agreements with executive officers.

Our long-term debt comprises borrowings under our Senior Notes, Senior Revolving Credit Facility, Eureka Hunter Term Loan, and term equipment debt assumed in the Triad Energy and NGAS acquisitions.  Interest on the Senior Notes is based on the stated rate of 9.75%.  Interest on revolving debt is based on the rate applicable under our senior revolving credit facility, which was 3.0% at June 30, 2012.  The term equipment debt had an average interest rate of approximately 4.83% at June 30, 2012.  See Note 9 in our condensed consolidated financial statements.

As of June 30, 2012, we rent various office spaces in Houston, Texas, that total approximately 15,000 square feet at a cost of $35,000 per month for the remaining terms ranging from eighteen to forty-six months.  Triad Hunter, LLC had various lease commitments for periods ranging from six to sixty-five months at June 30, 2012, and with monthly payments of approximately $26,053 as of that date.  Our Williston Hunter subsidiaries have office spaces in Calgary, Alberta and Denver, Colorado that have a combined monthly payment of approximately $32,000.

On June 24, 2011, the Company entered into a forty month drilling contract from July 1, 2011 through October 31, 2014.  Our remaining maximum liability under the drilling contract, which would apply if we terminated the contract before the end of its term, was approximately $13.6 million as of June 30, 2012.

Our asset retirement obligation represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws.  We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability.  The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

We have outstanding employment agreements with two of our senior officers for terms ranging from two to six months.  Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were all terminated without cause, was approximately $472,000 at June 30, 2012.

The following table summarizes our contractual commitments as of June 30, 2012 (in thousands):

Contractual Obligations	Total		2012		2013 –2014		2015 - 2016		After 2016
Long-term debt(1)	$	609,752	$	1,609	$	6,169	$	106,762	$	495,212
Interest on long-term debt(2)	396,700		29,465		105,347		103,194		158,694
Operating lease obligations(3)	2,483		632		1,188		521		142
Asset retirement obligations(4)	23,816		1,941		1,201		1,671		19,003
Employment agreements with executive officers	472		472		—		—		—
Drilling contract commitment	13,648		2,928		10,720		—		—
Total	$	1,046,871	$	37,047	$	124,625	$	212,148	$	673,051

(1)	See Note 9 to our consolidated financial statements for a discussion of our long-term debt.
(2)	Interest payments have been calculated by applying the interest rate 3.0% on the Senior Revolving Credit Facility in place as of June 30, 2012.
(3)	Operating lease obligations are for office space and equipment.

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(4) See Note 7 to our consolidated financial statements for a discussion of our asset retirement obligations.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of June 30, 2012, the off-balance sheet arrangements and transactions that we have entered into include operating lease agreements.  We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Item 3.Quantitative and qualitative disclosures about market risk.

Some of the information below contains forward-looking statements.  The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks.  The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and other related factors.  The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses.  This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures.  Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, and not for trading purposes.

Commodity Price Risk

Given the current economic outlook, we expect the commodity prices to remain volatile.  Even modest decreases in commodity prices can materially affect our revenues and cash flow.  In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to perform a write down of our oil and gas properties.

We may enter into financial swaps and collars to reduce the risk of commodity price fluctuations.  We do not designate such instruments as cash flow hedges.  Accordingly, we record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as income (expense) on our consolidated statements of operations as they occur.

At June 30, 2012, we had the following commodity derivative positions outstanding:

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			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Collars	Jul 2012 - Dec 2012	11,910	$4.58 - $6.42
	Jan 2013 - Dec 2013	12,500	$4.50 - $5.96
Swaps	Jul 2012 - Dec 2012	16,100	$3.53
	Jan 2013 - Dec 2013	15,500	$3.52
Ceilings sold (call)	Jan 2014 - Dec 2014	16,000	$5.91

			Weighted Avg
Crude Oil	Period	Bbls/day	Price per Bbl
Collars	Jul 2012 - Dec 2012	2,950	$81.80 - $98.76
	Jan 2013 - Dec 2013	2,763	$81.38 - $97.61
	Jan 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Three-way collars (1)	Jul 2012 - Dec 2012	50	$55.00 - $75.00 - $108.00
	Jan 2013 - Dec 2013	2,000	$60.63 - $80.00 - $100.00
Three-way collar (2)	Jan 2013 - Dec 2013	763	$65.00 - $91.25 - $101.25
Ceilings sold (call)	Jul 2012 - Dec 2012	688	$100.30
Ceilings purchased (call)	Jul 2012 - Dec 2012	688	$91.25
Floors sold (put)	Jul 2012 - Dec 2012	1,400	$80.00
	Jan 2013 - Dec 2013	763	$65.00
	Jan 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00
Floors purchased (put)	Jul 2012 - Dec 2012	1,553	$93.52

(1) These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.

(2) This three-way collar is a combination of three options: a sold call, a purchased call and a sold put.

At June 30, 2012, the fair value of our open derivative contracts was a net asset of approximately $9.7 million.

Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, UBS AG London Branch, Deutsche Bank AG London Branch, and Citibank, N.A. are the only counterparties to our commodity derivatives positions.  We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions.  However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.  All counterparties are participants in our revolving credit facility, and the collateral for the outstanding borrowings under our revolving credit facility is used as collateral for our commodity derivatives.

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts.  Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations.  We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities.  We internally valued the collar, call, and put contracts using industry-standard option pricing models and observable market inputs.  We use our internal valuations to determine the fair values of

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the contracts that are reflected on our consolidated balance sheets.  Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

Realized gains and losses from our commodity derivative activity increased our earnings by approximately $5.7 million and decreased our earnings by approximately $508,000 for the six months ended June 30, 2012 and 2011, respectively.  Realized gains and losses are derived from the relative movement of oil and gas prices on the products we sell in relation to the range of prices in our derivative contracts for the respective three months.  The unrealized gain or loss on commodity derivatives was a gain of approximately $14.7 million for the 2012 period and a loss of $166,000 for the 2011 period.  As commodity prices increase, the fair value of the open portion of those positions decreases.  As commodity prices decrease, the fair value of the open portion of those positions increases.  Historically, we have not designated our derivative instruments as cash-flow hedges.  We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives.  We record all changes in realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled “Gain (loss) on derivative contracts.”  Our gain or loss from realized and unrealized derivative contracts was a gain of approximately $20.5 million and a loss of approximately $674,000 for the three months ended June 30, 2012 and 2011, respectively.  (See Note 7 to our condensed consolidated financial statements for more information.)

For the three months ended June 30, 2012, we recorded an unrealized gain on commodity derivatives of approximately $17.6 million, compared to an unrealized gain of approximately $3.2 million for the three months ended June 30, 2011, from the change in fair value of our commodity derivatives positions.  A hypothetical 10% increase in commodity prices would have resulted in a $20.9 million decrease in the fair value of our commodity derivative positions recorded on our balance sheet at June 30, 2012, and a corresponding increase in the unrealized loss on commodity derivatives recorded on our consolidated statement of operations for the three months ended June 30, 2012.  A hypothetical 10% decrease in commodity prices would have resulted in a $19.6 million increase in the fair value of our commodity derivative position recorded on our balance sheet at June 30, 2012, and a corresponding decrease in the unrealized loss on commodity derivatives recorded on our consolidated statement of operations for the three months ended June 30, 2012.

The following table summarizes derivatives entered into since June 30, 2012:

			Weighted Avg
Crude Oil	Period	Bbls/day	Price per Bbl
Three-way collars (1)	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Swaps	Aug 2012 - Dec 2012	3,500	$90.55
	Jan 2013 - Dec 2013	1,000	$91.46

(1) These three-way collars are a combination of three options: a sold call, a purchased put and a sold put.

Item 4.Controls and procedures.

Evaluation of disclosure controls and procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we file under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Such controls include those designed to ensure that information for disclosure is accumulated and communicated to management, including the Chairman and Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Our management, with the participation of our CEO and CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of June 30, 2012.  Based on this evaluation, the CEO and CFO have concluded that, as of June 30, 2012, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Internal control over financial reporting

There were no changes made in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the three months ended June 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Limitations inherent in all controls

Our management, including the CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud.  Any controls system, no matter how well crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives.  Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been or will be detected.

PART II.  OTHER INFORMATION

Item 1.       Legal Proceedings.

There have been no material developments in the legal proceedings described in Part I, Item 3. “Legal Proceedings” of our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011.

Item 1A.    Risk factors.

In addition to the other information set forth in this report, you should carefully consider the risks discussed in the following reports that we have filed with the SEC, which risks could materially affect our business, financial condition and results of operations:  Annual Report on Form 10-K, as amended, for the year ended December 31, 2011, under the headings Items 1. and 2. “Business and Properties — Markets and Customers; Competition; and Regulation,” Item 1A. “Risk Factors,” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk”.

Except as provided below, there have been no material changes to the risk factors discussed in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011, which is accessible on the SEC’s website at www.sec.gov and our website at www.magnumhunterresourcess.com.

The use of geoscientific, petropyhsical and engineering analyses and other technical or operating data to evaluate drilling prospects is uncertain and does not guarantee drilling success or recovery of economically producible reserves.

Our decisions to explore, develop and acquire prospects or properties targeting the Eagle Ford Shale, Bakken Shale, Marcellus Shale, and other areas depend on data obtained through geoscientific, petrophysical and engineering analyses, the results of which can be uncertain. Even when properly used and interpreted, data from whole cores, regional well log analyses and 3-D seismic only assist our technical team in identifying hydrocarbon indicators and subsurface structures and estimating hydrocarbons in place. They do not allow us to know conclusively the amount of hydrocarbons in place and if those hydrocarbons are producible economically. In addition, the use of advanced drilling and completion technologies for our Bakken Shale and Eagle Ford developments, such as horizontal drilling and multi-stage fracture stimulations, requires greater expenditures than our traditional development drilling strategies. Our ability to commercially recover and produce the hydrocarbons that we believe are in place and attributable to the our properties will depend on the effective use of advanced drilling and completion techniques, the scope of our drilling program (which will be directly affected by the availability of capital), drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and geological and mechanical factors affecting recovery rates. Our estimates of unproved reserves, estimated ultimate recoveries per well, hydrocarbons in place and resource potential may change significantly as development of our oil and gas assets provides additional data.

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ITEM 6. EXHIBITS

Exhibit Number	Description
2.1	Second Amendment to Purchase and Sale Agreement, dated April 2, 2012, by and among Eagle Operating, Inc., Williston Hunter ND, LLC, and Magnum Hunter Resources Corporation (Incorporated by reference from the Registrant’s current report on Form 8-K filed on April 5, 2012).
2.2	First Amendment to Asset Purchase Agreement, dated April 2, 2012, by and between Eureka Hunter Holdings, LLC, TransTex Gas Services, LP, and Eureka Hunter Acquisition Sub LLC (Incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012).
2.3	Purchase and Sale Agreement, dated as of April 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (Incorporated by reference from the Registrant’s current report on Form 8-K filed on April 24, 2012).+
2.4	First Amendment to Purchase and Sale Agreement, dated May 17, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (Incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012).
2.5	Second Amendment to Purchase and Sale Agreement, dated May 22, 2012, by and between Baytex Energy USA Ltd. and Bakken Hunter, LLC (Incorporated by reference from the Registrant’s current report on Form 8-K filed on May 23, 2012).
3.1	Restated Certificate of Incorporation of the Registrant, filed February 13, 2002 (Incorporated by reference from the Registrant’s Registration Statement on Form SB-2 filed on March 21, 2006).
3.1.1	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed May 8, 2003 (Incorporated by reference from the Registrant’s Registration Statement on Form SB-2 filed on March 21, 2006).
3.1.2	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed June 6, 2005 (Incorporated by reference from the Registrant’s Registration Statement on Form SB-2 filed on March 21, 2006).
3.1.3	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed July 18, 2007 (Incorporated by reference from the Registrant’s quarterly report on Form 10-QSB filed on August 14, 2007).
3.1.4	Certificate of Ownership and Merger Merging Magnum Hunter Resources Corporation with and into Petro Resources Corporation, filed July 13, 2009 (Incorporated by reference from the Registrant’s current report on Form 8-K filed on July 14, 2009).
3.1.5	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed November 3, 2010 (Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 2, 2010).

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3.2	Amended and Restated Bylaws of the Registrant, dated March 15, 2001 (Incorporated by reference from the Registrant’s Registration Statement on Form SB-2 filed on March 21, 2006).
3.2.1	Amendment to Bylaws of the Registrant, dated April 14, 2006 (Incorporated by reference from the Registrant’s Amendment No. 1 to Registration Statement on Form SB-2 filed on June 9, 2006).
3.2.2	Amendment to Bylaws of the Registrant, dated October 12, 2006 (Incorporated by reference from the Registrant’s Amendment No. 1 to Registration Statement on Form SB-2 filed on September 21, 2007).
4.1	Form of certificate for common stock (Incorporated by reference from the Registrant’s 2010 annual report on Form 10-K filed on February 18, 2011).
4.2	Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated December 10, 2009 (Incorporated by reference from the Registrant’s Registration Statement on Form 8-A filed on December 10, 2009).
4.2.1	Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated August 2, 2010 (Incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on August 12, 2010).
4.2.2	Certificate of Amendment of Certificate of Designation of Rights and Preferences of 10.25% Series C Cumulative Perpetual Preferred Stock, dated September 8, 2010 (Incorporated by reference from the Registrant’s current report on Form 8-K filed on September 15, 2010).
4.2.3	Certificate of Amendment of Certificate of Incorporation of the Registrant, filed March 16, 2011 (Incorporated by reference from the Registrant’s current report on Form 8-K filed on March 17, 2011).
4.3	Indenture, dated May 16, 2012, by and among the Company, the Guarantors named therein, Wilmington Trust, National Association and Citibank, N.A., as Paying Agent, Registrar and Authenticating Agent (Incorporated by reference from the Registrant’s current report on Form 8-K filed on May 16, 2012).
4.4	Registration Rights Agreement, dated May 16, 2012, by and among the Company, the Guarantors named therein and Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as the representatives of the several Initial Purchasers named therein (Incorporated by reference from the Registrant’s current report on Form 8-K filed on May 16, 2012).
10.1	Sixth Amendment to Second Amended and Restated Credit Agreement and Limited Waiver, dated May 2, 2012, by and among the Company, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.2	Seventh Amendment to Second Amended and Restated Credit Agreement, dated May 2, 2012, by and among the Company, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.3	Eighth Amendment to Second Amended and Restated Credit Agreement, dated May 10, 2012, by and among the Company, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto.#
10.4	Third Amendment to Second Lien Term Loan Credit Agreement and Limited Waiver, dated May 2, 2012, by and among the Company, Capital One, N.A., as Administrative Agent, and the lenders and

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	guarantors party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.5	Fourth Amendment to Second Lien Term Loan Credit Agreement, dated May 2, 2012, by and among the Company, Capital One, N.A., as Administrative Agent, and the lenders and guarantors party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.6	First Amendment to First Lien Credit Agreement, dated May 2, 2012, by and among Eureka Hunter Pipeline, LLC, SunTrust Bank, as Administrative Agent, and the lenders party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.7	First Amendment to Second Lien Term Loan Agreement, dated September 20, 2011, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.8	Limited Waiver to Second Lien Term Loan Agreement, dated May 2, 2012, by and among Eureka Hunter Pipeline, LLC, U.S. Bank National Association, as Collateral Agent, PennantPark Investment Corporation and the other lenders party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.9	Second Amendment to Second Lien Term Loan Agreement by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 8, 2012).
10.10	Limited Waiver and Third Amendment to Second Lien Term Loan Agreement, dated June 29, 2012, by and among Eureka Hunter Pipeline, LLC, PennantPark Investment Corporation and the other lenders party thereto (Incorporated by reference from Registrant’s current report on Form 8-K filed on July 6, 2012).
10.11	First Amendment to Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated April 2, 2012, by and between Magnum Hunter Resources Corporation, Ridgeline Midstream Holdings, LLC, and TransTex Gas Services LP (Incorporated by reference from the Registrant’s quarterly report on Form 10-Q filed on May 3, 2012).
10.12	Underwriting Agreement, dated May 11, 2012, between the Company and Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as the representatives for the several underwriters named therein (Incorporated by reference from Registrant’s current report on Form 8-K filed on May 14, 2012).
12.1	Computation of Ratio of Earnings to Fixed Charges. #
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#
32.1	Certification of the Chief Executive Officer and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.#
101.INS	XBRL Instance Document ^

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101.SCH	XBRL Taxonomy Extension Schema Document ^
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document ^
101.LAB	XBRL Taxonomy Extension Label Linkbase Document ^
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document ^
101.DEF	XBRL Taxonomy Extension Definition Presentation Linkbase Document ^

+	The exhibits and the schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.
#	Filed herewith.
^	These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

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SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereto duly authorized.

	MAGNUM HUNTER RESOURCES CORPORATION
Date: August 9, 2012		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman and Chief Executive Officer

Date: August 9, 2012	/s/ Ronald D. Ormand
	Ronald D. Ormand,
	Executive Vice President and Chief Financial Officer

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