Magnum Hunter Resources 10-Q 2012 Q3 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 September 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 November 13, 2012, there were 168,627,014 shares of the registrant’s common stock ($0.01 par value) outstanding.

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED SEPTEMBER 30, 2012

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited):	1
Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	1
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011	2
Consolidated Statements of Comprehensive Income (Loss)	3
Condensed Consolidated Statement of Shareholders’ Equity for the Nine Months Ended September 30, 2012	4
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 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	36
Item 3. Quantitative and Qualitative Disclosures About Market Risk	53
Item 4. Controls and procedures	55
Part II. OTHER INFORMATION	58
Item 1. Legal Proceedings	58
Item 1A. Risk Factors	58
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	58
Item 6. Exhibits	58
SIGNATURES	61

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

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

	September 30,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,998		$	14,851
Accounts receivable, net of allowance for doubtful accounts of $3,874 and $3,888 as of September 30, 2012 and December 31, 2011, respectively	84,606			48,083
Derivative assets	3,307			5,732
Convertible security derivative asset	590
Inventory	11,333			4,534
Prepaids and other current assets	2,754			1,720
Assets held for sale — current	—			2,749
Total current assets	124,588			77,669
PROPERTY AND EQUIPMENT (Net of Accumulated Depletion and Depreciation):
Oil and natural gas properties, successful efforts accounting	1,577,500			962,965
Gas gathering and other equipment	163,770			112,169
Total property and equipment, net	1,741,270			1,075,134
OTHER ASSETS:
Deferred financing costs, net of amortization of $7,327 and $958 as of September 30, 2012 and December 31, 2011, respectively	19,423			10,642
Derivatives and other long term assets	8,644			1,913
Intangible assets, net	9,485			—
Goodwill	30,602			—
Assets held for sale — long term	—			3,402
Total assets	$	1,934,012		$	1,168,760
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of notes payable	$	3,672		$	4,565
Accounts payable	131,589			137,276
Accrued liabilities	20,747			4,752
Revenue payable	19,576			10,781
Derivatives and other current liabilities	11,070			7,454
Liabilities associated with assets held for sale — current	—			2,847
Total current liabilities	186,654			167,675
OTHER LIABILITIES:
Long-term debt	680,321			285,824
Asset retirement obligation	22,833			20,089
Deferred tax liability	90,410			95,299
Commodity and preferred stock embedded derivatives	48,604			6,112
Other long term liabilities	3.359			2,842
Liabilities associated with assets held for sale — long term	—			267
Total liabilities	$	1,032,181		$	578,108
COMMITMENTS AND CONTINGENCIES (Note 14)
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 September 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, 6,672,892 and none issued & outstanding as of September 30, 2012 and December 31, 2011, respectively, with liquidation preference of $134,267 and $0 as of September 30, 2012 and December 31, 2011, respectively	86,334			—
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, 4,138,325 and 1,437,558 issued & outstanding as of September 30, 2012 and December 31, 2011, respectively, with liquidation preference of $50.00 per share	206,916			71,878
Common stock, $0.01 par value; 250,000,000 shares authorized, 169,455,528 and 130,270,295 shares issued and 169,455,528 and 129,803,374 outstanding as of September 30, 2012 and December 31, 2011, respectively	1,695			1,298
Exchangeable common stock, par value $0.01 per share, 538,875 and 3,693,871 issued and outstanding as of September 30, 2012 and December 31, 2011, respectively	5			37
Additional paid in capital	720,956			569,690
Accumulated deficit	(220,248		)	(140,070		)
Accumulated other comprehensive loss	(6,136		)	(12,463		)
Treasury stock at cost, 914,952 and 761,652 shares as of September 30, 2012 and December 31, 2011	(1,914		)	(1,310		)
Unearned common stock in KSOP at cost, none and 153,300 shares as of September 30, 2012 and December 31, 2011 respectively	—			(604		)
Total Magnum Hunter Resources Corporation shareholders’ equity	701,274			488,456
Non-controlling interest	14,223			2,196
Total shareholders’ equity	715,497			490,652
Total liabilities and shareholders’ equity	$	1,934,012		$	1,168,760

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

1

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
REVENUE:
Oil and gas sales	$	62,648		$	25,548		$	167,502		$	65,555
Gas gathering and processing	2,529			885			5,609			2,103
Oilfield services	4,616			2,525			14,330			3,729
Gain (loss) on sale of assets and other revenue	(23		)	(903		)	(175		)	737
Total revenue	69,770			28,055			187,266			72,124
EXPENSES:
Lease operating expenses	12,567			7,542			35,793			17,101
Severance taxes and marketing	4,393			1,933			11,928			4,729
Exploration	345			467			1,075			1,140
Gas gathering and processing	1,153			102			2,152			278
Oilfield services	5,213			2,473			11,230			4,716
Impairment of unproved oil and gas properties	7,870			—			25,564			—
Depreciation, depletion and accretion	33,202			12,392			90,412			28,594
General and administrative	14,766			17,150			46,405			47,573
Total expenses	79,509			42,059			224,559			104,131
OPERATING LOSS	(9,739		)	(14,004		)	(37,293		)	(32,007		)
OTHER INCOME (EXPENSE):
Interest income	3			10			99			14
Interest expense (Note 10)	(14,740		)	(2,268		)	(39,556		)	(6,973		)
Gain (loss) on derivative contracts	(10,151		)	17,341			9,056			16,667
Other income	277			22			460			109
Total other income (expense)	(24,611		)	15,105			(29,941		)	9,817
Income (loss) from continuing operations before income tax benefit and net loss attributable to non-controlling interest	(34,350		)	1,101			(67,234		)	(22,190		)
Income tax benefit	1,936			272			7,229			470
Net loss attributable to non-controlling interest	(49		)	(55		)	(71		)	(172		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	(32,463		)	1,318			(60,076		)	(21,892		)
Income from discontinued operations	—			682			354			2,162
Gain on sale of discontinued operations	—			—			2,224			—
Net income (loss)	(32,463		)	2,000			(57,498		)	(19,730		)
Dividend on preferred stock	(9,820		)	(3,952		)	(22,680		)	(10,017		)
Net loss attributable to common shareholders	$	(42,283	)	$	(1,952	)	$	(80,178	)	$	(29,747	)
Weighted average number of common shares outstanding, basic and diluted	168,897,700			112,619,793			151,225,832			106,651,326
Net loss from continuing operations per share	$	(0.25	)	$	(0.02	)	$	(0.55	)	$	(0.30	)
Net income from discontinued operations per share	$	—		$	—		$	0.02		$	0.02
Net loss per common share, basic and diluted	$	(0.25	)	$	(0.02	)	$	(0.53	)	$	(0.28	)

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

2

MAGNUM HUNTER RESOURCES CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
Net income (loss)	$	(32,463	)	$	2,000		$	(57,498	)	$	(19,730	)
Foreign currency translation	7,245			(14,320		)	6,628			(17,542		)
Unrealized gain (loss) on available for sale investments	(35		)	74			(301		)	82
Total comprehensive loss	$	(25,253	)	$	(12,246	)	$	(51,171	)	$	(37,190	)

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 Stock	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	93	—		—	1		—			—		550			—			—			—			—			—			551
Share based compensation	—	—		—	—		—			—		14,207			—			—			—			—			—			14,207
Issued shares as Employer Match	199	—		—	2		—			—		872			—			—			—			—			—			874
Issued shares of Series D Preferred Stock for cash	—	—		2,700	—		—			135,038		(15,568		)	—			—			—			—			—			119,470
Issued shares of common stock for cash	35,000	—		—	350		—			—		147,979			—			—			—			—			—			148,329
Issued shares of common stock upon warrant exercise	65	—		—	1		—			—		155			—			—			—			—			—			156
Issued shares of common stock upon stock option exercise	843	—		—	8		—			—		1,172			—			—			—			—			—			1,180
Dividends-preferred stock	—	—		—	—		—			—		—			(22,680		)	—			—			—			—			(22,680		)
Issued shares of common stock for acquisition of assets	297	—		—	3		—			—		1,899			—			—			—			—			—			1,902
Issued shares of common stock upon exchange of MHR
Exchangeco Corporation’s exchangeable shares	3,155	(3,155	)	—	32		(32		)	—		—			—			—			—			—			—			—
Purchase of outstanding noncontrolling interest in a subsidary	—	—		—	—		—			—		—			—			—			—			—			(497		)	(497		)
Issued common units of Eureka Hunter Holdings for asset acquisition	—	—		—	—		—			—		—			—			—			—			—			12,453			12,453
Shares Returned to Treasury from KSOP	—	—		—	—		—			—		—			—			—			(604		)	604			—			—
Net loss	—	—		—	—		—			—		—			(57,498		)	—			—			—			71			(57,427		)
Comprehensive income:	—	—		—	—		—			—		—			—			—			—			—			—			—
Foreign currency translation	—	—		—	—		—			—		—			—			6,628			—			—			—			6,628
Unrealized gain on available for sale securities	—	—		—	—		—			—		—			—			(301		)	—			—			—			(301		)
BALANCE, September 30, 2012	169,455	539		4,138	$	1,695	$	5		$	206,916	$	720,956		$	(220,248	)	$	(6,136	)	$	(1,914	)	$	—		$	14,223		$	715,497

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)

	Nine Months Ended
	September 30,
	2012			2011
Cash flows from operating activities
Net loss	$	(57,498	)	$	(19,730	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Noncontrolling interest	71			172
Depletion, depreciation, and accretion	90,462			28,829
Asset impairment	25,564			—
Share based compensation	14,758			19,922
Cash paid for plugging wells	(101		)	(8		)
Gain on sale of assets	(2,900		)	(640		)
Unrealized loss on derivative contracts	(1,094		)	(17,221		)
Unrealized loss on available for sale securities	301			—
Amortization of deferred financing costs and discount on Senior Notes included in interest expense	10,725			3,045
Deferred taxes	(5,748		)	(470		)
Changes in operating assets and liabilities:
Accounts receivable	(36,984		)	(10,426		)
Inventory	(5,283		)	(3,006		)
Prepaid expenses and other current assets	(1,219		)	(675		)
Accounts payable	(4,592		)	7,968
Revenue payable	8,795			1,943
Accrued liabilities	11,562			554
Net cash provided by operating activities	46,819			10,257
Cash flows from investing activities
Capital expenditures and advances	(360,498		)	(201,618		)
Cash paid in acquisitions, net of cash received of $0 and $2.5 million, respectively	(433,865		)	(78,523		)
Change in deposits	(147		)	(2,837		)
Proceeds from sales of assets	823			9,459
Net cash used in investing activities	(793,687		)	(273,519		)
Cash flows from financing activities
Net proceeds from the sale of common stock	148,329			13,892
Net proceeds from sale of preferred shares	119,469			94,042
Proceeds from sale of Series A preferred units in Eureka Hunter Holdings	128,251			—
Proceeds from exercise of warrants and options	1,336			7,126
Preferred stock dividend paid	(17,536		)	(10,017		)
Principal repayments of debt	(481,557		)	(234,047		)
Proceeds from borrowings on debt	430,977			408,587
Proceeds from issuing Senior Notes	443,971			—
Payment of deferred financing costs	(19,414		)	(8,528		)
Change in other long-term liabilities	335			59
Net cash provided by financing activities	754,161			271,114
Effect of exchange rate changes on cash	(146		)	(231		)
Net increase in cash and cash equivalents	7,147			7,621
Cash and cash equivalents, beginning of period	14,851			554
Cash and cash equivalents, end of period	$	21,998		$	8,175
Supplemental disclosure of cash flow information
Cash paid for interest	$	13,185		$	3,867
Non-cash transactions
Common stock issued for acquisitions	$	1,902		$	345,537
Non-cash consideration received from sale of assets	$	7,706		$	—
Common stock issued as payment of services	$	—		$	779
Accrued capital expenditures	$	10,722		$	12,412
Common stock issued for 401k matching contribution	$	874		$	—
Eureka Hunter Holdings Series A preferred dividends paid in kind	$	1,658		$	—
Eureka Hunter Holdings Series A common units issued for an acquisition	$	12,453		$	—
Debt assumed in acquisition	$	—		$	71,895
Exchangeable common stock issued for acquisition of NuLoch Resources	$	—		$	31,642
Warrants issued for payment of common stock dividends	$	—		$	6,695
Warrants issued for payment of dividends on MHR Exchangeco Corporation exchangeable shares	$	—		197

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 statement 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.  The year-end condensed balance sheet data were derived from audited financial statements, but do not include all disclosures required by accounting principles generally accepted in the United States of America.  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.

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 September 30, 2012 was 29,215,585.  There were 26,284,178 potentially dilutive securities outstanding at September 30, 2011.  We did not include the potentially dilutive securities in our calculation of diluted loss per share during any of the 2012 or 2011 periods presented herein, because to include them would have been anti-dilutive due to our net loss during those periods.

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

	September 30,
	2012	2011
	(in thousands)
Warrants	13,445	13,532
Restricted shares granted, not yet issued	—	25
Common stock options	15,770	12,727

NOTE 2 — LIQUIDITY

At September 30, 2012, we had (i) cash and cash equivalents of $22.0 million, of which $3.9 million was held by Eureka Hunter Holdings, LLC or its subsidiaries (which are unrestricted subsidiaries under our senior revolving credit facility) and was only available for use by Eureka Hunter Holdings, LLC or its subsidiaries; and (ii) a working capital deficit of $62.1 million. 

We utilize our credit agreements, as described in Note 10, to fund a portion of our operating and capital needs.  Under our senior revolving credit facility, our borrowing base at September 30, 2012 was $260.0 million, and our remaining borrowing capacity was $85.0 million on September 30, 2012.  Pursuant to the terms of the latest amendment of our senior revolving credit facility, our borrowing base was increased to $375.0 million as of November 6, 2012, an increase of $115.0 million.  As of November 12, 2012, we had over $150.0 million of liquidity, including borrowing capacity under this facility and cash on hand.

For the three months ended September 30, 2012, we had net loss attributable to common shareholders of $42.3 million and an operating loss from continuing operations of $9.7 million, including a $7.9 million impairment of unproved oil and gas properties.  For the nine months ended September 30, 2012, we had net loss attributable to common shareholders of $80.2 million and an operating loss from continuing operations of $37.3 million, including a $25.6 million impairment of unproved oil and gas properties.

At September 30, 2012, we were in compliance with all of our covenants, as amended, contained in our senior revolving credit facility, our senior notes indenture and the Eureka Hunter Pipeline, LLC credit facilities, as described in Note 10.

We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) borrowing capacity available under our credit facilities 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, as amended, and undertake our capital expenditure program for the twelve months ending September 30, 2013.

6

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 Magnum Hunter Services, LLC.  We have consolidated our 87.5% controlling interest in PRC Williston, LLC as of September 30, 2012, and our 65.6% controlling interest in Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”), and its wholly owned subsidiaries, Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline”), TransTex Hunter, LLC, and Eureka Hunter Land, LLC, as of September 30, 2012, with noncontrolling interests recorded for the outside interests in those majority owned subsidiaries. The consolidated financial statements also reflect the interests 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 our oil and gas properties.

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, might 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 expense for this entity as discontinued operations.

Inventory

Inventory is made up of $11.3 million and $4.5 million of materials and supplies as of September 30, 2012 and December 31, 2011, respectively. The Company’s materials and supplies inventory primarily comprises sand used in the Appalachian region and parts for equipment servicing. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. Any reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets are written off to other income (expense) in the accompanying consolidated statements of operations.  Inventory was condensed and reported in prepaids and other assets as of December 31, 2011 and has been reclassified to inventory to correspond with current-year classifications.

7

Property and Equipment

Our oil and gas properties and gas gathering and other equipment comprised the following:

	September 30, 2012			December 31, 2011
	(in thousands)
Mineral interests in properties:
Oil and natural gas properties	$	1,709,853	��	$	1,027,436
Accumulated depletion	(132,353		)	(64,471		)
Net oil and natural gas properties	$	1,577,500		$	962,965
Gas gathering and other equipment	$	176,061		$	120,929
Accumulated depreciation	(12,291		)	(8,760		)
Net gas gathering and other equipment	$	163,770		$	112,169

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 September 30, 2012, Energy Hunter Securities, Inc. had net capital of $56,000 and aggregate indebtedness of $32,000. Magnum Hunter has entered into a letter of intent with MLV & Co. to form a joint venture to operate the business of Energy Hunter Securities, Inc., whereby MLV & Co. would own 75% and the Company would own 25% of the joint venture. The Company anticipates that this transaction will close no later than the first quarter of 2013.

Sentra Corporation (“Sentra”) owns and operates distribution systems for retail sales of natural gas in south central Kentucky. Sentra is a public utility whose gas sales are regulated by the Kentucky Public Service Commission.  We account for Sentra’s 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 had gas transmission, compression and processing revenue of $369,000 for the three and nine months ended September 30, 2012 and $61,000 for the three and nine months ended September 30, 2011, which included gas utility sales from Sentra’s regulated operations.  Sentra had property and equipment of $192,000, net of $90,000 of depreciation, and accounts payable of $63,000 as of September 30, 2012.

Other Comprehensive Income (Loss)

The functional currency of our operations in Canada, the only country in addition to the United States in which we operate, is the Canadian dollar.  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 shareholders’ equity on our consolidated balance sheets. During the nine months ended September 30, 2012 and 2011, we recognized a translation gain of $6.6 million and a loss of $17.5 million, respectively. As the Company considers undistributed earnings in Canada to be indefinitely reinvested in Canada, there is no tax effect of the translation gain.

Impairment

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 writing off the value of the property to impairment expense.  We recorded $7.9 million of impairment during the three months ended September 30, 2012, comprising $3.0 million in our Williston Basin region and $4.9 million in our Canadian region, due to write offs of lease acreage which was deemed non-prospective.  We recorded $25.6 million in unproved property impairment during the nine months ended September 30, 2012, comprising $5.0 million in our Appalachian region, $12.1 million in our Williston Basin region, and $8.5 million

8

in our Tableland region, all due to write-offs of lease acreage which was deemed non-prospective.  We recorded no impairments to unproved oil and gas properties for the three or nine months ended September 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 or whenever interim impairment indicators arise.  Goodwill of $30.6 million was recorded related to 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 September 2011, the FASB issued ASU No. 2011-08 Intangibles - Goodwill and Other (Topic 350) (“ASU 2011-08”).  ASU 2011-08 amended FASB ASC Topic 350 to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU 2011-08 became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 did not impact the carrying value of the Company’s goodwill.

In December 2011, the FASB issued ASU No. 2011-11, 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.

In July 2012, the FASB issued ASU No. 2012-02, an amendment to the accounting guidance for testing indefinite-lived intangible assets for impairment.  The amendment allows for the assessment of qualitative factors in determining whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired before performing any quantitative tests.  The amendment also allows for the assessment of qualitative factors to be bypassed for any indefinite-lived intangible asset to allow for direct performance of the quantitative impairment test.  This guidance will become effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012.  The Company does not expect the adoption of this guidance will have a material impact on its consolidated financial statements.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2011 annual report on Form 10-K.

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

9

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 at September 30, 2012 and December 31, 2011:

Level 1 Classification:

Available for Sale Securities

At September 30, 2012 and December 31, 2011, the Company held common stock of companies publicly traded on the TSX Venture Exchange and the NYSE MKT (formerly NYSE Amex) 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 September 30, 2012 and December 31, 2011, the Company had commodity derivative financial instruments in place.  The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting.  Changes in fair value of derivative instruments subsequent to the initial measurement are recorded as other income (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 indices, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange.  See Note 7 —Derivatives, for additional information.

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

Level 3 Classification:

Preferred Stock Embedded Derivative

The preferred stock embedded derivative was valued using the “with and without” analysis in a simulation model. The key inputs used in the model were a volatility range of 20% to 30%, credit spread range between 15% to 19%, and an initial fair value of Eureka Hunter Holdings of $400.0 million.

Convertible Security Embedded Derivative

The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated converison feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal, LLC (See Note 7).  The convertible security embedded derivative was valued using a Black Scholes model valuation of the conversion option.

The key inputs used in the Black Scholes option pricing model were as follows:

	September 30, 2012
Life	5 Year
Risk-free interest rate	11.00		%
Estimated volatility	40		%
Dividend	—
Stock price at end of period	$	2.27

The following table presents a reconciliation of the derivative assets and liabilities measured at fair value using significant unobservable inputs for the nine month period ended September 30, 2012:

	Preferred Stock			Convertible Security
	Embedded Derivative			Embedded Derivative
	(in thousands)
Fair value at December 31, 2011	$	—		$	—
Issuance of embedded derivative	(45,420		)	405
Increase in fair value recognized in other income (expense)	3,420			185
Fair value as of September 30, 2012	$	(42,000	)	$	590

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

	Fair Value Measurements on a Recurring Basis
	September 30, 2012(in thousands)
	Level 1		Level 2		Level 3
Available for sale securities	$	196	$	—	$	—
Commodity derivative assets	$	—	$	3,307	$	—
Convertible security derivative assets	—		—		590
Total assets at fair value	$	196	$	3,307	$	590
Derivatives and other current liabilities	$	—	$	4,772	$	—
Commodity and preferred stock embedded derivatives liabilities	—		6,605		42,000
Total liabilities at fair value	$	—	$	11,377	$	42,000

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	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	$	—

Other Fair Value Measurements

The carrying amounts reported in the condensed consolidated balance sheet for cash and equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.  The fair value hierarchy for these items is Level 1.

The carrying value of our senior revolving credit facility approximates fair value as it is subject to short-term floating interest rates that approximate the rates available to us for those periods.  The fair value hierarchy for our senior revolving credit facility is Level 1.

The fair value of our senior notes is based on quoted market prices.  The estimated fair value of our senior notes as of September 30, 2012 and December 31, 2011 was $443.2 million and $0, respectively.  The fair value hierarchy for our senior notes is Level 2 (quoted prices for identical assets in active markets).

The fair value of Eureka Hunter Pipeline’s second lien term loan is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate.  The credit spread is the Company’s default or repayment risk.  The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt.  The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company.  Eureka Hunter Pipeline’s second lien term loan is valued using an income approach and classified as Level 3 in the fair value hierarchy.

The Company uses available market data and valuation methodologies to estimate the fair value of debt.  The carrying amounts and fair values of long-term debt are as follows:

	September 30, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes	$	444,100	$	443,250	$	—	$	—
Senior revolving credit facility	$	175,000	$	175,000	$	142,000	$	142,000
Second lien term loan (Eureka Hunter Pipeline)	$	50,000	$	57,063	$	31,000	$	34,407

NOTE 5 — ACQUISITIONS

The Company has recognized $1.1 million and $3.6 million of expenses related to acquisition costs in its general and administrative expenses for the three and nine months ended September 30, 2012, respectively.

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Utica Shale Assets 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 in cash.  The Utica acreage consists of approximately 15,558 gross (12,186 net) acres.

Eagle Operating Assets 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 Operating”), an unrelated third party, 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 following table summarizes the purchase price and the fair values of the net assets acquired from Eagle Operating at the date of acquisition based on our preliminary determination as of September 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	$	1,902
Cash	50,974
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

TransTex Gas Services, LP Assets 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, closed on their purchase of certain assets of TransTex Gas Services, LP (“TransTex”), a related third party, under an 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, which is associated with the Company’s midstream operating segment, to be deductible for tax purposes.  The purpose of the acquisition was to complement the Company’s midstream assets.  The total purchase price paid for the acquired assets was $58.5 million, comprised of $46.0 million in cash and 622,641 Eureka Hunter Holdings Class A Common Units

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representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million.  The value of the common units transferred as partial consideration for the acquisition was determined utilizing a discounted future cash flow analysis.  The preliminary valuations of the assets acquired are set forth below.

The following table summarizes the purchase price and the fair values of the net assets acquired from TransTex at the date of acquisition based on our preliminary determination as of September 30, 2012 (in thousands):

Fair value of total purchase price:
Cash	$	46,047
Eureka Hunter Holdings Class A Common Units	12,453
Total	$	58,500
Amounts recognized for assets acquired and liabilities assumed:
Working capital	$	525
Equipment and other fixed assets	15,575
Other assets	1,306
Goodwill	30,602
Intangible assets (Note 8)	10,492
Total	$	58,500

Gary Evans, our Chairman and CEO, held a small limited partnership interest in TransTex, and participated in the purchase of certain Eureka Hunter Holdings Class A Common Units offered to all limited partners of TransTex in connection with the acquisition. See Note 13 - Related Party Transactions below.

Baytex Energy USA Assets Acquisition

On May 22, 2012, the Company, through its wholly owned subsidiary, Bakken Hunter, LLC, closed on the acquisition of certain Williston Basin assets of Baytex Energy USA, Ltd. (“Baytex Energy USA”), an affiliate of Baytex Energy Corporation, an unrelated third party, for a total purchase price of $312.0 million.  The purpose of the acquisition was to significantly increase the Company’s ownership interest in existing mineral leases in a key shale play where the Company plans to increase its drilling activities. To a lesser extent, proved reserves were added attributable to the acquired properties. The acquired assets include all of Baytex Energy USA’s non-operated working interest in oil and gas properties and wells located in Divide and Burke Counties, North Dakota, within an area subject to an operating agreement among Samson Resources Company, as operator, Baytex Energy Corporation, and Williston Hunter, Inc., a wholly owned subsidiary of Magnum Hunter.  The preliminary valuations of the assets acquired are set forth below.

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 September 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

The following summarizes the revenue and operating income (loss) from the acquisitions included in our consolidated statement of operations for the nine months ended September 30, 2012:

	For the nine months ended September 30,2012
	Revenues		Operating Income (Loss)
	(in thousands)
Eagle Operating Assets	$	3,721	$	(714	)
TransTex Assets	$	4,809	$	85
Baytex Energy USA Assets	$	9,934	$	3,648

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The following unaudited summary, prepared on a pro forma basis, presents the results of operations for the nine months ended September 30, 2012, and the three and nine month periods ended September 30, 2011, as if the acquisitions of the  Eagle Operating assets, the Baytex Energy USA assets, the TransTex assets, and the Eureka Hunter Holdings 8% Series A Preferred Units transaction (See Note 12 — Shareholders’ Equity and Redeemable Preferred Stock) 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 dividends.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of January 1, 2011, nor are they necessarily indicative of future consolidated results.

	Three Months Ended September 30,			Nine Months Ended September 30,			Nine Months Ended September 30,
	2011			2012			2011
	(in thousands, except per-share data)
Total revenue	$	37,684		$	201,129		$	100,863
Total expenses	50,258			237,397			127,699
Operating loss	(12,574		)	(36,268		)	(26,836		)
Interest, Gain (loss) on derivatives, and other expenses, net	7,184			(33,636		)	(13,017		)
Net loss attributable to Magnum Hunter Resources Corporation	(5,390		)	(69,904		)	(39,853		)
Dividends on preferred stock	(6,088		)	(24,002		)	(16,425		)
Net loss attributable to common stockholders	$	(11,478	)	$	(93,906	)	$	(56,278	)
Loss per common share, basic and diluted	$	(0.08	)	$	(0.56	)	$	(0.34	)

NOTE 6 — DISCONTINUED OPERATIONS

On February 17, 2012, the Company, through its wholly owned subsidiary, Triad Hunter, LLC, sold 100% of its equity ownership interest in Hunter Disposal, LLC, to an affiliate of GreenHunter Energy, Inc., for total consideration of $9.9 million, comprised of 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, Inc. common stock based on the conversion price of $2.50 per share. The Company has recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with fair market value of $590,000. The cash proceeds from the sale were adjusted downward for changes in working capital to reflect the effective date of the sale of December 31, 2011. GreenHunter Energy, Inc. is a related party as described in Note 13. The operating results of Hunter Disposal, LLC, for the nine months ended September 30, 2012 and the three and nine months ended September 30, 2011, have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below:

	Three Months Ended September 30,			Nine Months Ended September 30,			Nine Months Ended September 30,
	2011			2012(1)			2011
	(in thousands)
Revenues	$	4,386		$	2,400		$	7,978
Operating expenses	(3,699		)	(2,047		)	(5,800		)
Other income (expense)	(5		)	1			(16		)
Gain on sale of discontinued operations	—			2,224			—
Income from discontinued operations	$	682		$	2,578		$	2,162

(1)Represents operations from January 1, 2012 through February 17, 2012, the date of sale.

NOTE 7 — 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 natural gas and 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 September 30, 2012, we had the following derivative instruments in place:

			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Collars	Oct 2012 - Dec 2012	11,910	$4.58 - $6.42
	Jan 2013 - Dec 2013	12,500	$4.50 - $5.96
Swaps	Oct 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	Oct 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)	Oct 2012 - Dec 2012	50	$55.00 - $75.00 - $108.00
	Jan 2013 - Dec 2013	2,000	$60.63 - $80.00 - $100.00
	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Three-way collars (2)	Jan 2013 - Dec 2013	763	$65.00 - $91.25 - $101.25
Swaps	Oct 2012 - Dec 2012	3,500	$90.55
	Jan 2013 - Dec 2013	1,000	$91.46
Ceilings sold (call)	Oct 2012 - Dec 2012	688	$100.30
Ceilings purchased (call)	Oct 2012 - Dec 2012	688	$91.25
Floors sold (put)	Oct 2012 - Dec 2012	2,290	$80.00
	Jan 2013 - Dec 2013	1,438	$65.00
	Jan 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00
Floors purchased (put)	Oct 2012 - Dec 2012	2,443	$94.06

(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.

Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, UBS AG London Branch, Deutsche Bank AG London Branch, Citibank, N.A., and J. Aron & Company 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 or their affiliates are participants in our senior revolving credit facility, and the collateral for the outstanding borrowings under our senior revolving credit facility is used as collateral for our commodity derivatives with those counterparties.

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At September 30, 2012, the Company has preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of our Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC. See Note 12 — Shareholders’ Equity and Redeemable Preferred Stock, for more information.

At September 30, 2012, the Company also has a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note received as partial consideration in the sale of Hunter Disposal, LLC.

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

		Gross Derivative Assets				Gross Derivative Liabilities
Derivatives not designated as hedging		September 30,		December 31,		September 30,			December 31,
instruments	Balance Sheet Classification	2012		2011		2012			2011
		(in thousands)
Commodity
	Current Assets - Derivatives	$	3,307	$	5,732	$	—		$	—
	Derivatives and other long term assets	—		1,192		—			—
	Derivatives and other current liabilities	—		—		(4,772		)	(5,800		)
	Derivatives and other long term liabilities	—		—		(6,605		)	(6,112		)
Total Commodity		$	3,307	$	6,924	$	(11,377	)	$	(11,912	)
Financial
	Convertible security embedded derivative	$	590	$	—	$	—		$	—
	Commodity and preferred stock embedded derivatives	—		—		46,770			—
Total financial		$	590	—		$	46,770		$	—

The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts as of the dates indicated:

	Three Months Ended September 30, 2012 (in thousands)			Nine Months Ended September 30, 2012 (in thousands)
Realized gain	$	2,224		$	7,962
Unrealized loss	(12,375		)	1,094
Net gain (loss)	$	(10,151	)	$	9,056

	Three Months Ended September 30, 2011 (in thousands)			Nine Months Ended September 30, 2011 (in thousands)
Realized loss	$	(45	)	$	(554	)
Unrealized gain	17,386			17,221
Net gain	$	17,341		$	16,667

NOTE 8 — INTANGIBLE ASSETS

Intangible assets consist primarily of the fair value of the acquired gas gathering and processing contracts and customer relationships in the TransTex Gas Services, LP assets acquisition.  The intangible assets were valued at fair value using a discounted cash flow model with a discount rate of 13%.  Such assets will be amortized over the weighted average term of the contracts of 4.27 years.  The customer relationships are being amortized on a straight line basis with a 12.5 year life.

The following table summarizes our preliminary purchase price allocation to intangible assets:

	September 30,			December 31,
	2012			2011
	(in thousands)
Intangible assets at beginning of the period	$	—		$	—
Additions through acquisition	10,492			—
Total intangible assets	$	10,492		—
Accumulated amortization	(1,007		)	—
Intangible assets, net of accumulated amortization	$	9,485		$	—

NOTE 9 — 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.

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The following table summarizes the Company’s asset retirement obligation activities during the nine month period ended September 30, 2012:

	Nine Months Ended
	September 30, 2012
	(in thousands)
Asset retirement obligation at beginning of period	$	20,584
Assumed in acquisitions	2,232
Liabilities incurred	321
Liabilities settled	(39		)
Accretion expense	1,225
Revisions in estimated liabilities	67
Effect of foreign currency translation	43
Asset retirement obligation at end of period	24,433
Less: current portion	(1,600		)
Asset retirement obligation at end of period	$	22,833

NOTE 10 — LONG-TERM DEBT

Long-term debt at September 30, 2012 and December 31, 2011 consisted of the following:

	September 30, 2012			December 31, 2011
	(in thousands)
Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $5.9 million	$	444,100		$	—
Various equipment and real estate notes payable with maturity dates January 2015 - April 2021, interest rates of 4.25% - 5.70%	14,893			17,745
Eureka Hunter Pipeline, LLC second lien term loan due August 16, 2018, interest rate of 12.5%	50,000			31,000
Senior revolving credit facility due April 13, 2016, interest rate of 3.48% at September 30, 2012 and 3.55% at December 31, 2011	175,000			142,000
Second lien term loan due October 13, 2016, interest rate of 8% (1)	—			100,000
	$	683,993		290,745
Less: current portion	(3,672		)	(4,681		)
Total long-term debt obligations, net of current portion	$	680,321		286,064

(1)The Company’s second lien term loan was paid in full in May 2012 in connection with the issuance of the Company’s Senior Notes.

The following table presents the scheduled or expected approximate annual maturities of debt:

	(in thousands)
2012	$	939
2013	3,704
2014	2,143
2015	4,204
Thereafter	673,003
Total	$	683,993

Senior Notes Payable

On May 16, 2012, the Company successfully completed the issuance of $450.0 million aggregate principal amount of its 9.75% Senior Notes due May 15, 2020 for total proceeds of $432.2 million net of issuing costs of $11.8 million, resulting in a discount of $6.0 million.  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.

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The Senior Notes were issued at a price of 98.646% of their face amount and provided net proceeds to the Company, after fees and expenses, of $432.2 million.  The Company used 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 Energy USA, Ltd., which closed on May 22, 2012, (ii) to pay off all amounts outstanding under the Company’s term loan, (iii) to repay outstanding debt under the Company’s senior revolving credit facility, (iv) to increase the Company’s 2012 upstream capital budget from $150.0 million to $325.0 million (92% of capital budget focused on Williston Basin and Eagle Ford Shale) 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 subsidiary guarantors party thereto, 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 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 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 or 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.

Eureka Hunter Pipeline Credit Facilities

Eureka Hunter Pipeline’s First Lien Credit Agreement provides for a revolving credit facility in an aggregate principal amount of up to $100.0 million (with an initial committed amount of $25.0 million), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline and its subsidiaries.  Availability under the revolving credit facility is subject to satisfaction of certain financial covenants that are tested on a quarterly basis.  Currently, the revolving credit facility is not available, although it is anticipated that the revolving credit facility will be available with the reporting of the first quarter 2013 financial results. The revolving credit facility has a maturity date of August 16, 2016.

Eureka Hunter Pipeline’s Second Lien Term Loan Agreement provides for a $50.0 million term loan, secured by a second lien on substantially all of the assets of Eureka Hunter Pipeline and its subsidiaries.  The entire $50.0 million of the term loan must be drawn before any portion of the revolver is drawn.  The term loan has a maturity date of August 16, 2018.  On August 16, 2011, Eureka Hunter Pipeline drew $31.0 million under the term loan, $21.0 million of which was distributed to the Company to repay existing corporate indebtedness.  As of September 30, 2012, the principal amount outstanding under the term loan was $50.0 million. Both the revolver and the term loan are non-recourse to Magnum Hunter.

On April 2, 2012, Eureka Hunter Holdings closed on the acquisition of certain assets of TransTex.  The working capital and EBITDA associated with the acquired assets are included in the covenant determinations under Eureka Hunter Pipeline’s credit facilities going forward based on amendments to such credit facilities.

On June 29, 2012, Eureka Hunter Pipeline entered into a Third Amendment to its 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, unless such First Lien Credit Agreement is amended in a manner satisfactory to the lenders under the Second Lien Term Loan Agreement.  The Company paid $500,000 as consideration for the Third Amendment. These amendments were necessary primarily due to the delay in the completion of MarkWest’s Mobley gas processing plant.

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At September 30, 2012, we were in compliance with all of our covenants, as amended, contained in the Eureka Hunter Pipeline credit facilities.

Senior Revolving Credit Facility

Our senior revolving credit facility is evidenced by the Second Amended and Restated Credit Agreement among the Company, the subsidiary guarantors party thereto and the lenders party thereto. The senior revolving credit facility is an asset-based, secured credit facility governed by a semi-annual borrowing base redetermination derived from the Company’s proved crude oil and natural gas reserves.

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 under the senior revolving credit facility from $200 million to $235 million.

On May 2, 2012, the Company entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement.  Pursuant to the Sixth Amendment, the borrowing base under our senior revolving credit facility was increased from $235.0 million to $275.0 million, then was decreased from $275.0 million to $187.5 million upon the issuance of the $450.0 million of 9.75% Senior Notes, and then was increased from $187.5 million to $212.5 million upon the closing of the acquisition of assets from Baytex Energy USA.

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

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

On October 29, 2012, the Company entered into the Tenth Amendment to the Second Amended and Restated Credit Agreement.  See Note 17 — Subsequent Events, for more information.

On November 7, 2012, the Company entered into the Eleventh Amended to the Second Amended and Restated Credit Agreement.  See Note 17 — Subsequent Events, for more information.

Interest expense for the three and nine months ended September 30, 2012 and 2011 includes amortization of deferred financing costs of $0.6 million, $6.4 million, $0.3 million, and $3.0 million, respectively.

NOTE 11 — SHARE-BASED COMPENSATION

Under our 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 3,159,143 shares have been issued as of September 30, 2012.

We recognized share-based compensation expense of $2.4 million and $14.8 million for the three and nine months ended September 30, 2012, and we recognized $7.9 million and $19.9 million for the three and nine months ended September 30, 2011.

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A summary of common stock option and stock appreciation rights activity for the nine months ended September 30, 2012 and 2011 is presented below:

	Shares				Weighted Average Exercise Price
	2012		2011		2012	2011
Outstanding at beginning of period	12,566,199		12,779,282		5.64	2.65
Granted	4,853,750		5,492,792		6.05	7.82
Exercised	(843,075	)	(5,284,250	)	1.40	0.89
Cancelled	(806,575	)	(260,575	)	7.24	2.73
Outstanding at end of period	15,770,299		12,727,249		5.91	5.61
Exercisable at end of period	8,959,338		5,098,125		5.79	3.97

A summary of the Company’s non-vested common stock options and stock appreciation rights as of September 30, 2012 and 2011 is presented below.

	2012		2011
Non-vested at beginning of period	5,650,782		5,215,532
Granted	4,853,750		5,492,792
Vested	(3,005,435	)	(2,820,125	)
Cancelled	(688,136	)	(259,075	)
Non-vested at end of period	6,810,961		7,629,124

Total compensation cost related to the non-vested common stock options was $15.1 million and $14.2 million as of September 30, 2012 and 2011, respectively.  The unrecognized cost at September 30, 2012, is expected to be recognized over a weighted-average period of 2.10 years.  At September 30, 2012, the weighted average remaining contract life was 6.33 years.

Total unrecognized compensation cost related to non-vested, restricted shares amounted to $462,000 and $870,000 as of September 30, 2012 and 2011, respectively.  The unrecognized cost at September 30, 2012, is expected to be recognized over a weighted-average period of 1.17 years.

The assumptions used in the fair value method calculation for the nine months ended September 30, 2012, are disclosed in the following table:

	Nine Months Ended September 30,
	2012 (1)
Weighted average fair value per option granted during the period (2)	$3.76
Assumptions (3) :
Weighted average stock price volatility	83.00%
Weighted average risk free rate of return	0.77%
Weighted average expected term	4.59 years

(1)Our estimated future forfeiture rate is zero.

(2)Calculated using the Black-Scholes fair value based method for service and performance based grants and the Lattice Model for market based grants.

(3)The Company does not pay dividends on its common stock.

NOTE 12 —SHAREHOLDERS’ EQUITY AND REDEEMABLE PREFERRED STOCK

Common Stock

During the nine months ended September 30, 2012, the Company issued 92,775 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.

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During the nine months ended September 30, 2012, the Company issued 65,216 shares of the Company’s common stock upon the exercise of warrants for total proceeds of approximately $156 thousand.

During the nine months ended September 30, 2012, the Company issued 843,250 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 nine months ended September 30, 2012, the Company issued 3,154,996 shares of the Company’s common stock upon exchange of 3,154,996 exchangeable shares issued by MHR Exchangeco Corporation in connection with the Company’s acquisition of NuLoch Resources, Inc. in May 2011.

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.

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 offering expenses, were approximately $148.3 million.

On August 20, 2012, the Company issued 199,055 shares of the Company’s common stock as a matching contribution to the Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan.

Unearned Common Stock in Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan

On August 13, 2012, the Company rescinded the loan of 153,300 Magnum Hunter common shares to the Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan (the “Plan”) and the common shares were returned to the Company and held in treasury. The loan was rescinded to correct a mutual mistake by the parties in connection with the Company’s original acquisition of the shares through open market purchases. The Company has agreed that 153,300 shares of the Company’s common stock will either be (i) offered for sale to the participants in the Plan at a price not to exceed the lesser of $3.94 per share (the basis of these treasury shares) or the fair market value of the shares on the date of the sale, or (ii) contributed to the Plan as one or more discretionary matching contributions.  Such sale or contribution shall be made at such time or times as determined by the trustee of the Plan, except to the extent that the Company elects prior to that time to contribute all or a part of such shares as a discretionary matching contribution.

Non-controlling Interest

During the nine months ended September 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 based on fair value at the date of acquisition.

Series D Cumulative Preferred Stock

During the nine months ended September 30, 2012, the Company issued an aggregate of 2,700,767 shares of our 8.0% Series D Cumulative Perpetual Preferred Stock with a liquidation preference of $50.00 per share for cumulative net proceeds of approximately $119.5 million, which included various offering expenses of approximately $3.1 million.  The 2,700,767 shares of our 8.0% Series D Cumulative Perpetual Preferred Stock issued during the nine months ended September 30, 2012 included (i) 1,650,767 shares issued under an At the Market (“ATM”) sales agreement for net proceeds of approximately $74.9 million, which included approximately $1.5 million of offering and underwriting fees and (ii) 1,050,000 shares issued pursuant to an underwritten public offering on September 7, 2012 at a price of $44.00 per share for net proceeds of approximately $44.6 million, which included approximately $1.6 million of underwriting discounts, commissions and offering expenses.

The 8.0% Series D Cumulative Perpetual 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 its liquidation preference of $50.00 per share or in certain circumstances, prior to such date as a result of a change in control.

Eureka Hunter Holdings Class A Common Units

On April 2, 2012, Eureka Hunter Holdings, a majority owned subsidiary, issued 622,641 Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million, as partial consideration for the assets acquired from TransTex.  The value of the units transferred as partial consideration for the acquisition was determined utilizing a discounted future cash flow analysis.

Eureka Hunter Holdings 8% Series A Preferred Units

On March 21, 2012, Eureka Hunter Holdings entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with Magnum Hunter and Ridgeline Midstream Holdings, LLC (“Ridgeline”), 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 “Series A Preferred Units”).

During the nine months ended September 30, 2012, Eureka Hunter Holdings issued 6,590,000 Series A Preferred Units to Ridgeline

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for net proceeds of $129.2 million, net of transaction costs.  The Series A Preferred Units sold represented 31.3% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.  Eureka Hunter Holdings pays 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 period from March 21, 2012 through March 21, 2013 in the form of “paid-in-kind” units and up to 50% during the period from June 30, 2013 through March 31, 2014.  The Series A Preferred Units can be converted into Class A Common Units of Eureka Hunter Holdings upon demand by Ridgeline at any time or by Eureka Hunter Holdings upon the consummation of a qualified initial public offering, provided that Eureka Hunter Holdings converts no less than 50% of the Series A Preferred Units into Class A Common Units at that time.  The conversion rate is 1:1, which may be adjusted from time to time based upon certain anti-dilution and other provisions.  Eureka Hunter Holdings can redeem all outstanding Series A Preferred Units at their liquidation preference, which involves a specified IRR hurdle, 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 equal to the higher of the as-converted value and a specified internal investment rate of return calculation.  The Series A Preferred Units are recorded as temporary equity because a forced redemption by the holders of the preferred units is outside the control of Eureka Hunter Holdings.

We have evaluated the Series A Preferred Units and determined that they should be considered a “debt host” and not an “equity host”. This evaluation is necessary to determine if any embedded features require bifurcation and, therefore, would be required to be accounted for separately as a derivative liability. Our analysis followed the “whole instrument approach,” which compares an individual feature against the entire preferred instrument that includes that feature. Our analysis was based on a consideration of the economic characteristics and risks of the preferred unit and, more specifically, evaluated all of the stated and implied substantive terms and features of such unit, including (1) whether the preferred unit included redemption features; (2) how and when any redemption features could be exercised; (3) whether the holders of preferred units were entitled to dividends; (4) the voting rights of the preferred unit; and (5) the existence and nature of any conversion rights. As a result of our determination that the preferred unit is a “debt host,” we determined that the embedded conversion option, redemption options and other features of the preferred units do require bifurcation and separate accounting as embedded derivatives. The fair value of the embedded features were determined to be $22.1 million, $15.4 million, and $7.9 million at the issuance dates of March 21, 2012, April 2, 2012, and June 20, 2012, respectively, which were bifurcated from the issuance values of the Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was determined to be $42.0 million in the aggregate at September 30, 2012.

During the nine months ended September 30, 2012, Eureka Hunter Holdings issued 82,892 Series A Preferred Units as payment of $1.7 million in distributions paid in kind to holders of the Series A Preferred Units.

As a result of the initial investment by Ridgeline in the Series A Preferred Units, the Company recorded a non-controlling interest in Eureka Hunter Holdings and its subsidiaries.

NOTE 13 — 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 recorded in general and administrative expense totaled $0 and $81,000 for the three and nine months ended September 30, 2012, respectively and $160,000 and $388,000 for the three and nine months ended September 30, 2011, respectively.

We obtained accounting services and use of office space from GreenHunter Energy, Inc., an entity for which Mr. Evans is an officer, director and major shareholder, for which Ronald Ormand, our Chief Financial Officer and a director, is also a director, and for which David Krueger, our Senior Vice President and our former Chief Accounting Officer, is an officer.  This agreement terminated in 2011 and all accounting services are now controlled by Magnum Hunter personnel.  Professional services expenses totaled $0 for the three and nine months ended September 30, 2012, and $66,000 and $107,000 for the three and nine months ended September 30, 2011, respectively.

During the nine months ended September 30, 2012 and 2011, the Company paid rent of $23,000 and $23,000, 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 2012.

During the nine months ended September 30, 2012, Eagle Ford Hunter, Inc., Triad Hunter, LLC, 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 $244,000 and approximately $875,000 for the three and nine months ended September 30, 2012, respectively, and $230,000 for the three and nine months ended September 30, 2011.  As of September 30, 2012, our net accounts payable to GreenHunter Energy, Inc. were $2,000 for these leases recorded in accounts payable.  Additionally, these companies regularly obtain services from GreenHunter Energy, Inc. for water disposal.  The Company believes that such services are provided at competitive market rates and are comparable to or more attractive than rates that could be obtained from unaffiliated third party suppliers of such services.  Disposal charges recorded in lease operating expenses totaled $618,000 and $1.6 million for the three and nine months ended September 31, 2012.

During the nine months ended September 30, 2012, Alpha Hunter Drilling, LLC, a wholly owned subsidiary of the Company, performed drilling operations for GreenHunter Energy, Inc. for a fee.  Drilling revenues totaled $359,000 for the three and nine months ended September 30, 2012, and our net accounts receivable from GreenHunter Energy, Inc. for these services were $359,000 as of September 30, 2012 recorded in accounts receivable.

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 an independent special committee of the Company.  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 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.  The Company has recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with fair market value of $590,000.  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.  The Company has recorded interest income as a result of the note receivable from GreenHunter Energy, Inc, in the amounts of $55,000 and $110,000 for the three and nine months ended September 30, 2012, respectively.  As a result of this transaction, the Company has an investment in GreenHunter Energy, Inc. that is included in derivatives and other long term assets and recorded under the equity method.  The loss related to this investment was $97,000 for the three months ended September 30, 2012, and $299,000 for the nine months ended September 30, 2012.

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Mr. Evans, our Chairman and Chief Executive Officer, was a 4.0% limited partner in TransTex Gas Services, LP, which limited partnership received total consideration of 622,641 Class A Common Units of Eureka Hunter Holdings and cash of $46.0 million upon the Company’s acquisition of certain of its assets.  This includes units issued in accordance with the agreement of Eureka Hunter Holdings and TransTex to provide the limited partners of TransTex the opportunity to purchase additional Class A Common Units of Eureka Hunter Holdings 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.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

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

NOTE 15 — SEGMENT REPORTING

The Oilfield Services, Midstream, U.S. Upstream and Canadian Upstream segments represent 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 segments are organized and operate to explore for and produce crude oil and natural gas.  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 subsidiaries of the Company. The Midstream segment operates a network of pipelines that gather natural gas.

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.

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

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	For the Three Months Ended September 30, 2012
	(in thousands)
	Corporate Unallocated			U.S. Upstream			Canadian Upstream			Midstream			Oilfield Services			Intersegment Eliminations			Total
Oil and gas sales	$	—		$	53,362		$	9,286		$	—		$	—		$	—		$	62,648
Gas gathering and processing	—			—			—			2,529			—			—			2,529
Oilfield services	—			583			—			2,529			3,534			(2,030		)	4,616
Gain (loss) on sale of assets and other revenue	—			345			(36		)	8			(340		)	—			(23		)
Total revenue	—			54,290			9,250			5,066			3,194			(2,030		)	69,770
Lease operating expenses	—			12,108			1,668			—			—			(1,209		)	12,567
Severance taxes and marketing	—			3,729			664			—			—			—			4,393
Exploration	—			345			—			—			—			—			345
Gas gathering and processing	—			—			—			1,153			—			—			1,153
Oilfield services	—			712			—			1,135			3,716			(350		)	5,213
Impairment of oil & gas properties	—			2,954			4,916			—			—			—			7,870
Depreciation, depletion, and accretion	—			25,778			5,992			1,195			237			—			33,202
General and administrative	8,058			4,729			903			958			118			—			14,766
Total expenses	8,058			50,355			14,143			4,441			4,071			(1,559		)	79,509
Interest income	2,137			5			778			—			—			(2,917		)	3
Interest expense	(12,885		)	(1,977		)	(1,061		)	(1,671		)	(63		)	2,917			(14,740		)
Gain (loss) on derivative contracts	(15,571		)	80			—			5,340			—			—			(10,151		)
Other income and (expense)	—			285			2			(10		)	—			—			277
Total other income and expense	(26,319		)	(1,607		)	(281		)	3,659			(63		)	—			(24,611		)
Income (loss) from continuing operations before income taxes and non-controlling interest	(34,377		)	2,328			(5,174		)	4,284			(940		)	(471		)	(34,350		)
Income tax benefit	—			1,647			289			—			—			—			1,936
Net income attributable to non-controlling interest	—			(49		)	—			—			—			—			(49		)
Net income (loss)	(34,377		)	3,926			(4,885		)	4,284			(940		)	(471		)	(32,463		)
Total segment assets	$	51,677		$	1,411,808		$	275,066		$	182,144		$	15,120		$	(1,803	)	$	1,934,012

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	For the Three Months Ended September 30, 2011
	(in thousands)
	Corporate			U.S.			Canadian						Oilfield			Intersegment
	Unallocated			Upstream			Upstream			Midstream			Services			Eliminations			Total
Oil and gas Sales	$	—		$	22,430		$	3,118		$	—		$	—		$	—		$	25,548
Gas gathering and processing	—			381			—			504			—			—			885
Oilfield services	—			—			—			—			3,355			(830		)	2,525
Other	—			(903		)	—			—			—			—			(903		)
Total revenue	—			21,908			3,118			504			3,355			(830		)	28,055
Lease operating expenses	—			7,411			560			—			—			(429		)	7,542
Severance taxes and marketing	—			1,704			229			—			—			—			1,933
Exploration	—			467			—			—			—			—			467
Gas gathering and processing	—			—			—			102			—			—			102
Oilfield services	—			350			—			—			2,524			(401		)	2,473
Depreciation, depletion, and accretion	—			9,651			2,139			465			137			—			12,392
General and administrative	13,701			2,195			799			314			141			—			17,150
Total expenses	13,701			21,778			3,727			881			2,802			(830		)	42,059
Interest income	—			6			774			—			—			(770		)	10
Interest expense	(1,610		)	(850		)	(17		)	(523		)	(40		)	772			(2,268		)
Gain (loss) on derivative contracts	17,341			—			—			—			—			—			17,341
Other income and (expense)	—			57			(35		)	—			—			—			22
Total other income and expense	15,731			(787		)	722			(523		)	(40		)	2			15,105
Income (loss) from continuing operations before income taxes and non-controlling interest	2,030			(657		)	113			(900		)	513			2			1,101
Income tax benefit (expense)	—			309			(37		)	—			—			—			272
Net income attributable to non-controlling interest	—			(55		)	—			—			—			—			(55		)
Net income (loss) from continuing operations	2,030			(403		)	76			(900		)	513			2			1,318
Income from discontinued operations	—			—			—			—			682			—			682
Net income (loss)	$	2,030		$	(403	)	$	76		$	(900	)	$	1,195		$	2		$	2,000
Total segment assets	$	245,902		$	536,408		$	197,747		$	82,030		$	15,477		$	—		$	1,077,564

25

	For the Nine Months Ended September 30, 2012
	(in thousands)
	Corporate						Canadian						Oilfield			Intersegment
	Unallocated			U.S. Upstream			Upstream			Midstream			Services			Eliminations			Total
Oil and gas sales	$	—		$	141,690		$	25,812		$	—		$	—		$	—		$	167,502
Gas gathering and processing	—			—			—			5,609			—			—			5,609
Oilfield services	—			3,402			—			4,809			9,794			(3,675		)	14,330
Gain (loss) on sale of assets and other revenue	—			451			(35		)	25			(616		)	—			(175		)
Total revenue	—			145,543			25,777			10,443			9,178			(3,675		)	187,266
Lease operating expenses	—			34,748			3,899			—			—			(2,854		)	35,793
Severance taxes and marketing	—			10,066			1,862			—			—			—			11,928
Exploration	—			1,075			—			—			—			—			1,075
Gas gathering and processing	—			—			—			2,152			—			—			2,152
Oilfield services	—			2,070			—			2,227			7,283			(350		)	11,230
Impairment of oil & gas properties	—			17,068			8,496			—			—			—			25,564
Depreciation, depletion, and accretion	—			71,265			15,610			2,853			684			—			90,412
General and administrative	29,956			10,918			3,216			2,065			250			—			46,405
Total expenses	29,956			147,210			33,083			9,297			8,217			(3,204		)	224,559
Interest income	2,192			36			2,314			—			—			(4,443		)	99
Interest expense	(34,380		)	(3,658		)	(1,062		)	(4,678		)	(221		)	4,443			(39,556		)
Gain (loss) on derivative contracts	4,881			185			—			3,990			—			—			9,056
Other income and (expense)	—			471			1			(12		)	—			—			460
Total other income and expense	(27,307		)	(2,966		)	1,253			(700		)	(221		)	—			(29,941		)
Income (loss) from continuing operations before income taxes and non-controlling interest	(57,263		)	(4,633		)	(6,053		)	446			740			(471		)	(67,234		)
Income tax benefit	—			6,727			502			—			—			—			7,229
Net income attributable to non-controlling interest	—			(71		)	—			—			—			—			(71		)
Net income (loss) from continuing operations	(57,263		)	2,023			(5,551		)	446			740			(471		)	(60,076		)
Income from discontinued operations	—			—			—			—			354			—			354
Gain on sale of discontinued operations	—			2,224			—			—			—			—			2,224
Net loss	$	(57,263	)	$	4,247		$	(5,551	)	$	446		$	1,094		$	(471	)	$	(57,498	)
Total segment assets	$	51,677		$	1,411,808		$	275,066		$	182,144		$	15,120		$	(1,803	)	$	1,934,012

26

	For the Nine Months Ended September 30, 2011
	(in thousands)
	Corporate			U.S.			Canadian						Oilfield			Intersegment
	Unallocated			Upstream			Upstream			Midstream			Services			Eliminations			Total
Oil and gas Sales	$	—		$	61,381		$	4,174		$	—		$	—		$	—		$	65,555
Gas gathering and processing	—			1,027			—			1,076			—			—			2,103
Oilfield services	—			—			—			—			6,063			(2,334		)	3,729
Other	—			(784		)	—			1,512			9			—			737
Total revenue	—			61,624			4,174			2,588			6,072			(2,334		)	72,124
Lease operating expenses	—			17,067			888			—			—			(854		)	17,101
Severance taxes and marketing	—			4,500			229			—			—			—			4,729
Exploration	—			1,140			—			—			—			—			1,140
Gas gathering and processing	—			—			—			278			—			—			278
Oilfield services	—			1,035			—			—			5,161			(1,480		)	4,716
Depreciation, depletion, and accretion	—			24,088			2,820			1,338			348			—			28,594
General and administrative	40,577			4,872			1,205			543			376			—			47,573
Total expenses	40,577			52,702			5,142			2,159			5,885			(2,334		)	104,131
Interest income	3			7			1,287			—			—			(1,283		)	14
Interest expense	(6,128		)	(1,453		)	(45		)	(523		)	(107		)	1,283			(6,973		)
Gain (loss) on derivative contracts	16,667			—			—			—			—			—			16,667
Other income and (expense)	—			140			(31		)	—			—			—			109
Total other income and expense	10,542			(1,306		)	1,211			(523		)	(107		)	—			9,817
Income (loss) from continuing operations before income taxes and non-controlling interest	(30,035		)	7,616			243			(94		)	80			—			(22,190		)
Income tax benefit (expense)	—			539			(69		)	—			—			—			470
Net income attributable to non-controlling interest	—			(172		)	—			—			—			—			(172		)
Net income (loss) from continuing operations	(30,035		)	7,983			174			(94		)	80			—			(21,892		)
Income from discontinued operations	—			—			—			—			2,162			—			2,162
Net income (loss)	$	(30,035	)	$	7,983		$	174		$	(94	)	$	2,242		$	—		$	(19,730	)
Total segment assets	$	245,902		$	536,408		$	197,747		$	82,030		$	15,477		$	—		$	1,077,564

27

NOTE 16 — CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS

The Company and certain of its wholly owned subsidiaries, Eagle Ford Hunter, Inc., Triad Hunter, LLC, NGAS Hunter, LLC, Willison Hunter, Inc., Williston Hunter ND, LLC, and Bakken Hunter, LLC (collectively, “Guarantor Subsidiaries”), have fully and unconditionally guaranteed the obligations of the Company under any debt securities that it may issue pursuant to a universal shelf registration statement on Form S-3, on a joint and several basis.  In the third quarter of 2012, the Company revised its condensed consolidating balance sheet for the year ended December 31, 2011, to correct the presentation of Guarantor and non Guarantor shareholders' equity and the corresponding impact to investment in subsidiaries in the Magnum Hunter Resources Corporation column.  The impact of this revision to the Guarantor Subsidiaries and Magnum Hunter Resources Corporation is an increase of equity and investment in subsidiaries of approximately $45.3 million and $32.2 million, respectively, for the year ended December 31, 2011.  Management concluded the revision was not material to the related financial statements. 

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 September 30, 2012 and December 31, 2011, and for the three and nine months ended September 30, 2012 and 2011, was as follows:

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Balance Sheets

(in thousands)

	As of September 30, 2012
										Magnum Hunter
	Magnum Hunter									Resources
	Resources		Guarantor		Non Guarantor					Corporation
	Corporation		Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets	$	22,656	$	76,881	$	25,808	$	(757	)	$	124,588
Intercompany accounts receivable	972,704		—		—		(972,704		)	—
Property and equipment (using successful efforts accounting)	12,590		1,294,074		434,606		—			1,741,270
Investment in subsidiaries	453,727		64,909		163,223		(681,859		)	—
Other assets	16,431		6,803		44,920		—			68,154
Total Assets	$	1,478,108	$	1,442,667	$	668,557	$	(1,655,320	)	$	1,934,012
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities	$	45,833	$	106,228	$	34,901	$	(308	)	$	186,654
Intercompany accounts payable	—		555,478		417,187		(972,665		)	—
Long-term liabilities	631,001		91,456		123,070		—			845,527
Redeemable preferred stock	100,000		—		86,334		—			186,334
Shareholders’ equity	701,274		689,505		7,064		(682,346		)	715,497
Total Liabilities and Shareholders’ Equity	$	1,478,108	$	1,442,667	$	668,556	$	(1,655,319	)	$	1,934,012

28

	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	212,273		45,310		126,655		(384,238		)	—
Other assets	9,152		3,838		2,967		—			15,957
Total Assets	$	862,887	$	813,363	$	479,521	$	(987,011	)	$	1,168,760
LIABILITIES AND SHAREHOLDERS’ 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	488,457		363,637		22,796		(384,238		)	490,652
Total Liabilities and Shareholders’ Equity	$	862,887	$	813,363	$	479,521	$	(987,011	)	$	1,168,760

29

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of Operations

(in thousands)

	For the Three Months Ended September 30, 2012
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor		Non Guarantor						Corporation
	Corporation			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Revenues	$	172		$	51,873	$	19,755		$	(2,030	)	$	69,770
Expenses	34,863			49,701		21,586			(2,030		)	104,120
Loss from continuing operations before equity in net income of subsidiary	(34,691		)	2,172		(1,831		)	—			(34,350		)
Equity in net income of subsidiary	(1,797		)	—		—			1,797			—
Income (loss) from continuing operations before income taxes and non-controlling interest	(36,488		)	2,172		(1,831		)	1,797			(34,350		)
Income tax benefit	—			1,647		289			—			1,936
Net income attributable to non-controlling interest	—			—		(49		)	—			(49		)
Net income (loss)	(36,488		)	3,819		(1,591		)	1,797			(32,463		)
Dividends on preferred stock	(5,795		)	—		(4,025		)	—			(9,820		)
Net income (loss) attributable to common shareholders	$	(42,283	)	$	3,819	$	(5,616	)	$	1,797		$	(42,283	)

30

	For the Three Months Ended September 30, 2011
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor		Non Guarantor						Corporation
	Corporation			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Revenues	$	242		$	21,058	$	7,585		$	(830	)	$	28,055
Expenses	(1,675		)	20,548		8,912			(831		)	26,954
Loss from continuing operations before equity in net income of subsidiary	1,917			510		(1,327		)	1			1,101
Equity in net income of subsidiary	83			—		—			(83		)	—
Income (loss) from continuing operations before income taxes and non-controlling interest	2,000			510		(1,327		)	(82		)	1,101
Income tax benefit	—			—		272						272
Net income attributable to non-controlling interest	—			—		(55		)	—			(55		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	2,000			510		(1,110		)	(82		)	1,318
Income from discontinued operations	—			—		682			—			682
Net income (loss)	2,000			510		(428		)	(82		)	2,000
Dividends on preferred stock	(3,952		)	—		—			—			(3,952		)
Net income (loss) attributable to common shareholders	$	(1,952	)	$	510	$	(428	)	$	(82	)	$	(1,952	)

31

	For the Nine Months Ended September 30, 2012
													Magnum Hunter
	Magnum Hunter												Resources
	Resources			Guarantor			Non Guarantor						Corporation
	Corporation			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues	$	638		$	138,471		$	51,832		$	(3,675	)	$	187,266
Expenses	58,811			142,812			56,553			(3,675		)	254,501
Loss from continuing operations before equity in net income of subsidiary	(58,173		)	(4,341		)	(4,721		)	—			(67,235		)
Equity in net income of subsidiary	(6,826		)	—			—			6,826			—
Income (loss) from continuing operations before income taxes and non-controlling interest	(64,999		)	(4,341		)	(4,721		)	6,826			(67,235		)
Income tax benefit	—			6,728			502			—			7,230
Net income attributable to non-controlling interest	—			—			(71		)	—			(71		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	(64,999		)	2,387			(4,290		)	6,826			(60,076		)
Income from discontinued operations	—			354						—			354
Gain on sale of discontinued operations	—			2,224			—			—			2,224
Net income (loss)	(64,999		)	4,965			(4,290		)	6,826			(57,498		)
Dividends on preferred stock	(15,179		)	—			(7,501		)	—			(22,680		)
Net income (loss) attributable to common shareholders	$	(80,178	)	$	4,965		$	(11,791	)	$	6,826		$	(80,178	)

32

	For the Nine Months Ended September 30, 2011
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor		Non Guarantor						Corporation
	Corporation			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Revenues	$	857		$	58,512	$	15,089		$	(2,334	)	$	72,124
Expenses	31,208			48,374		17,066			(2,334		)	94,314
Loss from continuing operations before equity in net income of subsidiary	(30,351		)	10,138		(1,977		)	—			(22,190		)
Equity in net income of subsidiary	10,621			—		—			(10,621		)	—
Income (loss) from continuing operations before income taxes and non-controlling interest	(19,730		)	10,138		(1,977		)	(10,621		)	(22,190		)
Income tax benefit	—			—		470						470
Net income attributable to non-controlling interest	—			—		(172		)	—			(172		)
Net income (loss) attributable to Magnum Hunter Resources Corporation from continuing operations	(19,730		)	10,138		(1,679		)	(10,621		)	(21,892		)
Income from discontinued operations	—			—		2,162			—			2,162
Net income (loss)	(19,730		)	10,138		483			(10,621		)	(19,730		)
Dividends on preferred stock	(10,017		)	—		—			—			(10,017		)
Net income (loss) attributable to common shareholders	$	(29,747	)	$	10,138	$	483		$	(10,621	)	$	(29,747	)

33

Magnum Hunter Resources Corporation and Subsidiaries Condensed Consolidating Statements of Cash Flows

(in thousands)

	For the Nine Months Ended September 30, 2012
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor			Non Guarantor					Corporation
	Corporation			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Cash flow from operating activities	$	(303,365	)	$	341,173		$	10,011		$	—	$	46,819
Cash flow from investing activities	(308,625		)	(337,985		)	(147,077		)	—		(793,687		)
Cash flow from financing activities	612,579			(1,747		)	143,327			—		754,159
Effect of exchange rate changes on cash	—			—			(146		)	—		(146		)
Net increase (decrease) in cash	(411		)	1,441			6,117			—		7,147
Cash at beginning of period	18,758			(6,126		)	2,219			—		14,851
Cash at end of period	$	18,347		$	(4,685	)	$	8,336		$	—	$	21,998

	For the Nine Months Ended September 30, 2011
												Magnum Hunter
	Magnum Hunter											Resources
	Resources			Guarantor			Non Guarantor					Corporation
	Corporation			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Cash flow from operating activities	$	(150,913	)	$	124,354		$	36,816		$	—	$	10,257
Cash flow from investing activities	(80,160		)	(124,113		)	(69,246		)	—		(273,519		)
Cash flow from financing activities	236,565			(278		)	34,827			—		271,114
Effect of exchange rate changes on cash	—			—			(231		)	—		(231		)
Net increase (decrease) in cash	5,492			(37		)	2,166			—		7,621
Cash at beginning of period	1,556			(1,094		)	92			—		554
Cash at end of period	$	7,048		$	(1,131	)	$	2,258		$	—	$	8,175

NOTE 17 — SUBSEQUENT EVENTS

Issuance of Series D Preferred Stock

We sold an additional 67,188 shares of our Series D Cumulative Perpetual Preferred Stock at prices ranging from $44.50 per share to $44.75 per share for net proceeds of approximately $2.9 million, pursuant to our ATM sales agreement subsequent to September 30, 2012, through the date of this report.  There are a total of 4,205,513 shares of Series D Preferred Stock outstanding as of the date of this report.

Acquisition of Viking International Resources Co., Inc.

On October 24, 2012, Triad Hunter, LLC, a wholly owned subsidiary of the Company, entered into a Stock Purchase Agreement (the “Stock Purchase Agreement”) with Viking International Resources Co., Inc. (“Virco”) and all of the stockholders of Virco (the “Sellers”).  Pursuant to the Stock Purchase Agreement, Triad Hunter agreed to purchase from the Sellers all of the outstanding capital stock of Virco (the “Virco Shares”).  The acquisition of the Virco Shares pursuant to the Stock Purchase Agreement closed on November 2, 2012, and for purposes of certain restrictive covenants applicable to Virco, had an effective date of January 1, 2012.  Under the Stock Purchase Agreement, the purchase price for the Virco Shares was approximately $106.7 million, of which approximately $37.3 million was paid in cash and approximately $69.4 million (based on liquidation preference) was paid in the form of 2,774,850 depositary shares (the “Depositary Shares”) representing 2,774.85 shares of a new 8.0% Series E Cumulative Convertible Preferred Stock of the Company.  188,000 of the Depositary Shares paid at closing were deposited with an escrow agent for purposes of satisfying the Sellers’ indemnification obligations under the Stock Purchase Agreement.

Each share of Series E Preferred Stock has a stated liquidation preference of $25,000 and a dividend rate of 8.0% per annum (based on stated liquidation preference), is convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference divided by a conversion price of $8.50 per share (subject to anti-dilution adjustments in the case of stock dividends, stock splits and combinations of shares), and is redeemable by the Company under certain circumstances.  The Series E Preferred Stock is junior to the Company’s 10.25% Series C Cumulative Perpetual Preferred Stock and 8.0% Series D Cumulative Preferred Stock in respect of dividends and distributions upon liquidation.  Each Depositary Share is a 1/1000th interest in a share of Series E Preferred Stock.  Accordingly, the Depositary Shares have a stated liquidation

34

preference of $25.00 per share and a dividend rate of 8.0% per annum (based on stated liquidation preference), are similarly convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference divided by a conversion price of $8.50 per share (subject to corresponding anti-dilution adjustments), and are redeemable by the Company under certain circumstances.

Tenth and Eleventh Amendments to the Second Amended and Restated Credit Agreement

On October 29, 2012, the Company entered into a Tenth Amendment to its Second Amended and Restated Credit Agreement.  The Tenth Amendment permits the Company to issue a new Series E cumulative convertible preferred stock (the “Series E Stock”), of which 2,774.85 shares were first issued in connection with the acquisition of Viking International Resources Co., Inc. by the Company’s subsidiary, Triad Hunter, LLC. In addition, the Tenth Amendment adds the Series E Stock to the list of securities eligible to receive dividends subject to the annual preferred stock basket of $25.0 million and other restrictions.

On November 7, 2012, the Company entered into an Eleventh Amendment to its Second Amended and Restated Credit Agreement. The Eleventh Amendment amended the credit agreement to, among other things, increase the borrowing base thereunder from $260 million to $375 million. Of the increased borrowing base amount, $50 million has a maximum term through June 30, 2013 and is subject to certain required reduction events including, without limitation, a mandatory reduction from any interim increase in the $325 million borrowing base tranche before June 30, 2013. With the startup of MarkWest’s Mobley gas processing facility expected in the near future, Magnum Hunter will be able to increase its natural gas liquids proved developed reserves, which can be utilized to address any required payment of borrowings on June 30, 2013.

The Eleventh Amendment also increased the annual preferred stock dividend basket from $20.0 million to $40.0 million and amended the credit agreement to permit dividends for the Series E Stock on substantially the same terms as the existing Series C and Series D preferred stock of the Company.

In addition, the Eleventh Amendment amended the Total Debt to EBITDAX financial covenant in the credit agreement to require that such ratio not exceed (a) 4.5 to 1.0 for the fiscal quarter ended September 30, 2012 and the fiscal quarter ending December 31, 2012, (b) 4.25 to 1.0 for the fiscal quarter ending March 31, 2013 and (c) 4.0 to 1.0 for the fiscal quarter ending June 30, 2013 and for each fiscal quarter thereafter.

Additional Investment by Ridgeline in Eureka Hunter Holdings

On October 31, 2012, Ridgeline invested an additional $20.0 million in 1,000,000 Series A Preferred Units of Eureka Hunter Holdings. As of November 14, 2012, Ridgeline held an approximate 36.5% membership interest in Eureka Hunter Holdings, represented by Series A Preferred Units in Eureka Hunter Holdings.

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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,

·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,

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·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.

Recent Events

Fifth Amendment to Credit Agreement

On February 14, 2012, the Company entered into the Fifth Amendment to its Second Amended and Restated Credit Agreement. Pursuant to the Fifth Amendment, the Company’s borrowing base was increased to $235.0 million from $200.0 million.

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Sixth and Seventh Amendments to Credit Agreement

On May 2, 2012, the Company entered into the Sixth Amendment to its Second Amended and Restated Credit Agreement.  Pursuant to the Sixth Amendment, the borrowing base under our senior revolving credit facility was increased from $235.0 million to $275.0 million, then pursuant to the issuance of the $450.0 million of 9.75% Senior Notes, the borrowing base was decreased from $275.0 million to $187.5 million. Subsequent to the closing of the Baytex assets 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 for the June 30, 2012 reporting period, but such reduction did not become effective due to the issuance by the Company of its Senior Notes and the closing of the Baytex Energy USA assets acquisition.

Eighth Amendment to Credit Agreement

On May 10, 2012, the Company entered into the Eighth Amendment to its Second Amended and Restated Credit Agreement.  Pursuant to the Eighth Amendment, the Company used a portion of the proceeds from the issuance of the Senior Notes to retire its term loan of $100.0 million, and the Company was required to have a minimum liquidity greater than $75.0 million after retiring the term loan in order to issue the Senior Notes.

Ninth Amendment to Credit Agreement

On August 8, 2012, the Company entered into the Ninth Amendment to its Second Amended and Restated Credit Agreement.  Pursuant to the Ninth Amendment, debt under the Senior Notes is limited to $550.0 million, provided that the maturity date of the Senior Notes may not be earlier that one year after the maturity date of the senior revolving credit facility, and the Company shall not prepay any amounts owing under the Senior Notes at any time.  The Ninth Amendment also raised the amount that the Company can pay as cash dividends on its Series C and Series D Preferred Stock to $25.0 million in any calendar year.  The Ninth Amendment also raised the borrowing base to $260.0 million.

Tenth Amendment to Credit Agreement

On October 29, 2012, the Company entered into the Tenth Amendment to its Second Amended and Restated Credit Agreement. The Tenth Amendment permits the Company to issue a new Series E cumulative convertible preferred stock (the “Series E Stock”), of which 2774.85 shares were first issued in connection with the aquisition of Viking International Resources Co., Inc. by the Company’s subsidiary, Triad Hunter, LLC. In addition, the Tenth Amendment adds the Series E Stock to the list of securities eligible to receive dividends subject to the annual preferred stock basket of $25.0 million and other restrictions.

Eleventh Amendment to Credit Agreement

On November 7, 2012 the Company entered into the Eleventh Amendment to its Second Amended and Restated Credit Agreement. The Eleventh Amendment amended the credit agreement to, among other things, increase the borrowing base, thereunder from $260 million to $375 million. Of the increased borrowing base amount, $50 million has a maximum term through June 30, 2013 and is subject to certain required reduction events including, without limitation, a mandatory reduction from any interim increase in the $325 million borrowing base tranche before June 30, 2013. With the startup of MarkWest’s Mobley gas processing facility expected in the near future, Magnum Hunter will be able to increase its natural gas liquids proved developed reserves, which can be utilized to address any required payment of borrowings on June 30, 2013.

The Eleventh Amendment also increased the annual preferred stock dividend basket from $20.0 million to $40.0 million and amended the credit agreement to permit dividends for the Series E Stock on substantially the same terms as the existing Series C and Series D preferred stock of the Company.

In addition, the Eleventh Amendment amended the Total Debt to EBITDAX financial covenant in the credit agreement to require that such ratio not exceed (a) 4.5 to 1.0 for the fiscal quarter ended September 30, 2012 and the fiscal quarter ending December 31, 2012, (b) 4.25 to 1.0 for the fiscal quarter ending March 31, 2013 and (c) 4.0 to 1.0 for the fiscal quarter ending June 30, 2013 and for each fiscal quarter thereafter.

Amendment to Eureka Hunter Pipeline Second Lien Term Loan Agreement

On June 29, 2012, Eureka Hunter Pipeline entered into a Third Amendment to its Second Lien Term Loan Agreement.  The Third Amendment amended 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 such 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,

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unless such First Lien Credit Agreement is amended in a manner satisfactory to the lenders under the Second Lien Term Loan Agreement.  The Company paid consideration of $500,000 for the Third Amendment.

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 in cash.  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 increased Triad Hunter’s acreage position to 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 its equity ownership interest in 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 an officer, director and major shareholder, for which Ronald Ormand, our Chief Financial Officer and a director, is also a director, and for which David Krueger, one of our Senior Vice Presidents and former Chief Accounting Officer, is Chief Financial Officer.  The terms and conditions of the equity purchase agreement between the parties were approved by an independent special committee of the Company.  The total sales price for this divestiture 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 convertible promissory note due to Triad Hunter.  In connection with the sale Triad Hunter 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.

Series A Convertible Preferred Unit Purchase Agreement

On March 21, 2012, Eureka Hunter Holdings entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with the Company and Ridgeline Midstream Holdings, LLC (“Ridgeline”), 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 “Series A Preferred Units”).  Eureka Hunter Holdings is a majority owned subsidiary of Magnum Hunter and the holding company for Magnum Hunter’s midstream operations, which include its existing pipeline operation in West Virginia and Ohio conducted through Eureka Hunter Pipeline and the below-described gas treating business and assets acquired (the “TransTex Acquisition”) by the Company from TransTex Gas Services, LP (“TransTex”) on April 2, 2012.

Contemporaneous with the execution of the Unit Purchase Agreement, Ridgeline purchased 3,000,000 Series A 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 wholly owned subsidiary of Eureka Hunter Pipeline.  Upon consummation of Ridgeline’s $60.0 million initial investment, Eureka Hunter Holdings was owned 83.4% by Magnum Hunter, all in the form of Class A Common Units (the “Class A Common Units”), and 16.6% by Ridgeline, all in the form of Series A Preferred Units (on an as-converted basis).  Further, Ridgeline purchased an additional 2,340,000 Series A 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 Hunter Holdings to Magnum Hunter to reimburse it for certain capital expenditures with respect to the assets acquired for cash in the TransTex Acquisition.  Ridgeline’s remaining capital commitment, 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 Unit Purchase Agreement.  The remaining capital commitment 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 represented, 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. Individual TransTex partners purchased 37,641 Class A Common Units, including 27,641 purchased by Gary Evans, the Chairman and CEO of the Company.

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

On October 31, 2012, Ridgeline invested an additional $20.0 million in 1,000,000 Series A Preferred Units of Eureka Hunter Holdings. As of November 14, 2012, Ridgeline held an approximate 36.5% membership interest in Eureka Hunter Holdings, represented by Series A Preferred Units in 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., 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 Assets Acquisition

On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC, 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 Corporation, for $312.0 million, as adjusted for certain customary adjustments.

The assets 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 became 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, along with certain environmental liabilities.

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 Company and the guarantor subsidiaries will use commercially reasonable efforts to register the Senior Notes under the Securities Act within 365 days after the date of issuance of the Senior Notes. The Company and the guarantor subsidiaries are required to pay additional interest if they fail to comply with their obligations to register the Senior Notes within the specified time period.

The Senior Notes were issued at a price of 98.646% of their face amount and provided net proceeds to the Company, after fees and expenses, of $432.2 million.  The Company has used 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 Energy USA, Ltd., which closed on May 22, 2012, (ii) to pay off all amounts outstanding under the Company’s term loan existing at that time, (iii) to repay outstanding debt under the Company’s senior revolving credit facility, (iv) to increase the Company’s 2012 upstream capital budget from $150.0 million to $325.0 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 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 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.

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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 or 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 at a price of $4.50 per share.  The net proceeds of the offering, after deducting underwriting discounts and commissions and offering expenses, were approximately $148.0 million.

Equity Financings 

We have raised substantial cash in the total amount of approximately $271.7 million in gross proceeds through equity transactions this fiscal year through November 13, 2012.  Those transactions included:

·$1.3 million in net proceeds from the exercise of warrants and common stock options for 2012 through November 13, 2012;

·$122.4 million in net proceeds from the issuance of our Series D Preferred Stock for 2012 through November 13, 2012; and

·$148.0 million in net proceeds from the sale of 7,590,000 Series A Preferred Units of Eureka Hunter Holdings through November 13, 2012.

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

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 nine months ended September 30, 2012, and 2011, respectively.  See a glossary of terms used below the table.

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	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Oil and gas revenue and production
Revenues (in thousands)
Oil — US	$	41,487	$	13,907	$	103,246	$	40,686
Oil — Canada	9,147		2,726		25,442		3,592
Gas — US	10,325		6,555		33,411		17,690
Gas — Canada	135		380		359		564
NGLs — US	1,551		1,969		5,034		3,006
NGLs — Canada	3		11		10		17
Total oil and gas sales	$	62,648	$	25,548	$	167,502	$	65,555
Production
Oil (mbbls) — US	471		166		1,138		456
Oil (mbbls) — Canada	107		32		292		41
Gas (mmcfs) — US	3,046		1,456		11,222		3,572
Gas (mmcfs) — Canada	53		79		163		134
NGL (mboe) — US	54		31		139		57
NGL (mboe) — Canada	—		—		—		—
Total (mboe)	1,148		485		3,467		1,172
Total (boe/d)	12,480		5,270		12,653		4,292
Average prices
Oil (per bbl) — US	$	88.15	$	83.54	$	90.73	$	89.20
Oil (per bbl) — Canada	85.73		86.65		87.04		88.27
Gas (per mcf) — US	3.39		4.50		2.98		4.95
Gas (per mcf) —Canada	2.55		4.82		2.21		4.21
NGL (per boe) — US	62.46		63.93		51.20		55.60
NGL (per boe) — Canada	33.65		41.18		31.17		39.50
Total average price (per boe)	$	54.56	$	52.69	$	48.32	$	55.95
Costs and expenses (per boe)
Lease operating expense	$	10.95	$	15.55	$	10.32	$	14.60
Severance tax and marketing	3.83		3.99		3.44		4.04
Exploration expense	0.30		0.96		0.31		0.97
General and administrative expense (see Footnote 1 below)	12.86		35.37		13.39		40.60
Depletion, depreciation and accretion	29.35		25.56		26.08		24.40
Midstream and oilfield service segments (in thousands)
Oilfield services segment revenue	3,194		3,355		9,178		6,072
Midstream operations segment revenue	5,066		504		10,443		2,588
Oilfield services segment expense	4,071		2,802		8,217		5,885
Midstream operations segment expense	4,931		881		9,297		2,159

(1)General and administrative expense includes:

(i)acquisition related expenses of $1.1 million for the three months in 2012 ($0.94 per boe) and $424,000 ($0.87 per boe) for the three months in 2011, and

(ii)acquisition related expenses of $3.6 million ($1.05 per boe) for the nine months in 2012 and $7.8 million ($6.68 per boe) for the nine months in 2011.

(iii)non-cash stock compensation of $3.5 million ($3.02 per boe) for the three months in 2012 and $7.9 million ($16.31 per boe) for the three months in 2011.

(iv)non-cash stock compensation of $16.0 million ($4.62 per boe) for the nine months in 2012 and $12.0 million ($10.25 per boe) for the nine 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.

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Three Months Ended September 30, 2012 and 2011

Oil and gas production.  Oil and gas production increased 137% to 1,148 MBoe for the three months ended September 30, 2012, from 485 MBoe for the three months ended September 30, 2011.  Production for the 2012 period was approximately 55% oil and 45% natural gas compared to 47% oil and 53% natural gas for the 2011 period.  Our average daily production on a Boe basis increased 137% to 12,480 Boe per day for the 2012 period compared to 5,270 Boe per day for the 2011 period.  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 closed by the Company in the Williston Basin area during May of 2012.  Our oil and gas production in the three months ended September 30, 2012 was significantly impacted by Appalachian production curtailments due to lack of available processing capacity at Dominion Transmission’s Hasting’s processing facility and shut-in of producing natural gas wells in Kentucky.  This negatively impacted third quarter 2012 production by approximately 1,600 Boepd. The Company anticipates curtailed production to be abreviated and realization of natural gas liquids from its Marcellus production once MarkWest’s Mobley gas processing plant becomes operational.

US Upstream segment.  Production increased in the US Upstream operating segment by 128%, to 1,003 Mboe, for the three months ended September 30, 2012 from 440 Mboe for the three months ended September 30, 2011.  Production for 2012 during the second quarter on a Boe basis was 49% oil and 51% natural gas compared to 45% oil and 55% natural gas for the third quarter of 2011.  Our average daily production increased by 128% to 10,904 Boepd during the 2012 period compared to 4,782 Boepd for 2011.  This increase in production 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 closed by the Company in the Williston Basin area during May of 2012.  US upstream volumes were impacted by the forced shut-ins described above.

Canadian Upstream segment.  Production increased from the Canadian upstream operating segment 158%, to 116 Mboe, for the three months ended September 30, 2012 from 45 Mboe for the three months ended September 30, 2011.  Production for the 2012 period on a Boe basis was 92% oil and 8% natural gas compared to 71% oil and 29% natural gas for the 2011 period.  Our average daily production increased by 158% to 1,257 Boepd during the third quarter of 2012 compared to 488 Boepd for 2011.  This increase in production in 2012 compared to 2011 is completely attributable to organic growth through the company’s ongoing drilling programs in the Tableland Field.

Oil and gas sales.  Oil and gas sales increased $37.1 million, or 145%, for the three months ended September 30, 2012, to $62.6 million from $25.5 million for the three months ended September 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 increased $3.67 per barrel (4%) to $87.70 per barrel, while the average price received for gas production decreased $1.14 per Mcf (25%) to $3.38 per Mcf.  Our average price for gas decreased due to market trends in general for the price for natural gas.  Of the $37.1 million increase in oil and gas sales, approximately $39.2 million was attributable to an increase in production volumes partially offset by a $2.1 million decrease in the prices received for the commodities produced.  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.)

Oilfield services segment revenue.  Oilfield services revenue decreased by 5%, or $161,000, for the three months ended September 30, 2012 to $3.2 million from $3.4 million for the three months ended September 30, 2011.  Oilfield services revenues for the three months ended September 30, 2012 were primarily drilling services.  The decrease in revenues in the oilfield services segment was due to proportional decrease in the volume of drilling services provided to customers.

Midstream operations revenue.  Revenue from the Eureka Hunter Holdings midstream segment increased by $4.6 million, or 905%, for the three months ended September 30, 2012, to $5.1 million from $504,000 for the three months ended September 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 $2.5 million related to leasing its gas treating equipment.

Third party gas marketing.  The Company began marketing gas produced by third parties for a fee during the second quarter of 2012.  Revenues from marketing third party gas were $840,000 during the three months ended September 30, 2012.

Other revenues.  The Company recorded a net gain on sales of assets of $24,000 for the three months ended September 30, 2012, that was from sales of equipment out of our Appalachian upstream operations. We also recorded $325,000 of other revenues in gain (loss) on sale of assets and other revenue during the three months ended September 30, 2012, primarily from revenue from a utility subsidiary of the Company in the Appalachian Region.

Lease operating expense.  Our lease operating expenses increased $5.0 million, or 67%, for the three months ended September 30, 2012, to $12.6 million ($10.95 per Boe) from $7.5 million ($15.55 per Boe) for the three months ended September 30, 2011.  The decline in operating expense per Boe is due to the effect of adding new production, principally in the Eagle Ford and Williston Basin areas, at a 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 $2.3 million, or 122%, for the three months ended September 30, 2012, to $4.3 million from $1.9 million for the three months ended September 30, 2011.  The increase in severance taxes was

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attributable to the increase in oil and gas production.  Marketing expenses increased by $119,000, or 696%, for the three months ended September 30, 2012, to $136,000 from $17,000 for the three months ended September 30, 2011, due to expenses incurred by our midstream segment related to contracts for marketing gas for third party producers.

Exploration.  We incurred $345,000 of exploration expense for the three months ended September 30, 2012, compared to $467,000 for the three months ended September 30, 2011.

Impairment of oil and gas properties.We provided for an impairment to the carrying value of certain unproved properties in the amount of approximately $7.9 million for the three months ended September 30, 2012, which consisted of $3.0 million of our North Dakota leasehold and $4.9 million of our Canadian leasehold which expired undrilled before September 30, 2012.

Oilfield services expenses.  Oilfield services expenses increased by 45%, or $1.3 million, for the three months ended September 30, 2012 to $4.1 million from $2.8 million for the three months ended September 30, 2011.  Oilfield services expenses for these periods comprised expenses incurred in our drilling operations.

Midstream operations expenses.  Expenses incurred by the Eureka Hunter Holdings subsidiary increased by approximately $4.0 million to $4.9 million for the three months ended September 30, 2012 from $881,000 for the three months ended September 30, 2011.  The increase is due to the increase in new 2012 pipeline activities being managed by Eureka Hunter Pipeline 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 $23.8 million, or 168%, to $33.2 million for the three months ended September 30, 2012, from $12.4 million for the three months ended September 30, 2011 due to increased production in the 2012 period described above.  Our DD&A per Boe increased by $3.36, or 13%, to $28.92 per Boe for the three months ended September 30, 2012, compared to $25.56 per Boe for the three months ended September 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 require horizontal drilling and more expensive completion techniques than traditional, vertically-drilled wells.

General and administrative.  Our general and administrative expenses (“G&A”) decreased $2.4 million, or 14%, to $14.8 million ($12.86 per Boe) for the three months ended September 30, 2012, from $17.1 million ($35.37 per Boe) for the three months ended September 30, 2011.  G&A expenses decreased overall during the 2012 period primarily due to decreases in share based compensation expense and consulting expense of the Company.  Non-cash stock compensation totaled approximately $3.5 million ($3.02 per Boe) and $7.9 million ($16.31 per Boe) for the three months ended September 30, 2012 and 2011, respectively.  The three months ended September 30, 2012 also included transaction costs of $1.1 million ($0.94 per Boe) related to the acquisitions of assets in the Appalachian region which closed subsequent to September 30, 2012.  The three months ended September 30, 2011, included acquisition related costs of approximately $424,000 ($0.87 per Boe) for legal, consulting and other costs related to the acquisition of NGAS, NuLoch, and the PostRock Energy Corporation assets which closed during the second quarter of 2011.  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 production growth of the Company.

Interest expense, net.  Our interest expense, net of interest income, increased approximately $12.4 million, or 553% to $14.7 million for the three months ended September 30, 2012, from $2.3 million for the three months ended September 30, 2011.  This increase was the result of our higher average debt level during 2012 as well as non-cash amortization of $1.1 million in the 2012 period.

Commodity derivative activities.  Realized gains and losses from our commodity derivative activity increased our earnings by approximately $2.2 million and decreased our earnings by approximately $45,000 for the three months ended September 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 loss of approximately $17.8 million for the 2012 period and a gain of approximately $17.4 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.  The Company also has embedded derivatives in its Series A Convertible Preferred Units of Eureka Hunter Holdings and a promissory note received as partial consideration in the sale of Hunter Disposal. The unrealized gain on these embedded derivatives was $4.1 million for the three months ended September 30, 2012.  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 loss of approximately $10.2 million and a gain of approximately $17.3 million for the three months ended September 30, 2012 and 2011, respectively.  (See Note 7 to our condensed consolidated financial statements for more information.)

Income tax benefit.  The Company’s income tax benefit increased by $1.7 million to $1.9 million for the three months ended September 30, 2012, from $272,000 for the three months ended September 30, 2011.  The increase in the deferred tax benefit is due to

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higher intangible drilling costs incurred during the three months ended September 30, 2012. The income tax benefit recorded reflects the change in the deferred tax liability of the Company’s Williston Hunter and Magnum Hunter Production subsidiaries.

Net income attributable to non-controlling interest.  Net income attributable to non-controlling interest was approximately $49,000 for the three months ended September 30, 2012 versus $55,000 for same period in 2011.

Loss from Continuing Operations.  We had a loss from continuing operations of $32.5 million for the 2012 period versus income of $1.3 million for the 2011 period, a decrease of $33.8 million.  This was due to the $41.7 million increase in revenues offset by a $5.0 million increase in lease operating expense, an unproved property impairment charge of $7.9 million, a decrease in G&A of $2.4 million, an increase in DD&A of $20.8 million, and increase in interest expense of $12.5 million, an increase in loss on fair value of derivatives of $27.5 million.

Dividends on Preferred Stock.  Total dividends on our Series C and Series D Preferred Stock and the Series A Preferred Units of Eureka Hunter Holdings were approximately $9.8 million for the three months ended September 30, 2012.  Dividends were $4.0 million for the three months ended September 30, 2011.  The Series C Preferred Stock had a stated value of $100 million at both September 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 $206.9 million and $71.9 million at September 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 liquidation preference of $134.3 million and $0 at September 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 $42.3 million in the 2012 period versus $2.0 million in the 2011 period.  Our net loss per common share, basic and diluted was $0.27 per share for the three months ended September 30, 2012, compared to net loss of $0.02 per share for the 2011 period.  Our weighted average shares outstanding increased by approximately 37.8 million shares, or 29%, from 112,619,793 shares in the 2011 period to 168,897,700 during the 2012 period.  Our net loss per share from continuing operations was $0.27 per share for the three months ended September 30, 2012, versus a net loss of $0.02 per share for the 2011 period.

Nine Months Ended September 30, 2012 and 2011

Oil and gas production.  Oil and gas production increased 196% to 3,467 MBoe for the nine months ended September 30, 2012, from 1,172 MBoe for the nine months ended September 30, 2011.  Production for the 2012 period was approximately 45% oil and 55% natural gas compared to 47% oil and 53% natural gas for the 2011 period.  Our average daily production on a Boe basis increased 195% to 12,653 Boe per day for the 2012 period compared to 4,292 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 closed by the Company in the Williston Basin area during May of 2012.

US Upstream segment.  Production increased in the US Upstream operating segment by 180%, to 3,107 Mboe, for the nine months ended September 30, 2012 from 1,108 Mboe for the nine months ended September 30, 2011.  Production for 2012 on a Boe basis was 40% oil and NGLs and 60% natural gas compared to 46% oil and 54% natural gas for 2011.  Our average daily production increased by 180% to 11,338 Boepd during 2012 compared to 4,050 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 closed by the Company in the Williston Basin area during May of 2012.

Canadian Upstream segment.  Production increased from the Canadian upstream operating segment 404%, to 320 Mboe, for the nine months ended September 30, 2012 from 63 Mboe for the nine months ended September 30, 2011.  Production for 2012 on a Boe basis was 92% oil and 8% natural gas compared to 65% oil and 35% natural gas for 2011.  Our average daily production increased by 402% to 1,167 Boepd during 2012 compared to 232 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 a full nine months of production in the current year compared to five months during 2011.

Oil and gas sales.  Oil and gas sales increased $101.9 million, or 156%, for the nine months ended September 30, 2012, to $167.5 million from $65.6 million for the nine months ended September 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 increased $0.85 per barrel (1%) to $89.97 per barrel, while the average price received for gas production decreased $1.96 per Mcf (40%) 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 $101.9 million increase in oil and gas sales, approximately $109.7 million, or 108%, was attributable to the increase in production volumes partially offset by approximately $7.8 million, or 8%, decrease in prices received for commodities produced.  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

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offset some of the variability in prices.  (See the discussion of commodity derivative activities in Note 7 to our condensed consolidated financial statements.)

Oilfield services segment revenue.  Revenue from the Oilfield services segment increased by 51%, or $3.1 million, for the nine months ended September 30, 2012 to $9.2 million from $6.1 million for the nine months ended September 30, 2011.  Oilfield services revenues for the nine months ended September 30, 2012 were primarily drilling services.  The increase was caused by a higher volume of drilling services performed during the first three months of 2012.

Midstream operations revenue.  Revenue from the Eureka Hunter Holdings midstream segment increased by $7.9 million, or 308%, for the nine months ended September 30, 2012, to $10.4 million from $2.5 million for the nine months ended September 30, 2011.  The increase in revenues resulted from the increased volume of natural gas products gathered by the pipeline network and gathering system, $1.6 million of revenue from marketing gas to third parties, and $4.8 million of revenues from leasing gas treating equipment.

Other revenues.  We recorded a net loss on sale of assets of $540,000 for the nine months ended September 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 nine months ended September 30, 2011, we recorded a gain on sale of assets of $651,000 from the sale of assets in the Appalachian region.

Lease operating expense.  Our lease operating expenses increased $18.7 million, or 109%, for the nine months ended September 30, 2012, to $35.8 million ($10.32 per Boe) from $17.1 million ($14.60 per Boe) for the nine months ended September 30, 2011.  The decline in operating expense per Boe is due to the effect of adding new production, principally in our unconventional resource areas, at lower a 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 $7.2 million, or 156%, for the nine months ended September 30, 2012, to $11.7 million from $4.7 million for the nine months ended September 30, 2011.  All of the increase in severance taxes was attributable to the increase in oil and gas production.  Marketing expenses increased by $73,000, or 47%, for the nine months ended September 30, 2012, to $229,000 from $157,000 for the nine months ended September 30, 2011, due to production increases from our Eagle Ford Shale properties.

Exploration.  We incurred $1.1 million of exploration expense for the nine months ended September 30, 2012, compared to $1.1 million for the nine months ended September 30, 2011.

Impairment of oil and gas properties.  We provided for an impairment to the carrying value of certain unproved properties in the amount of approximately $25.6 million including $12.1 million of our North Dakota unproved oil and gas properties, and $5.0 million of our Appalachian acreage, which expired undrilled before September 30, 2012.  We also we wrote off $8.5 million of expired leases related to our Canadian properties.

Oilfield services segment expenses.  Oilfield services expenses increased by 40%, or $2.3 million, for the nine months ended September 30, 2012 to $8.2 million from $5.9 million for the nine months ended September 30, 2011.  Oilfield services expenses for the three months ended comprise expenses incurred in our drilling operations.

Midstream operations expenses.  Expenses from our Eureka Hunter Holdings midstream segment increased by $7.1 million, or 331%, for the nine months ended September 30, 2012, to $9.3 million from $2.2 million for the nine months ended September 30, 2011.  The increase in expenses resulted from the increased volume of natural gas products gathered by the pipeline network and gathering system, as well as expenses of $2.5 million related to leasing gas treating equipment.

Depletion, depreciation and accretion.  Our DD&A expense increased $61.8 million, or 216%, to $90.4 million for the nine months ended September 30, 2012, from $28.6 million for the nine months ended September 30, 2011 due to increased production during 2012.  Our DD&A per Boe increased by $1.67, or 7%, to $26.08 per Boe for the nine months ended September 30, 2012, compared to $24.40 per Boe for the nine months ended September 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 general and administrative expenses (“G&A”) decreased $1.2 million, or 2%, to $46.4 million ($13.39 per Boe) for the nine months ended September 30, 2012, from $47.6 million ($40.60 per Boe) for the nine months ended September 30, 2011.  G&A expenses decreased overall during the 2012 period due to lower acquisition costs and lower stock compensation recognized in the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.  Non-cash stock compensation totaled approximately $16.0 million ($4.62 per Boe) and $12.0 million ($10.25 per Boe) for the nine

46

months ended September 30, 2012 and 2011, respectively.  The nine months ended September 30, 2012 also included transaction costs of $3.6 million ($1.05 per Boe) related to acquisition activity.  The nine months ended September 30, 2011, included acquisition related costs of approximately $7.8 million ($6.68 per Boe) for legal, consulting and other costs related to the acquisitions of NGAS, NuLoch, and the PostRock assets which closed during the second quarter of 2011.  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 production growth of the Company.

Interest expense, net.  Our interest expense, net of interest income, increased approximately $32.6 million, or 474% to $39.6 million for the nine months ended September 30, 2012, from $7.0 million for the nine months ended September 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 of $9.4 million relating to our Senior Notes.  For the nine months ended September 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 revolving credit facility and the termination of our term loan.   During the nine months ended September 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 revolving credit facility in April of 2011.

Commodity derivative activities.  Realized gains and losses from our commodity derivative activity increased our earnings by approximately $8.0 million and decreased our earnings by approximately $554,000 for the nine months ended September 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 loss on commodity derivatives was approximately $3.1 million for the 2012 period and the unrealized gain was approximately $17.2 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.  The Company also has embedded derivatives in its Series A Convertible Preferred Units of Eureka Hunter Holdings and a promissory note received as partial consideration in the sale of Hunter Disposal. The unrealized gain on these embedded derivatives was $4.2 million for the nine months ended September 30, 2012.  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 $4.9 million and $16.7 million for the nine months ended September 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 $7.2 million for the nine months ended September 30, 2012, to reflect the change in the deferred tax liability of the Company’s Williston Hunter subsidiary.  For the nine months ended September 30, 2011, the Company recorded an income tax benefit of $470,000.

Net income attributable to non-controlling interest.  Net income attributable to non-controlling interest was approximately $71,000 for the nine months ended September 30, 2012 versus $172,000 for same period in 2011.

Loss from Continuing Operations.  We had a loss from continuing operations of $60.1 million for the 2012 period versus a loss of $21.9 million for the 2011 period, an increase of $38.2 million, or 174%.  This was primarily due to increases in lease operating expenses of $18.7 million, severance taxes and marketing expense of $7.2 million, gas gathering and processing expenses of $6.5 million, oil and gas property impairment of $25.6 million and interest expense of $32.6 million, depreciation, depletion, and accretion of $61.8 million, and a decrease of $11.8 million in derivative gains, partially offset by increases in revenues of $115.2 million and a decrease of general and administrative expenses of $1.2 million and increase in income tax benefit $6.8 million.

Income from Discontinued Operations.  On February 17, 2012, we closed on the sale of Hunter Disposal, LLC, previously a wholly owned subsidiary.  We have reclassified $354,000 and $2.2 million of net operating income (net of interest expense) of the divested subsidiary to discontinued operation for the nine month periods ended September 30, 2012 and 2011, respectively.  We have also reclassified the gain on sale of $4.3 million to discontinued operations for the nine months ended September 30, 2012.

Dividends on Preferred Stock.  Total dividends on our Series C and Series D Preferred Stock and the Series A Preferred Units of Eureka Hunter Holdings were approximately $22.7 million for the nine months ended September 30, 2012.  Dividends were $10.0 million for the nine months ended September 30, 2011.  The Series C Preferred Stock had a stated value of $100 million at both September 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 $206.9 million and $71.9 million at September 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 liquidation preference of $134.3 million and $0 at September 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 $80.2 million in the 2012 period versus $29.7 million in the 2011 period.  Our net loss per common share, basic and diluted was $0.53 per share for the nine months ended September 30, 2012, compared to net loss of $0.28 per share for the 2011 period.  Our weighted average shares outstanding increased by approximately 44.6 million shares, or 42%, from 106,651,326 shares in the 2011 period to 151,225,832 during the 2012 period.  Our net loss per share from continuing operations was $0.55 per share for the nine months ended September 30, 2012, versus a net loss of $0.30 per share from continuing operations for the 2011 period.  We had income from discontinued operations of

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$354,000 and a gain on sale of discontinued operations of $4.3 million on the sale of Hunter Disposal, LLC, which was sold on February 17, 2012.  Total income from discontinued operations was $4.7 million ($0.03 per share) for the nine months ended September 30, 2012.  We had income from discontinued operations of $2.2 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 senior 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 senior 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 senior revolving credit facility will be available, or acceptable on our terms, or at all, in the foreseeable future.

Under our senior revolving credit facility, our borrowing base at September 30, 2012, was $260.0 million, and our remaining borrowing capacity was $85.0 million on September 30, 2012.  Pursuant to the terms of the latest amendment of our senior revolving credit facility, our borrowing base was increased to $375.0 million as of November 6, 2012, an increase of $115.0 million.  At September 30, 2012, we had cash and cash equivalents of $22 million, of which $3.9 million was held by Eureka Hunter Holdings or its subsidiaries and was only available for use by Eureka Hunter Holdings or its subsidiaries, and a working capital deficit of $62.1 million.  As of November 12, 2012, we had over $150 million of liquidity, exclusive of 1,544,487 shares of Series D Preferred Stock available for issuance. 

The Eureka Hunter Pipeline revolving credit facility requires the testing of certain financial ratios prior to the actual funding of the credit facility.  The revolving credit facility currently is not available for funding.   We currently anticipate available borrowing capacity under the revolving credit facility with the reporting of the first quarter 2013 financial results.

On June 29, 2012, Eureka Hunter Pipeline entered into the Third Amendment to its Second Lien Term Loan Agreement, which increased the maximum total leverage ratio and decreased the minimum interest coverage ratio thereunder.  These amendments were necessary primarily due to the delay in the completion of MarkWest’s Mobley gas processing plant.

At September 30, 2012, we were in compliance with all of our covenants, as amended, contained in our senior revolving credit agreement and the Eureka Hunter Pipeline credit facilities.

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, (iv) our ability to issue Series D Preferred Stock under our existing ATM program and (iv) our ability to otherwise access the capital markets, provides sufficient means to conduct our operations, meet our contractual obligations, including our debt covenant requirements, as amended, and undertake our capital expenditure program for the twelve months ending September 30, 2013.

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

We intend to fund the remainder of our 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 market,  through sales of our Series D Preferred Stock and equity markets.  As of September 30, 2012, we had $85.0 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. The Company is anticipating further increases in the borrowing base under the senior revolving credit facility due to the increase in reserves from our organic drilling programs.  We intend to fund our activities in our Eureka Hunter Holdings midstream operations through our Eureka Hunter Pipeline credit facilities and the Ridgeline Series A Preferred Unit commitment.

For the nine months ended September 30, 2012, our primary sources of cash were from cash flows from operating activities, financing activities, and cash on hand at the beginning of the year.  Approximately $46.8 million of cash from operating activities, $444.0 million of proceeds from issuing the Senior Notes, $267.8 million of cash from sale of common and preferred stock and the proceeds from exercises of warrants, along with our $410.0 million of borrowings under our revolving credit facility, $19.0 million of borrowings under the second lien term loan, $2.0 million of borrowings under term loans, and $14.9 million of cash on hand were

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used to fund our acquisitions and drilling program, repay debt under our senior revolving credit facility, and pay deferred financing costs on our amended and restated credit facility.

For the nine months ended September 30, 2011, our primary sources of cash were from financing activities.  Approximately $94.0 million of cash from the sale of preferred stock and the proceeds from exercises of warrants, along with our $373.0 million of borrowings under our senior revolving credit facility and $35.6 million of proceeds from the second lien term loan and other loans, 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:

	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Cash flows provided by operating activities	$	46,819		$	10,257
Cash flows used in investing activities	(793,687		)	(273,519		)
Cash flows provided by financing activities	754,161			271,114
Effect of foreign currency exchange rates	(146		)	(231		)
Net increase (decrease) in cash and cash equivalents	$	7,147		$	7,621

Operating Activities

Our cash flow from operating activities was $46.8 million for the nine months ended September 30, 2012 compared to $10.3 million for the nine months ended September 30, 2011, an increase of $36.5 million.  This increase was due to increased oil and gas sales from the success of our drilling program as well as from our acquisitions completed during 2011 and 2012.

Investing Activities

Our cash used in investing activities for the nine months ended September 30, 2012 were $793.7 million, principally from acquisition and drilling activities.  We used $312.0 million in cash acquiring Bakken oil and gas properties from Baytex USA, Ltd, $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 $360.5 million in cash for drilling, average acquisition and midstream capital expenditures under our 2012 capital expenditures budget, which includes approximately $24.8 million in leasehold acquisitions, $31.8 million in capital expenditures for the Eureka Hunter Pipeline, and approximately $10.7 million in net payment of accrued capital expenditures.  Also during the nine months ended September 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 nine months ended September 30, 2011 were $273.5 million, which principally were a result of the acquisition and capital expenditures activity undertaken by the Company during the period. 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 nine months ended September 30, 2011, we used $2.8 million of cash for deposits on equipment, and we received proceeds from the sale of assets of $9.5 million. During the nine months ended September 30, 2011, we used $201.6 million in cash for capital expenditures which includes $20 million in cash for the acquisition of the Wetzel County assets from Windsor Marcellus, LLC, $4.9 million in cash in the third phase of the acquisition of assets from PostRock, and $176.7 million for capital expenditures under our 2011 capital expenditures budget as described below.

Financing Activities

Our cash flows from financing activities for the nine months ended September 30, 2012 were $754.7 million.  We issued $444.0 million of Senior Notes.  We used the proceeds from the offering to repay principal of $377.0 million of our senior revolving credit facility and retired the term note of $100.0 million.  We repaid $4.3 million on loans for other equipment. Eureka Hunter Pipeline also borrowed $19.0 million under its credit facility.  Other sources of cash from financing activities in the 2012 period were $148.3 million from the issuance of common stock, $119.5 million from the issuance of our Series D Preferred Stock, and $128.3 million from the issuance of Series A Preferred Units of Eureka Hunter Holdings, of which $60.0 million was distributed to Magnum Hunter. We also received $1.3 million in proceeds from exercise of stock options and warrants.  In the 2012 period we also incurred $18.4 million of deferred finance cost on loans and paid $17.5 million in dividends on our preferred stock.

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We borrowed $408.6 million under our revolving credit facility and other debt agreements and made principal repayments of $234.0 million during the 2011 period. In the 2011 period, we realized $7.1 million from the exercise of common stock options and warrants. We issued 1,190,544 shares of our Series C Cumulative Perpetual Preferred Stock in the 2011 period for net proceeds of $29.1 million, and we issued 1,421,237 shares of our Series D Preferred Stock in the 2011 period for net proceeds of $65.0 million. We also paid dividends of $10.0 million and used cash of $8.5 million for payment of deferred financing costs during the 2011 period.

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 for the twelve months ended September 30, 2013.  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 $500.0 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.

Weaknesses in Internal Controls

In October and November 2012, we identified material weaknesses in our internal controls over financial reporting in connection with (i) our lack of sufficient qualified personnel to design and manage an effective control environment, (ii ) our period-end financial reporting process and (iii) our share-based compensation.  We have promptly implemented, and are implementing, measures we believe will effectively address these weaknesses. However, any failure to do so could adversely affect our compliance with our reporting obligations under the Securities Exchange Act of 1934, and our compliance with our debt covenants, and therefore our ability to effect borrowings and readily access the capital markets to provide required liquidity.

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 estimated 2012 capital expenditures	$	375,000

(1)Funded through Eureka Hunter Pipeline credit facilities and Ridgeline Series A Preferred Unit investment.

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 under the senior revolving credit facility from $200 million to $235 million.

On May 2, 2012, the Company entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement.  The Sixth Amendment increased the borrowing base under the senior revolving credit facility 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 assets acquisition the borrowing base was increased from $187.5 million to $212.5 million.

On May 10, 2012, the Company entered into the Eighth Amendment to the Second Amended and Restated Credit Agreement.  Pursuant to the Eighth Amendment, the Company used a portion of the proceeds from the issuance of the Senior Notes to

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retire its term loan of $100.0 million, and the Company was required to have a minimum liquidity greater than $75.0 million after retiring the term loan in order to issue the Senior Notes.

On June 29, 2012, Eureka Hunter Pipeline, LLC entered into the Third Amendment to its 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 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 Credit Agreement such that after June 29, 2012, all interest shall be payable in cash.

On August 8, 2012, the Company entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement.  Pursuant to the Ninth Amendment, debt under the Senior Notes is limited to $550.0 million, provided that the maturity date of the Senior Notes may not be earlier that one year after the maturity date of the senior revolving credit facility and the Company shall not prepay any amounts owing under the Senior Notes at any time.  The Ninth Amendment also raises the amount that the Company can pay as cash dividends on its Series C and Series D Preferred Stock to $25.0 million in any calendar year. The Ninth Amendment also raised the borrowing base to $260.0 million.

On October 29, 2012, the Company entered into the Tenth Amendment to Second Amended and Restated Credit Agreement.  The Tenth Amendment permits the Company to issue a new Series E cumulative convertible preferred stock (the “Series E Stock”), of which 2774.85 shares were first issued in connection with the acquisition of Viking International Resources Co., Inc. by the Company’s subsidiary, Triad Hunter, LLC. In addition, the Tenth Amendment adds the Series E Stock to the list of securities eligible to receive dividends subject to the annual preferred stock basket of $25.0 million and other restrictions.

On November 7, 2012 the Company entered into the Eleventh Amendment to Second Amended and Restated Credit Agreement. The Eleventh Amendment amended the credit agreement to, among other things, increase the borrowing base thereunder from $260 million to $375 million. Of the increased borrowing base amount, $50 million has a maximum term through June 30, 2013 and is subject to certain required reduction events including, without limitation, a mandatory reduction from any interim increase in the $325 million borrowing base tranche before June 30, 2013. With the startup of MarkWest’s Mobley gas processing facility expected in the near future, Magnum Hunter will be able to increase its natural gas liquids proved developed reserves, which can be utilized to address any required payment of borrowings on June 30, 2013.

The Eleventh Amendment also increased the annual preferred stock dividend basket from $20.0 million to $40.0 million and amended the credit agreement to permit dividends for the Series E Stock on substantially the same terms as the existing Series C and Series D preferred stock of the Company.

In addition, the Eleventh Amendment amended the Total Debt to EBITDAX financial covenant in the credit agreement to require that such ratio not exceed (a) 4.5 to 1.0 for the fiscal quarter ended September 30, 2012 and the fiscal quarter ending December 31, 2012, (b) 4.25 to 1.0 for the fiscal quarter ending March 31, 2013 and (c) 4.0 to 1.0 for the fiscal quarter ending June 30, 2013 and for each fiscal quarter thereafter.

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 $0 and $81,000 for the three and nine months ended September 30, 2012, respectively and $160,000 and $388,000 for the three and nine months ended September 30, 2011, respectively.

We obtained accounting services and use of office space from GreenHunter Energy, Inc., an entity for which Mr. Evans is an officer, director and major shareholder, for which Mr. Ormand, our Chief Financial Officer and a director, is also a director, and for which Mr. Krueger, a Senior Vice President and our former Chief Accounting Officer, is Chief Financial Officer.  This agreement was terminated in 2011 and all accounting services are now controlled by Magnum Hunter personnel.  Professional services expenses totaled $0 for the three and nine months ended September 30, 2012, and $66,000 and $107,000 for the three and nine months ended September 30, 2011, respectively.

During the nine months ended September 30, 2012 and 2011, the Company paid rent of $23,000 and $23,000, 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 2012.

During the nine months ended September 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 $244,000 and approximately $875,000 for the three and nine months ended September 30, 2012, respectively, and $230,000 for the three and nine months ended September 30, 2011.  As of September 30, 2012, our net accounts payable to GreenHunter Energy, Inc. was $2,000 for these leases.  Additionally, these companies regularly obtain services from GreenHunter Energy, Inc. for water disposal.  Disposal charges totaled $618,000 and $1.6 million for the three and nine months ended September 31, 2012.

During the nine months ended September 30, 2012, Alpha Hunter Drilling, LLC, a wholly owned subsidiary of the Company, performed drilling operations for GreenHunter Energy, Inc. for a fee.  Drilling revenues totaled $359,000 for the three and nine

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months ended September 30, 2012, and our net accounts receivable from GreenHunter Energy, Inc. for these services was $359,000 as of September 30, 2012.

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 an independent special committee of the Company.  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 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 Triad Hunter.  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.  The Company has recorded interest income as a result of the note receivable from GreenHunter Energy, Inc, in the amounts of $55,000 and $110,000 for the three and nine months ended September 30, 2012, respectively.  As a result of this transaction, the Company has an investment in GreenHunter Energy, Inc. that is recorded under the equity method.  The loss related to this investment was $97,000 for the three months ended September 30, 2012, and $299,000 for the nine months ended September 30, 2012.

Mr. Evans, our Chairman and Chief Executive Officer, was a 4.0% limited partner in TransTex Gas Services, LP, which limited partnership received total consideration of 622,641 Class A common units of Eureka Hunter Holdings, and cash of $46.0 million upon the Company’s acquisition of certain of its assets.  This includes units issued in accordance with the agreement of Eureka Hunter

Holdings and TransTex to provide the limited partners of TransTex the opportunity to purchase additional Class A common units of Eureka Hunter Holdings in lieu of a portion of the cash distributions 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 and gas transportation 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 Pipeline 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 revolving credit facility, which was 3.48% at September 30, 2012.  The term equipment debt had an average interest rate of approximately 4.85% at September 30, 2012.  See Note 10 in our condensed consolidated financial statements.

As of September 30, 2012, we rent various office spaces in Houston, Texas, that represent approximately 15,000 square feet at a cost of $22,000 per month for the remaining terms ranging from fifteen to forty-three months.  Triad Hunter had various lease commitments for periods ranging from three to sixty-two months at September 30, 2012, and with monthly payments of approximately $24,000 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 $33,000 as of September 30, 2012.

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 $12.2 million as of September 30, 2012.

On December 14, 2011, the Company entered into a one hundred twenty month gas transportation contract.  The contract became effective on August 1, 2012.  Our remaining liability under the contract was approximately $25.5 million as of September 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 one to three 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 September 30, 2012.

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

Contractual Obligations	Total		2012		2013 –2014		2015 - 2016		After 2016
Long-term debt(1)	$	683,993	$	939	$	5,847	$	181,855	$	495,352
Interest on long-term debt(2)	394,145		13,950		111,538		107,070		161,587
Operating lease obligations(3)	2,131		286		1,207		496		142
Asset retirement obligations(4)	22,405		1,445		2,998		1,536		16,426
Employment agreements with executive officers	472		472		—		—		—
Drilling contract commitment	12,201		1,497		10,704		—		—
Gas transportation contract commitment	25,549		852		5,110		5,110		14,477
Total	$	1,140,896	$	19,441	$	137,404	$	296,067	$	687,484

(1)	See Note 10 to our consolidated financial statements for a discussion of our long-term debt.
(2)	Interest payments have been calculated by applying the weighted average interest rate of 5.77% on the debt facilities in place as of September 30, 2012.
(3)	Operating lease obligations are for office space and equipment.
(4)	See Note 7 to our consolidated financial statements for a discussion of our asset retirement obligations.

Refer to Note 12 — Shareholders’ Equity and Redeemable Preferred Stock for a discussion of certain of our other contractual commitments.

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 September 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.

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

			Weighted Avg
Natural Gas	Period	MMBTU/day	Price per MMBTU
Collars	Oct 2012 - Dec 2012	11,910	$4.58 - $6.42
	Jan 2013 - Dec 2013	12,500	$4.50 - $5.96
Swaps	Oct 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	Oct 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)	Oct 2012 - Dec 2012	50	$55.00 - $75.00 - $108.00
	Jan 2013 - Dec 2013	2,000	$60.63 - $80.00 - $100.00
	Jan 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Three-way collars (2)	Jan 2013 - Dec 2013	763	$65.00 - $91.25 - $101.25
Swaps	Oct 2012 - Dec 2012	3,500	$90.55
	Jan 2013 - Dec 2013	1,000	$91.46
Ceilings sold (call)	Oct 2012 - Dec 2012	688	$100.30
Ceilings purchased (call)	Oct 2012 - Dec 2012	688	$91.25
Floors sold (put)	Oct 2012 - Dec 2012	2,290	$80.00
	Jan 2013 - Dec 2013	1,438	$65.00
	Jan 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00
Floors purchased (put)	Oct 2012 - Dec 2012	2,443	$94.06

(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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At September 30, 2012, the fair value of our open derivative contracts was a net liability of approximately $8.1 million.

Currently, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, UBS AG London Branch, Deutsche Bank AG London Branch, Citibank, N.A., and J. Aron & Company 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 or their affiliates 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 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 $8.0 million and decreased our earnings by approximately $554,000 for the nine months ended September 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 loss on commodity derivatives was approximately $3.1 million for the 2012 period and the unrealized gain was approximately $17.2 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 $4.9 million and a gain of approximately $16.7 million for the nine months ended September 30, 2012 and 2011, respectively.  (See Note 7 to our condensed consolidated financial statements for more information.)

For the three months ended September 30, 2012, we recorded an unrealized loss on commodity derivatives of approximately $17.8 million, compared to an unrealized gain of approximately $17.4 million for the three months ended September 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 $34.7 million decrease in the fair value of our commodity derivative positions recorded on our balance sheet at September 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 September 30, 2012.  A hypothetical 10% decrease in commodity prices would have resulted in a $32.1 million increase in the fair value of our commodity derivative position recorded on our balance sheet at September 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 September 30, 2012.

Item 4. Controls and procedures.

Restatement of Previously Issued Financial Statements

On October 12, 2012, management (“we”) of Magnum Hunter Resources Corporation (the “Company”) identified an error in the calculation of non-cash share-based compensation expense relating to common stock options granted to employees by the Compensation Committee during the second quarter of fiscal year 2012. The non-cash share-based compensation expense was understated due to the misapplication of the vesting schedule of such options (specifically, the Company’s calculations did not take into account that 25% of such options were immediately exercisable on the date of grant). The error affected our previously issued financial statements contained in the Company’s Quarterly Report on Form 10-Q, as filed with the Securities and Exchange Commission (“SEC”) on August 9,2012 (the “Affected Filing”). The misstatement understated general and administrative expenses, net loss attributable to common shareholders and net loss by approximately $3.8 million for the three and six month periods ended June 30, 2012. The error also affected our disclosures regarding share-based compensation expense for the three and six month periods ended June 30, 2012. As a result, the Company filed a Form 8-K on October 22, 2012 stating that the previously issued financial statements contained in the Affected Filing should no longer be relied upon and filed Amendment No. 1 to Form 10-Q on Form 10-Q/A for the three and six month periods ended June 30, 2012 on November 14, 2012 (the “Restated Financial Statements”).

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In addition, we identified an error during November 2012 in the accounting treatment and reporting of a financing transaction completed in March 2012 for the sale of Series A Convertible Preferred Units of our majority owned subsidiary, Eureka Hunter Holdings, LLC (“Eureka Hunter”) which resulted in the understatement of commodity and preferred stock embedded derivative liabilities of $44.1 million, an overstatement of Series A Convertible Preferred Units of Eureka Hunter of $44.3 million and an overstatement of gain on derivatives of $3.6 million and $1.4 million for the three and six month periods ended June 30, 2012, respectively and a misstatement of the related disclosures. The amounts and disclosures as included in the Affected Filing were also corrected in Note 2 to the Restated Financial Statements.

Evaluation of disclosure controls and procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance 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 provide reasonable assurance 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 September 30, 2012. Based on this evaluation, our CEO and CFO have concluded that, as of September 30, 2012, our disclosure controls and procedures were not effective due to the material weaknesses described below.

To address the material weaknesses described in this Item 4, we performed additional analyses and other post-closing procedures designed to provide reasonable assurance that our consolidated financial statements were prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”). As a result of these procedures, we believe that the consolidated financial statements included in this report fairly present, in all material respects, our financial condition, results of operations, changes in stockholders’ equity and cash flows for the periods presented, in conformity with US GAAP.

Limitations inherent in all controls

Our management, including the CEO and CFO, recognizes that the disclosure controls and procedures (discussed above) and internal controls over financial reporting may not prevent or detect misstatements or fraud. Any controls system, no matter how well designed and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of such limitations there is a risk that material misstatements or instances of fraud will not be prevented or detected on a timely basis by the financial reporting process. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Material Weaknesses

A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

In connection with the restatements and audit adjustments identified, management identified the material weaknesses described below.

Lack of sufficient, qualified personnel to design and manage an effective control environment. We did not design an effective control environment with the sufficient complement of personnel with the appropriate level of accounting knowledge, experience, and training in US GAAP to assess the completeness and accuracy of the accounting for complex accounting matters, principally related to equity instruments including convertible preferred stock and related arrangements. This material weakness resulted in the restatement of our Series A Convertible Preferred Units of Eureka Hunter, our commodity and preferred stock embedded derivative liabilities and our loss on derivatives and related disclosures for the three and six month periods ended June 30, 2012 discussed above and resulted in audit adjustments to our condensed consolidated financial statements for the three and nine month periods ended September 30, 2012. This material weakness also contributed to the material weaknesses described below.

Period-end financial reporting process. We did not maintain effective controls over the period-end financial reporting process, including controls with respect to the preparation, review, supervision, and monitoring of accounting operations. Specifically, we did not maintain effective controls to provide reasonable assurance that monthly account reconciliations were reviewed on a timely basis and that monthly and quarterly financial information was prepared and reviewed timely. This material weakness resulted in audit adjustments to our condensed consolidated financial statements for the three and nine month periods ended September 30, 2012.

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Share-based compensation. We did not design effective controls over share-based compensation expense, which is recorded in our general and administrative expenses. Specifically, we did not design effective controls related to the review of supporting details, including the completeness and accuracy of the vesting schedule and the journal entries for share-based compensation expenses. This control deficiency resulted in a misstatement of our general and administrative expense and share-based compensation related disclosures for the three and six month periods ended June 30, 2012 and resulted in the restatement discussed above.

Additionally, the material weaknesses described above could result in misstatements that would result in a material misstatement of the consolidated financial statements in a future annual or interim period that would not be prevented or detected.

Changes in Internal Control over Financial Reporting

Except for the material weaknesses discussed above and the remediation plans executed as of September 30, 2012 as noted below, 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 September 30, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Remediation Plans

We have initiated several steps and plan to continue to implement measures designed to improve our internal control over financial reporting and disclosure controls and procedures in order to remediate the material weaknesses, noted specifically above.

To remediate the material weakness in our control environment, we have implemented management changes to establish an environment necessary to prevent or detect potential deficiencies in the preparation of our financial statements and controls to support our desired internal control over financial reporting and disclosure controls and procedures. On October 23, 2012, we hired a new Chief Accounting Officer with the appropriate knowledge and experience to establish and maintain our desired control environment. We will implement more formalized processes and controls to identify, review and document accounting treatment of complex capital-raising instruments. To implement these processes and controls related to the complete and timely evaluation of technical accounting issues, we will continue to add staff and/or seek assistance from outside consultants, as warranted. Accordingly, we are in the process of expanding our accounting department to respond to the recent growth of the Company. These additions include an Assistant Controller hired in July, 2012, Division Controller hired in November, 2012, and Internal Audit Manager hired in August, 2012 and other accounting personnel are being recruited for additional positions. We believe that the personnel we have recently added and that we plan to add, in combination with the other initiatives explained herein, will enable us to improve the scope and quality of our internal review of complex technical accounting matters and financial reporting and remediate this material weakness, as well as aid in the remediation of the other two material weaknesses identified.

We are realigning the responsibilities and accountability in the financial reporting process and implementing additional monitoring and detective controls to remediate the material weakness in period-end financial reporting processes. These additional controls include: checklists to ensure appropriate reviews of reconciliations are performed on a timely basis and a financial close timetable and reporting calendar by department that will be monitored by the Chief Accounting Officer to ensure these reviews are completed on timely basis to allow sufficient time for review by management and permit the timely preparation and review of monthly and quarterly financial statements.

We plan to implement additional review controls and other controls with regard to share based compensation activity around the completeness and accuracy of the schedules and related inputs including reviewer checklists to ensure all inputs and calculations are complete and accurate. We are in the process of implementing these controls and will rely on the controls while we continue to implement a new software system to track stock option activity and the related compensation expense and disclosures.

We believe the foregoing efforts will effectively remediate the material weaknesses. As we continue to evaluate and work to improve our internal control over financial reporting, we may execute additional measures to address potential control deficiencies or modify the remediation plan described above.

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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.

We have identified certain weaknesses in our internal controls, which we are remediating, but failure to do so could adversely affect our capital raising ability.

In October and November 2012, we identified material weaknesses in our internal controls over financial reporting in connection with (i) our lack of sufficient qualified personnel to design and manage an effective control environment, (ii )our period-end financial reporting process and (iii) our share-based compensation.  We have promptly implemented, and are implementing, measures we believe will effectively address these weaknesses. However, any failure to do so could adversely affect our compliance with our reporting obligations under the Securities Exchange Act of 1934, and our compliance with our debt covenants, and therefore our ability to effect borrowings and readily access the capital markets to provide required liquidity.

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

None.

Item 6. Exhibits.

Exhibit Number	Description
2.1	Stock Purchase Agreement, dated as of October 24, 2012, by and among Triad Hunter, LLC, Viking International Resources Co., Inc., all of the stockholders of Viking International Resources Co., Inc., and solely for the purposes set forth therein, the Registrant (Incorporated by reference from the Registrant’s current report on Form 8-K filed on October 30, 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).

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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).
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).
4.3	Certificate of Designation of Rights and Preferences of 8.0% Series D Cumulative Preferred Stock of the Registrant, dated March 16, 2011 (Incorporated by reference from the Registrant’s current report on Form 8-K filed on March 17, 2011).
4.4	Certificate of Designations of Rights and Preferences of the 8.0% Series E Cumulative Convertible Preferred Stock of the Registrant, dated November 2, 2012 (Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012)
4.5	Deposit Agreement, dated as of November 2, 2012, by and among the Registrant, American Stock Transfer & Trust Company, as Depositary, and the holders from time to time of the depositary reciepts described therein (Incorporated by reference from the Registrant’s current report on Form 8-K filed on November 8, 2012)
10.1	Ninth Amendment to Second Amended and Restated Credit Agreement, dated August 8, 2012, by and among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders and guarantors party thereto (Incorporated by reference from the Registrant’s current report on Form 8-K filed on August 13, 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.^
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.^

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+	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 will be furnished pursuant to an amended report on Form 10-Q/A to be filed subsequent to the filling of this report. In accordance with Rule 406T of Regulation S-T, these exhibits will 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, and will not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise will not be 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: November 14, 2012		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman and Chief Executive Officer
Date: November 14, 2012		/s/ Ronald D. Ormand
		Ronald D. Ormand,
		Executive Vice President and Chief Financial Officer
Date: November 14, 2012		/s/ Fred J. Smith, Jr.
		Fred J. Smith, Jr.,
		Senior Vice President and Chief Accounting Officer

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