Magnum Hunter Resources 10-Q 2014 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, 2014 

-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) (Zip Code)

(832) 369-6986

(Registrant's telephone number, including area code)

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 6, 2014, there were 199,905,010 shares of the registrant’s common stock ($0.01 par value) outstanding.

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED September 30, 2014

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited):
Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	1
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013	3
Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2014 and 2013	4
Consolidated Statement of Shareholders’ Equity for the Nine Months Ended September 30, 2014	5
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013	6
Notes to Consolidated Financial Statements	7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	52
Item 3. Quantitative and Qualitative Disclosures About Market Risk	84
Item 4. Controls and Procedures	87
Part II. OTHER INFORMATION	88
Item 1. Legal Proceedings	88
Item 1A. Risk Factors	88
Item 3. Defaults Upon Senior Securities	89
Item 5. Other Information	89
Item 6. Exhibits	89
SIGNATURES	90

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

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

(unaudited)

	September 30, 2014		December 31, 2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	42,667	$	41,713
Restricted cash	—		5,000
Accounts receivable:
Oil and natural gas sales	22,276		25,099
Joint interests and other, net of allowance for doubtful accounts of $702 at September 30, 2014 and $196 at December 31, 2013	18,053		30,582
Derivative assets	1,954		608
Inventory	3,039		7,158
Investments	8,230		2,262
Prepaid expenses and other assets	4,832		2,938
Assets held for sale	—		5,366
Total current assets	101,051		120,726
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting, net	1,322,406		1,224,659
Gas transportation, gathering and processing equipment and other, net	468,908		289,420
Total property, plant and equipment, net	1,791,314		1,514,079
OTHER ASSETS
Deferred financing costs, net of amortization of $18,461 at September 30, 2014 and $9,735 at December 31, 2013	17,511		20,008
Derivative assets, long-term	255		25
Intangible assets, net	5,025		6,530
Goodwill	30,602		30,602
Assets held for sale	86,362		162,687
Other assets	1,445		1,994
Total assets	$	2,033,565	$	1,856,651

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

1

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS (Continued)

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

(unaudited)

	September 30, 2014			December 31, 2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Current portion of notes payable	$	8,670		$	3,804
Accounts payable	199,577			107,837
Accounts payable to related parties	355			23
Accrued liabilities	36,895			44,629
Revenue payable	5,911			6,313
Derivative liabilities	48			1,903
Liabilities associated with assets held for sale	—			12,865
Other liabilities	3,786			6,491
Total current liabilities	255,242			183,865
NONCURRENT LIABILITIES
Long-term debt	949,792			876,106
Asset retirement obligations	25,176			16,163
Derivative liabilities, long-term	173,271			76,310
Other long-term liabilities	5,382			2,279
Long-term liabilities associated with assets held for sale	1,619			14,523
Total liabilities	1,410,482			1,169,246
COMMITMENTS AND CONTINGENCIES (Note 16)
REDEEMABLE PREFERRED STOCK
Series C Cumulative Perpetual Preferred Stock ("Series C Preferred Stock"), cumulative dividend rate 10.25% per annum, 4,000,000 authorized, 4,000,000 issued and outstanding as of September 30, 2014 and December 31, 2013, with a liquidation preference of $25.00 per share	100,000			100,000
Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC (the "Eureka Hunter Holdings Series A Preferred Units"), cumulative distribution rate of 8.0% per annum, 10,592,540 and 9,885,048 issued and outstanding as of September 30, 2014 and December 31, 2013, respectively, with a liquidation preference of $271,410 and $200,620 as of September 30, 2014 and December 31, 2013, respectively	151,685			136,675
	251,685			236,675
SHAREHOLDERS’ EQUITY
Preferred stock of Magnum Hunter Resources Corporation, 10,000,000 shares authorized, including authorized shares of Series C Preferred Stock
Series D Cumulative Preferred Stock ("Series D Preferred Stock"), cumulative dividend rate 8.0% per annum, 5,750,000 authorized, 4,424,889 issued and outstanding as of September 30, 2014 and December 31, 2013, with a liquidation preference of $50.00 per share	221,244			221,244
Series E Cumulative Convertible Preferred Stock ("Series E Preferred Stock"), cumulative dividend rate 8.0% per annum, 12,000 authorized, 3,803 issued and 3,722 outstanding as of September 30, 2014 and December 31, 2013, with a liquidation preference of $25,000 per share	95,069			95,069
Common stock, $0.01 par value per share, 350,000,000 shares authorized, and 200,812,979 and 172,409,023 issued, and 199,898,027 and 171,494,071 outstanding as of September 30, 2014 and December 31, 2013, respectively	2,008			1,724
Additional paid in capital	923,679			733,753
Accumulated deficit	(879,005		)	(586,365		)
Accumulated other comprehensive loss	(3,566		)	(19,901		)
Treasury stock, at cost:
Series E Preferred Stock, 81 shares as of September 30, 2014 and December 31, 2013	(2,030		)	(2,030		)
Common stock, 914,952 shares as of September 30, 2014 and December 31, 2013	(1,914		)	(1,914		)
Total Magnum Hunter Resources Corporation shareholders’ equity	355,485			441,580
Non-controlling interest	15,913			9,150
Total shareholders’ equity	371,398			450,730
Total liabilities and shareholders’ equity	$	2,033,565		$	1,856,651

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

2

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2014			2013			2014			2013
REVENUES AND OTHER
Oil and natural gas sales	$	62,510		$	59,061		$	222,247		$	156,772
Natural gas transportation, gathering, processing, and marketing	10,285			12,545			90,461			42,854
Oilfield services	5,986			6,423			17,561			13,728
Other revenue	889			262			1,346			1,005
Total revenue	79,670			78,291			331,615			214,359
OPERATING EXPENSES
Lease operating expenses	24,482			19,587			64,612			48,689
Severance taxes and marketing	6,163			5,554			18,847			12,983
Exploration	27,284			41,978			52,394			75,257
Impairment of proved oil and gas properties	22,886			23,547			39,798			39,467
Natural gas transportation, gathering, processing, and marketing	4,954			8,985			79,707			35,830
Oilfield services	3,856			4,527			11,892			11,928
Depletion, depreciation, amortization and accretion	36,370			29,127			101,733			80,141
Loss (gain) on sale of assets, net	(8,000		)	40,952			(4,612		)	42,114
General and administrative	19,251			23,908			56,027			63,673
Total operating expenses	137,246			198,165			420,398			410,082
OPERATING LOSS	(57,576		)	(119,874		)	(88,783		)	(195,723		)
OTHER INCOME (EXPENSE)
Interest income	40			35			126			217
Interest expense	(18,095		)	(15,759		)	(62,473		)	(53,352		)
Loss on derivative contracts, net	(49,636		)	(29,553		)	(92,125		)	(30,644		)
Other income	2,078			12,056			2,102			14,544
Total other expense, net	(65,613		)	(33,221		)	(152,370		)	(69,235		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(123,189		)	(153,095		)	(241,153		)	(264,958		)
Income tax benefit	—			582			—			47,227
LOSS FROM CONTINUING OPERATIONS, NET OF TAX	(123,189		)	(152,513		)	(241,153		)	(217,731		)
Income (loss) from discontinued operations, net of tax	—			(75,573		)	4,561			(62,453		)
Gain (loss) on disposal of discontinued operations, net of tax	(258		)	(69,521		)	(13,983		)	102,931
NET LOSS	(123,447		)	(297,607		)	(250,575		)	(177,253		)
Net loss attributed to non-controlling interests	2,764			725			3,653			1,614
LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	(120,683		)	(296,882		)	(246,922		)	(175,639		)
Dividends on preferred stock	(15,492		)	(14,417		)	(45,718		)	(42,034		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(136,175	)	$	(311,299	)	$	(292,640	)	$	(217,673	)
Weighted average number of common shares outstanding, basic and diluted	199,448,453			169,953,997			185,440,763			169,752,042
Loss from continuing operations per share, basic and diluted	$	(0.68	)	$	(0.98	)	$	(1.53	)	$	(1.52	)
Income (loss) from discontinued operations per share, basic and diluted	—			(0.85		)	(0.05		)	0.24
NET LOSS PER COMMON SHARE, BASIC AND DILUTED	$	(0.68	)	$	(1.83	)	$	(1.58	)	$	(1.28	)
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
Loss from continuing operations, net of tax	$	(120,425	)	$	(151,788	)	$	(237,500	)	$	(216,117	)
Income (loss) from discontinued operations, net of tax	(258		)	(145,094		)	(9,422		)	40,478
Net loss	$	(120,683	)	$	(296,882	)	$	(246,922	)	$	(175,639	)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

3

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)

(in thousands)

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2014			2013			2014			2013
NET LOSS	$	(123,447	)	$	(297,607	)	$	(250,575	)	$	(177,253	)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation gain (loss)	—			3,856			(1,218		)	(7,943		)
Unrealized gain (loss) on available for sale investments	(2,583		)	3,735			(3,188		)	8,184
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	—			(8,262		)	—			(8,262		)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	—			—			20,741			—
Total other comprehensive income (loss)	(2,583		)	(671		)	16,335			(8,021		)
COMPREHENSIVE LOSS	(126,030		)	(298,278		)	(234,240		)	(185,274		)
Comprehensive loss attributable to non-controlling interests	2,764			725			3,653			1,614
COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	$	(123,266	)	$	(297,553	)	$	(230,587	)	$	(183,660	)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

4

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OFSHAREHOLDERS' EQUITY

(unaudited)

(in thousands)

	Number of Shares
	Series D Preferred Stock	Series E Preferred Stock	Common Stock	Series D Preferred Stock		Series E Preferred Stock		Common Stock		Additional Paid in Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (loss)			Treasury Stock			Non - controlling Interest			Total Shareholders’ Equity
BALANCE, January 1, 2014	4,425	4	172,409	$	221,244	$	95,069	$	1,724	$	733,753		$	(586,365	)	$	(19,901	)	$	(3,944	)	$	9,150		$	450,730
Share-based compensation	—	—	71	—		—		1		5,673			—			—			—			—			5,674
Shares of common stock issued for payment of 401k plan matching contribution	—	—	249	—		—		2		1,591			—			—			—			—			1,593
Sale of common stock	—	—	25,729	—		—		257		178,175			—			—			—			—			178,432
Dividends on preferred stock	—	—	—	—		—		—		—			(45,718		)	—			—			—			(45,718		)
Shares of common stock issued upon exercise of common stock options	—	—	2,355	—		—		24		9,598			—			—			—			—			9,622
Repurchase of non-controlling interest	—	—	—	—		—		—		(5,111		)	—			—			—			2,236			(2,875		)
Issuance of Eureka Hunter Holdings Series A Common Stock	—	—	—	—		—		—		—			—			—			—			8,180			8,180
Net loss	—	—	—	—		—		—		—			(246,922		)	—			—			(3,653		)	(250,575		)
Foreign currency translation	—	—	—	—		—		—		—			—			(1,218		)	—			—			(1,218		)
Unrealized loss on available for sale securities, net	—	—	—	—		—		—		—			—			(3,188		)	—			—			(3,188		)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	—	—	—	—		—		—		—			—			20,741			—			—			20,741
BALANCE, September 30, 2014	4,425	4	200,813	$	221,244	$	95,069	$	2,008	$	923,679		$	(879,005	)	$	(3,566	)	$	(3,944	)	$	15,913		$	371,398

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

5

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)

	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(250,575	)	$	(177,253	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	101,733			107,624
Exploration	51,306			91,533
Impairment of proved oil and gas properties	39,798			88,504
Impairment of other operating assets	666			263
Share-based compensation	7,267			11,834
Cash paid for plugging wells	(26		)	(14		)
Loss (gain) on sale of assets	9,371			(50,063		)
Unrealized loss on derivative contracts	88,051			23,757
Unrealized loss on investments	504			1,043
Amortization and write-off of deferred financing costs and discount on Senior Notes included in interest expense	8,809			3,660
Deferred tax benefit	—			(54,465		)
Changes in operating assets and liabilities:
Accounts receivable, net	20,742			(703		)
Inventory	4,681			77
Prepaid expenses and other current assets	(2,766		)	(3,095		)
Accounts payable	(50,851		)	23,303
Revenue payable	(2,336		)	(3,027		)
Accrued liabilities	(12,819		)	16,219
Net cash provided by operating activities	13,555			79,197
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and advances	(363,304		)	(418,245		)
Change in restricted cash	5,000			1,500
Change in deposits and other long-term assets	310			571
Proceeds from sales of assets	110,690			460,997
Net cash provided by (used in) investing activities	(247,304		)	44,823
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from sale of common shares	178,432			—
Net proceeds from sale of preferred shares	—			10,181
Equity issuance costs	—			(109		)
Proceeds from sale of Eureka Hunter Holdings Series A Preferred Units	11,956			27,440
Proceeds from sale of Eureka Hunter Holdings Series A Common Units	8,180			—
Repurchase of non-controlling interest	(2,875		)	—
Proceeds from exercise of warrants and options	9,622			1,932
Preferred stock dividend	(36,754		)	(29,911		)
Repayments of debt	(208,298		)	(379,504		)
Proceeds from borrowings on debt	279,592			245,991
Deferred financing costs	(6,228		)	(1,184		)
Change in other long-term liabilities	1,032			(1,103		)
Net cash provided by (used in) financing activities	234,659			(126,267		)
Effect of changes in exchange rate on cash	44			(93		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	954			(2,340		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	41,713			57,623
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	42,667		$	55,283

The accompanying Notes to the Consolidated Financial Statements are an integral part of these unaudited financial statements.

6

MAGNUM HUNTER RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1 - GENERAL

Organization and Nature of Operations

Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (together with its subsidiaries, the "Company" or "Magnum Hunter"), is a Houston, Texas based independent exploration and production company engaged in the United States in the acquisition and development of producing properties and undeveloped acreage and the production of oil and natural gas, along with certain midstream and oilfield services activities.

Presentation of Consolidated Financial Statements

The accompanying unaudited interim consolidated financial statements of Magnum Hunter are presented in U.S. Dollars and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP"). The preparation of these consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during reporting periods. Actual results could differ materially from those estimates.

In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the 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 balance sheet data were derived from audited financial statements, but do not include all disclosures required by GAAP. 

Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with GAAP that would substantially duplicate the disclosures contained in the audited consolidated financial statements as reported in the Company's Annual Report on Form 10-K have been condensed or omitted. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2013, as amended.

Non-Controlling Interest in Consolidated Subsidiaries

The Company has consolidated Eureka Hunter Holdings, LLC ("Eureka Hunter Holdings") in which it owned 57.5% as of September 30, 2014 and 56.4% as of December 31, 2013. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), TransTex Hunter, LLC ("TransTex Hunter"), and Eureka Hunter Land, LLC.

On December 30, 2013, PRC Williston, LLC ("PRC Williston"), in which the Company owned 87.5% as of December 31, 2013, sold substantially all of its assets. On July 24, 2014, the Company executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, the Company now owns 100% of the equity interests in PRC Williston and has all rights and claims to its remaining assets and liabilities, which are not significant. Consequently, there is no longer any non-controlling interest in PRC Williston's equity reflected in the consolidated financial statements as of September 30, 2014.

The consolidated financial statements also reflect the interests of our wholly-owned subsidiary Magnum Hunter Production, Inc. ("MHP") in various managed drilling partnerships. The Company accounts for the interests in these managed drilling partnerships using the proportionate consolidation method.

Reclassification of Prior-Period Balances

Certain prior period balances have been reclassified to correspond with current-year presentation.  As a result of the Company's decision in September 2014 to withdraw its plan to divest of its 100% equity interest in MHP and cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented, and all assets and liabilities of MHP that were previously reported as assets and liabilities held for sale in our consolidated balance sheet have been reclassified to assets and liabilities held for use as of September 30, 2014. See "Note 2 - Divestitures and Discontinued Operations". 

7

Regulated Activities

Energy Hunter Securities, Inc. ("Energy Hunter Securities") is a 100%-owned subsidiary and is a registered broker-dealer and member of the Financial Industry Regulatory Authority ("FINRA"). 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. Because it does not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness. As of September 30, 2014 and December 31, 2013, Energy Hunter Securities had net capital of $83,204 and $77,953, respectively, and aggregate indebtedness of $8,494 and $16,657, respectively.

During the third quarter of 2014, the Company initiated a process to wind down Energy Hunter Securities. This process included making an initial filing with FINRA and will include an audit of Energy Hunter Securities by FINRA which is anticipated to commence during the fourth quarter of 2014. On September 26, 2014, Energy Hunter Securities filed a Uniform Request for Withdrawal From Broker-Dealer Registration with the Securities and Exchange Commission ("SEC"). As of September 30, 2014, Energy Hunter Securities' request was still pending approval from FINRA and the SEC.

Sentra Corporation, a 100%-owned subsidiary, owns and operates distribution systems for retail sales of natural gas in south central Kentucky. Sentra Corporation's gas distribution billing rates are regulated by the Kentucky Public Service Commission based on recovery of purchased gas costs. The Company accounts for its operations based on the provisions of the Financial Accounting Standards Board's ("FASB") Accounting Standards Codification ("ASC") Subtopic 980-605, Regulated Operations-Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. During the three and nine months ended September 30, 2014, the Company had gas transmission, compression and processing revenue, which included gas utility sales from Sentra Corporation's regulated operations aggregating $27,656 and $473,555, respectively. During the three and nine months ended September 30, 2013, the Company had revenues of $215,618 related to Sentra Corporation's regulated operations.

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules.  The Company regularly reviews all new pronouncements to determine their impact, if any, on its financial statements.

In March 2013, the FASB issued Accounting Standards Update ("ASU") 2013-05, Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity, to provide guidance on whether to release cumulative translation adjustments ("CTA") upon certain derecognition events. ASU 2013-05 requires a parent company to apply the guidance in ASC Subtopic 830-30 when an entity ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity. Consequently, the CTA related to a foreign entity is released into net income only if the transaction results in complete or substantially complete liquidation of the foreign entity in which the subsidiary or group of assets resided; otherwise, no portion of the CTA is released.  The Company adopted this pronouncement prospectively on January 1, 2014. The adoption of this updated standard did not have a material impact on the Company’s consolidated financial statements.

In July 2013, the FASB issued ASU 2013-11, Presentation of Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, an amendment to FASB ASC Topic 740, Income Taxes ("FASB ASC Topic 740"). This update clarified that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The Company adopted this ASU prospectively on January 1, 2014. The adoption of this accounting standard update did not have a material impact on the Company's consolidated financial statements or its financial statement disclosures.

In April 2014, the FASB issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 updates the requirements for reporting discontinued operations in ASC Subtopic 205-20, Presentation of Financial Statements - Discontinued Operations, by requiring classification as discontinued operations of a component of an entity or a group of components of an entity if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when either 1) the component or group of components of an entity meet the criteria to be classified as held for sale, 2) are disposed of by sale, or 3) are disposed of other than by sale (e.g. abandonment or a distribution to owners in a spinoff). The amendments in this update expand the disclosure requirements related to discontinued operations and

8

disposals of individually significant components that do not qualify for discontinued operations presentation in the financial statements. This ASU is effective prospectively for all disposals (or classification as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: identify the contract(s) with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. This amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The guidance allows for either a "full retrospective" adoption or a "modified retrospective" adoption, however early application is not permitted. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation - Stock Compensation: Accounting for Share Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 clarifies that a performance target that affects vesting and that could be achieved after the requisite service period should be treated as a performance condition. An entity should apply existing guidance in ASC Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. This amendment is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern: Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This update requires an entity’s management to evaluate for each annual and interim reporting period whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued. The update further requires certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, and requires an express statement and other disclosures when substantial doubt is not alleviated. This amendment is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

NOTE 2 - DIVESTITURES AND DISCONTINUED OPERATIONS

Assets Held for Sale

On September 17, 2014, Bakken Hunter, LLC, a wholly-owned subsidiary of the Company ("Bakken Hunter") entered into a letter of intent to sell certain non-operated working interests in oil and natural gas properties located in Divide County, North Dakota for cash consideration of approximately $84.8 million, subject to customary purchase price adjustments. Additionally, on September 23, 2014 Triad Hunter, LLC, a wholly-owned subsidiary of the Company ("Triad Hunter") signed two agreements to sell certain non-core working interests in oil and gas properties located primarily in Calhoun and Roane Counties, West Virginia for cash consideration of $1.2 million, subject to customary purchase price adjustments. The sale of interests in the North Dakota oil and natural gas properties closed in October 2014. The sale of interests in the West Virginia oil and natural gas properties closed in November 2014. The Company has classified the associated assets and liabilities contemplated in these agreements as assets and liabilities held for sale in the consolidated balance sheet as of September 30, 2014.

Discontinued Operations

In September 2013, the Company adopted a plan to divest all of its interests in (i) MHP, whose oil and natural gas operations are located primarily in the Southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc. ("WHI Canada"), which was a wholly-owned subsidiary of the Company.

9

Planned Divestiture of Magnum Hunter Production

In connection with the Company’s adoption of a plan to divest of its interest in MHP in September 2013, the Company determined that the planned divestiture met the assets held for sale criteria and the criteria for classification as a discontinued operation. The Company classified the associated assets and liabilities of MHP as assets and liabilities held for sale in the consolidated balance sheet as of September 30, 2013 and reflected the results of MHP’s operations as discontinued operations in the consolidated statements of operations for the three and nine months ended September 2013 and 2012. The Company determined at each interim and annual period subsequent to September 30, 2013, and until September 30, 2014, that the planned divestiture continued to meet the criteria for classification as a discontinued operation based upon its ongoing marketing activities. Consequently, the Company continued to report the results of operations for MHP, including the results of operations of MHP for comparable periods presented from a preceding year, as a component of discontinued operations in the Company's consolidated financial statements for each interim and annual period from September 30, 2013 through June 30, 2014, and reported the assets and liabilities of MHP as assets and liabilities held for sale on the corresponding consolidated balance sheets.

During the year ended December 31, 2013, the Company recorded an impairment expense of $18.5 million, net of tax, to record MHP at the estimated selling price less costs to sell. Based upon additional information on estimated selling prices obtained through active marketing of the assets, the Company recorded an additional impairment expense during the quarter ended March 31, 2014 of $18.6 million, net of tax, to reflect the net assets at their estimated selling prices, less costs to sell. The Company did not record any impairment for MHP for the three month period ended June 30, 2014.

Effective September 2014, the Company withdrew its plan to divest MHP to further evaluate the oil and natural gas exploration and development upside opportunities underlying the acreage the Company has access to through MHP's leasehold and mineral interest rights. As a result of this decision the Company ceased all marketing activities for MHP, and consequently MHP no longer met the criteria for classification as a discontinued operation as of September 30, 2014.

The Company has reclassified the results of MHP’s operations from discontinued operations to continuing operations for all periods presented in these interim consolidated financial statements, and MHP’s assets and liabilities have been reclassified out of assets and liabilities held for sale and included with the Company’s other assets held and used as of September 30, 2014.

As of September 30, 2014, the Company has measured the carrying value of MHP’s individual long-lived assets previously classified as held for sale at the lesser of (i) their carrying amount before each asset was classified as held for sale, adjusted for any depreciation or amortization expense that would have been recognized had it been continuously classified as held and used, and (ii) their fair value at the date of the subsequent decision not to sell. As a result of this assessment, the Company recorded additional impairments of $1.9 million to the carrying amount of MHP’s unproved oil and natural properties and $17.0 million to the carrying amount of MHP’s proved oil and natural gas properties, which were recorded in exploration expense and impairment of proved oil and gas properties, respectively. In addition, the Company recorded depreciation expense of $1.7 million related to long-lived assets, whose fair value exceeded book value, adjusted for depreciation expense, as of September 30, 2014. In total, the Company recorded approximately $67.6 million of impairment related to MHP from September 30, 2013 through September 30, 2014.

Williston Hunter Canada Asset Sale

On April 10, 2014, WHI Canada closed on the sale of certain oil and natural gas properties and assets located in Alberta, Canada for cash consideration of CAD $9.5 million in cash (approximately U.S. $8.7 million at the exchange rate as of the close of business on April 10, 2014). The effective date of the sale was January 1, 2014. The Company recognized a gain of $6.1 million which is recorded in gain (loss) on disposal of discontinued operations.

Sale of Williston Hunter Canada

On May 12, 2014, the Company closed on the sale of 100% of its ownership interest in the Company's Canadian subsidiary, WHI Canada, whose assets consisted primarily of oil and natural gas properties located in the Tableland Field in Saskatchewan, Canada, for a purchase price of CAD $75.0 million (approximately U.S. $68.8 million at the exchange rate as of the close of business on May 12, 2014), prior to customary purchase price adjustments, with an effective date of March 1, 2014, of which CAD $18.4 million was placed in escrow pending final approval from the Canadian Revenue Authority. The Company received the cash held in escrow in July 2014. The Company recognized a loss of $12.8 million which is recorded in gain (loss) on disposal of discontinued operations. The loss on disposal of WHI Canada for the nine months ended September 30, 2014 includes $20.7 million in foreign currency translation adjustment which was reclassified out of accumulated other comprehensive income upon closing on the sale of our foreign operation.

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The following shows the Company's assets and liabilities held for sale at September 30, 2014 and December 31, 2013:

	September 30, 2014		December 31, 2013
	(in thousands)
Accounts receivable	$	—	$	4,362
Other current assets	—		1,004
Oil and natural gas properties, net	86,362		150,770
Gas transportation, gathering, and processing equipment and other, net	—		11,721
Other long-term assets	—		196
Total assets held for sale	$	86,362	$	168,053
Accounts payable	$	—	$	7,292
Accrued liabilities and other liabilities	—		5,573
Asset retirement obligations	1,619		8,678
Other long-term liabilities	—		5,845
Total liabilities held for sale	$	1,619	$	27,388

Sale of Eagle Ford Hunter

On April 24, 2013, the Company closed on the sale of all of its ownership interest in its wholly-owned subsidiary, Eagle Ford Hunter, Inc. ("Eagle Ford Hunter") to an affiliate of Penn Virginia Corporation for a total purchase price of approximately $422.1 million paid to the Company in the form of $379.8 million in cash (after estimated customary initial purchase price adjustments) and 10.0 million shares of common stock of Penn Virginia valued at approximately $42.3 million (based on the closing market price of the stock of $4.23 as of April 24, 2013). The effective date of the sale was January 1, 2013. At the date of closing, the Company initially recognized a preliminary gain on the sale of $172.5 million, net of tax, pending final working capital adjustments, which is recorded in gain (loss) on disposal of discontinued operations in the consolidated statements of operations.

In the months that followed closing, the Company and Penn Virginia were unable to agree upon the final settlement of the working capital adjustments as called for in the purchase and sale agreement and the disagreement was subsequently submitted to arbitration. The determination by the arbitrator was received by the Company on July 25, 2014 and resulted in a downward adjustment of the cash portion of the purchase price of $33.7 million plus accrued interest of $1.3 million. This liability was settled in cash on July 31, 2014. The Company had previously reserved and recognized substantially all of this obligation in its financial statements as of December 31, 2013. For the three and nine months ended September 30, 2013, the Company recorded a downward adjustment to the gain on sale of Eagle Ford Hunter of $13.9 million. For the three and nine months ended September 30, 2014, the Company recorded a downward adjustment to the gain on sale of Eagle Ford Hunter of $0.3 million and $7.3 million, respectively.

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The Company included the results of operations of WHI Canada through May 12, 2014 and Eagle Ford Hunter through April 24, 2013 in discontinued operations. The following presents our discontinued operations.

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2014			2013			2014			2013
	(in thousands)
Revenues	$	—		$	7,943		$	8,533		$	62,429
Expenses	—			(93,755		)	(3,976		)	(128,464		)
Other income	—			59			4			81
Income tax benefit	—			10,180			—			3,501
Income (loss) from discontinued operations, net of tax	—			(75,573		)	4,561			(62,453		)
Gain (loss) on disposal of discontinued operations, net of taxes	(258		)	(69,521		)	(13,983		)	102,931
Income (loss) from discontinued operations, net of taxes	$	(258	)	$	(145,094	)	$	(9,422	)	$	40,478

Other Divestitures

Sale of Certain Other North Dakota Assets

On September 30, 2014, Bakken Hunter closed on the sale of certain non-operated working interests in oil and natural gas properties located in Divide County, North Dakota for cash consideration of $23.5 million, subject to customary purchase price adjustments. The effective date of the sale was April 1, 2014. The Company recognized a gain on the sale of $8.2 million.

Sale of Certain Other Eagle Ford Shale Assets

On January 28, 2014, the Company, through its wholly-owned subsidiary Shale Hunter LLC ("Shale Hunter") and certain other affiliates, closed on the sale of certain of their oil and natural gas properties and related assets located in the Eagle Ford Shale in South Texas to New Standard Energy Texas LLC ("NSE Texas"), a subsidiary of New Standard Energy Limited ("NSE"), an Australian Securities Exchange-listed Australian company.

The assets sold consisted primarily of interests in leasehold acreage located in Atascosa County, Texas and working interests in five horizontal wells, of which four were operated by the Company. The effective date of the sale was December 1, 2013. As consideration for the assets sold, the Company received aggregate purchase price consideration of $15.5 million in cash, after customary purchase price adjustments, and 65,650,000 ordinary shares of NSE with a fair value of approximately $9.4 million at January 28, 2014 (based on the closing market price of $0.14 per share on January 28, 2014). These investment holdings represented approximately 17% of the total shares outstanding of NSE as of the closing date, and have been designated as available-for-sale securities, which are recorded at fair value of approximately $5.7 million and included in investments in the consolidated balance sheet as of September 30, 2014. The Company recognized a loss on the sale of the Shale Hunter assets of $4.5 million during the first quarter of 2014.

In connection with the closing of the sale, Shale Hunter and NSE Texas entered into a transition services agreement which provides that, during a specified transition period ending on July 28, 2015 unless otherwise extended or modified, Shale Hunter will provide NSE Texas with certain transitional services relating to the assets sold for which it is receiving a monthly fee.

Upon, and as a result of, the closing of the sale on January 28, 2014, the borrowing base under the Company’s asset-based, senior secured revolving credit facility was automatically reduced by $10.0 million as discussed in "Note 10 - Debt".

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NOTE 3 - OIL & NATURAL GAS SALES

During the three and nine months ended September 30, 2014 and 2013, the Company recognized sales from oil, natural gas, and natural gas liquids ("NGL") as follows:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2014		2013		2014		2013
	(in thousands)
Oil	$	34,495	$	40,471	$	111,354	$	103,545
Natural gas	18,247		12,417		74,031		41,145
NGL	9,768		6,173		36,862		12,082
Total oil and natural gas sales	$	62,510	$	59,061	$	222,247	$	156,772

NOTE 4 - PROPERTY, PLANT, & EQUIPMENT

Asset Acquisitions

On June 18, 2014, the Company entered into an Asset Purchase Agreement ("Ormet Asset Purchase Agreement") with Ormet Corporation for the purchase of certain mineral interests in approximately 1,700 net acres, consisting of 1,375 net acres in Monroe County, Ohio and 325 net acres in Wetzel County, West Virginia. Prior to the execution of the Ormet Asset Purchase Agreement, the Company held leasehold interests in a portion of the subject acreage, which only included leasehold rights to the Marcellus zone, and carried a 12.5% royalty on production to Ormet Corporation. On July 24, 2014, the Company closed on the purchase of the sub-surface mineral interests, including any royalty interests, in the underlying acreage, giving the Company an approximate 100% net revenue interest in and rights to oil, natural gas, and other minerals located in or under and that may be produced from the property, at any depth. The total purchase price for this transaction was approximately $22.7 million cash.

Oil and Natural Gas Properties

The following sets forth the net capitalized costs under the successful efforts method for oil and natural gas properties as of:

	September 30, 2014			December 31, 2013
	(in thousands)
Mineral interests in properties:
Unproved mineral rights and leasehold costs	$	510,296		$	469,337
Proved mineral rights and leasehold costs	282,150			336,357
Wells and related equipment and facilities	735,947			536,023
Advances to operators for wells in progress	2,508			13,571
Total costs	1,530,901			1,355,288
Less accumulated depletion, depreciation, and amortization	(208,495		)	(130,629		)
Net capitalized costs	$	1,322,406		$	1,224,659

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis bi-annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. Impairments of proved property of $22.9 million and $39.8 million were recorded during the three and nine months ended September 30, 2014 and $23.5 million and $39.5 million for the three and nine months ended September 30, 2013, respectively. For the three and nine months ended September 30, 2014, impairment of proved oil and gas properties included write-downs to fair value of MHP's proved oil and natural gas property of $17.1 million and $33.8 million, respectively. The Company recognized write-downs to fair value of MHP's proved oil and natural gas property of $16.4 million for the three and nine months ended September 30, 2013.

Depletion, depreciation, and amortization expense for proved oil and natural gas properties was $28.0 million and $81.9 million for the three and nine months ended September 30, 2014 and $23.6 million and $58.0 million for the three and nine months ended September 30, 2013, respectively.

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Exploration

Exploration expense consists primarily of abandonment charges and impairment expense for capitalized leasehold costs associated with unproved properties for which the Company has no further exploration or development plans, exploratory dry holes, and geological and geophysical costs.

During the three and nine months ended September 30, 2014 and 2013, the Company recognized exploration expense as follows:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2014		2013		2014		2013
	(in thousands)
Leasehold impairments	$	26,922	$	41,624	$	51,305	$	74,249
Geological and geophysical	362		354		1,089		1,008
Total exploration expense	$	27,284	$	41,978	$	52,394	$	75,257

Leasehold impairment expense recorded by the Company during the three and nine months ended September 30, 2014 consisted of $17.8 million and $37.8 million, respectively, in the U.S. upstream segment related to leases in the Williston Basin and $13.5 million during the nine months ended September 30, 2014 in the U.S. upstream segment related to leases in the Appalachian Basin. Leasehold impairment expense of $38.8 million and $71.5 million during the three and nine months ended September 30, 2013 primarily related to leases in the Williston Basin. Impairments of leases in the Williston and Appalachian Basins for all periods presented related to leases that expired undrilled during the period or are expected to expire and that the Company does not plan to develop or extend.

The Company recognized $1.9 million and $3.8 million in leasehold impairment expense related to fair value write-downs of MHP for the three and nine months ended September 30, 2014. For the same periods in 2013, leasehold impairment expense included $1.9 million in write-downs to fair value related to MHP.

Capitalized Costs Greater Than a Year

As of September 30, 2014, the Company had suspended exploratory well costs capitalized for periods greater than one year related to the Farley pad in Washington County, Ohio and the Farley #1305 H well. The Farley pad was constructed to drill multiple horizontal wells into a previously untested zone in the Utica formation. The Company spud the Farley #1305 H in April of 2013, and experienced well pressure instability during the fracture stimulation stage of completion. Further fracture stimulation and evaluation of this well will depend on the outcome of the drilling and completion of the Farley #1306 H and #1304 H wells, which were drilled in 2014 and are expected to be fracture stimulated and tested in 2015 upon completion of a new natural gas pipeline. Aggregate cost incurred through September 30, 2014 for the Farley pad and the Farley #1305 H well were $1.1 million and $13.8 million, respectively.

Gas Transportation, Gathering, and Processing Equipment and Other

The historical cost of gas transportation, gathering, and processing equipment and other property, presented on a gross basis with accumulated depreciation, as of September 30, 2014 and December 31, 2013 is summarized as follows:

	September 30, 2014			December 31, 2013
	(in thousands)
Gas transportation, gathering and processing equipment and other	$	516,258		$	315,642
Less accumulated depreciation	(47,350		)	(26,222		)
Net capitalized costs	$	468,908		$	289,420

Depreciation expense for gas transportation, gathering, and processing equipment and other property was $6.5 million and $16.1 million for the three and nine months ended September 30, 2014, respectively, and $4.3 million and $11.1 million for the three and nine months ended September 30, 2013, respectively. For the three and nine months ended September 30, 2014, depreciation expense included $1.7 million in depreciation recognized to adjust certain assets of MHP to their adjusted carrying value as if they

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had been held and used since their initial classification as assets held for sale through the date the Company withdrew their plan to divest of MHP.

The Company sells and leases gas treating and processing equipment, classified as gas transportation, gathering, and processing equipment and other property and included in the table above, much of which is leased to third party operators for treating gas at the wellhead.  The leases generally have a term of three years or less.  The equipment under leases in place as of September 30, 2014 had a net carrying value of $12.8 million, and the terms of such leases provide for future lease payments to the Company extending up to August 2016.  As of September 30, 2014, primarily all the leases to third parties were non-cancelable, with future minimum aggregate base rentals payable to the Company of $2.9 million over the twelve months ending September 30, 2015 and $0.5 million, in the aggregate, thereafter.

NOTE 5 - INTANGIBLE ASSETS

Intangible assets consist primarily of gas gathering and processing contracts and customer relationships. The following table summarizes the Company's net intangible assets as of September 30, 2014 and December 31, 2013:

	September 30,			December 31,
	2014			2013
	(in thousands)
Customer relationships	$	5,434		$	5,434
Trademark	859			859
Existing contracts	4,199			4,199
Total intangible assets	10,492			10,492
Less: accumulated amortization	(5,467		)	(3,962		)
Intangible assets, net of accumulated amortization	$	5,025		$	6,530

Amortization expense for intangible assets was $502,000 and $1.5 million for the three and nine months ended September 30, 2014 and $569,000 and $1.9 million for the three and nine months ended September 30, 2013, respectively.

The Company performed its annual impairment test of goodwill as of April 1, 2014. As a result of the Company's analysis no impairment of goodwill was indicated.

NOTE 6 - INVENTORY

The Company’s materials and supplies inventory is primarily comprised of frac sand used in the completion process of hydraulic fracturing. As of September 30, 2014 and December 31, 2013, the frac sand inventory is anticipated to be used in its entirety within the coming year, and is classified in current assets along with other inventory.

The following table shows the composition of the Company's inventory as of:

	September 30, 2014		December 31, 2013
	(in thousands)
Materials and supplies	$	2,228	$	6,790
Commodities	811		368
Inventory	$	3,039	$	7,158

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NOTE 7 - ASSET RETIREMENT OBLIGATIONS

The following table summarizes the Company’s asset retirement obligation ("ARO") activities during the nine-month period ended September 30, 2014 and for the year ended December 31, 2013:

	September 30, 2014			December 31, 2013
	(in thousands)
Asset retirement obligation at beginning of period	$	16,216		$	30,680
Assumed in acquisitions	—			17
Liabilities incurred	218			253
Liabilities settled	(26		)	(98		)
Liabilities sold	(596		)	(7,614		)
Accretion expense	1,731			2,264
Revisions in estimated liabilities (1)	2,625			1,935
Reclassified as liabilities associated with assets held for sale	(1,619		)	(11,148		)
Reclassified from liabilities associated with assets held for sale	8,109			—
Effect of foreign currency translation	—			(73		)
Asset retirement obligation at end of period	26,658			16,216
Less: current portion (included in other liabilities)	(1,482		)	(53		)
Asset retirement obligation at end of period	$	25,176		$	16,163

________________________________

 (1) Revisions in estimated liabilities during 2014 relate to a change in assumptions used with respect to certain wells in the Appalachian Basin in Ohio and West Virginia. Approximately $1.5 million of the revisions in estimated liabilities during 2013 is related to a change in assumptions used with respect to certain wells in the Williston Basin in North Dakota.

NOTE 8 - FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

Transfers between Levels 1 and 2 occur at the end of the reporting period in which it is determined that the observability of significant inputs has increased or decreased. There were no transfers between levels of the fair value hierarchy during 2014 and 2013. In January 2014, the Company acquired common shares of NSE in partial consideration of an asset sale. The significant inputs used in valuing the NSE common shares, which have a quoted market price in an active market, were designated as Level 1 as of September 30, 2014.

The Company used the following fair value measurements for certain of the Company's assets and liabilities at September 30, 2014 and December 31, 2013:

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Level 1 Classification:

Available for Sale Securities

At September 30, 2014 and December 31, 2013, the Company held common and preferred stock of publicly traded companies with quoted prices in an active market.  Accordingly, the fair market value measurements of these securities have been classified as Level 1.

Level 2 Classification:

Commodity Derivative Instruments

The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting.  The estimated fair value amounts of the Company’s commodity 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 commodity derivative instruments are valued using public indices, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange. Although the Company is exposed to credit risk to the extent of nonperformance by the counterparties to these derivative contracts, 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

At September 30, 2014 and December 31, 2013, the Company had a preferred stock embedded derivative liability resulting from its Eureka Hunter Holdings Series A Preferred Units, which contain certain conversion features, redemption options, and other features.

The fair value of the bifurcated conversion feature was valued using the "with and without" analysis in a simulation model based upon management's estimate of the expected life of the conversion feature. The key assumptions used in the model to determine fair value at September 30, 2014 were as follows:

	September 30, 2014
Volatility	13.7		%
Credit spread	24		%
Expected term	1-2 years
Total enterprise value (in millions)	$	929.7

The selection of assumptions for expected term and total enterprise value were made based on a weighting of possible outcomes. The term of the conversion feature, which was linked to the terms of the Eureka Hunter Holdings Amended and Restated Limited Liability Company Agreement (the "Eureka Hunter Holdings LLC Agreement"), could range from zero to 6 years. During the three-month period ended September 30, 2014, MSIP II Buffalo Holdings LLC, an affiliate of Morgan Stanley Infrastructure, Inc ("MSI"), entered into an agreement to purchase all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units and Class A Common Units held by Ridgeline Midstream Holdings, LLC ("Ridgeline"), an affiliate of ArcLight Capital Partners, LLC ("ArcLight"), which constituted all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units. In making the Company's determination of the total enterprise value for Eureka Hunter Holdings of $929.7 million, the Company considered the purchase price associated with MSI's purchase of the Eureka Hunter Holdings Series A Preferred Units, and its implied value to the enterprise as a whole. The issued and outstanding Eureka Hunter Holdings Series A Preferred Units were subsequently converted to a new class of common equity of Eureka Hunter Holdings. See "Note 13 - Redeemable Preferred Stock" and "Note 20 - Subsequent Events".

The fair value calculation is sensitive to movements in volatility, estimated remaining term, and the total enterprise value of Eureka Hunter Holdings. A decrease in the estimated term of the conversion feature results in a higher fair value of the conversion feature. During the three-month period ended June 30, 2014, the Company changed the estimated term to 1-2 years due to changes in the Company's expectation of when the conversion feature with respect to the Eureka Hunter Holdings Series A Preferred Units would be exercised. As the implied volatility of the instruments increases so too does the fair value of the derivative liability arising from the conversion and redemption features. Similarly, as the total enterprise value of Eureka Hunter Holdings increases, the fair value

17

of the derivative liability increases. Decreases in volatility and total enterprise value would result in a reduction to the fair value of the derivative liability associated with these instruments.

Convertible Security Embedded Derivative

The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with the convertible note it received in February 2012 as partial consideration upon the sale of Hunter Disposal, LLC ("Hunter Disposal") to GreenHunter Resources, Inc. ("GreenHunter"), a related party. The 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, 2014
Life	2.4
Risk-free interest rate	1.03		%
Estimated volatility	40		%
Dividend	—
GreenHunter stock price at end of period	$	1.52

The sensitivity of the estimate of volatility used in determining the fair value of the convertible security embedded derivative would not have a significant impact to the Company's financial statements based on the value of the assets as compared to the financial statements as a whole.

The following tables present the fair value hierarchy levels of the Company's financial assets and liabilities which are measured and carried at fair value on a recurring basis:

	Fair Value Measurements on a Recurring Basis
	September 30, 2014
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	8,076	$	—	$	—
Commodity derivative assets	—		2,127		—
Convertible security derivative assets	—		—		83
Total assets at fair value	$	8,076	$	2,127	$	83
Liabilities
Commodity derivative liabilities	$	—	$	114	$	—
Convertible preferred stock derivative liabilities	—		—		173,205
Total liabilities at fair value	$	—	$	114	$	173,205

	Fair Value Measurements on a Recurring Basis
	December 31, 2013
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	1,819	$	—	$	—
Commodity derivative assets	—		554		—
Convertible security derivative assets	—		—		79
Total assets at fair value	$	1,819	$	554	$	79
Liabilities
Commodity derivative liabilities	$	—	$	2,279	$	—
Convertible preferred stock derivative liabilities	—		—		75,934
Total liabilities at fair value	$	—	$	2,279	$	75,934

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The following table presents a reconciliation of the financial derivative asset and liability measured at fair value using significant unobservable inputs (Level 3 inputs) for the nine-month period ended September 30, 2014:

	Preferred Stock Embedded Derivative Liability			Convertible Security Embedded Derivative Asset
	(in thousands)
Fair value as of December 31, 2013	$	(75,934	)	$	79
Issuance of redeemable preferred stock	(5,479		)	—
Increase in fair value recognized in gain (loss) on derivative contracts, net	(91,792		)	4
Fair value as of September 30, 2014	$	(173,205	)	$	83

As of September 30, 2014, the valuation of the conversion feature embedded in the Eureka Hunter Holdings Series A Preferred Units increased the fair value of the embedded derivative liability by approximately $91.8 million as a result of changes in the total enterprise value of Eureka Hunter Holdings and the Company's estimate of the expected remaining term of the conversion feature. Management's estimate of the expected remaining term of the conversion option as of September 30, 2014 shortened the time horizon previously estimated by management, resulting in higher fair value of the conversion feature. Management's estimates were based upon several factors, including an estimate of the likelihood of each of the possible settlement options, which included redemption through a call or put option, or a liquidity event that triggers conversion to Class A Common Units of Eureka Hunter Holdings. See "Note 20 - Subsequent Events".

Other Fair Value Measurements

The following table presents the carrying amounts and fair values categorized by fair value hierarchy level of the Company's financial instruments not carried at fair value: 

		September 30, 2014				December 31, 2013
	Fair Value Hierarchy	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
		(in thousands)
Senior Notes	Level 2	$	597,313	$	639,000	$	597,230	$	651,300
MHR Senior Revolving Credit Facility	Level 3	$	256,000	$	256,000	$	218,000	$	218,000
Eureka Hunter Pipeline second lien term loan	Level 3	$	—	$	—	$	50,000	$	58,921
Eureka Hunter Pipeline Credit Agreement	Level 3	$	80,000	$	80,000	$	—	$	—
Equipment Notes Payable	Level 3	$	25,149	$	25,170	$	18,615	$	17,676

The fair value of the Company's Senior Notes is based on quoted market prices available for Magnum Hunter's Senior Notes.  The fair value hierarchy for the Company's Senior Notes is Level 2 (quoted prices for similar assets in active markets).

The carrying values of the Company's senior revolving credit facility (the "MHR Senior Revolving Credit Facility") and the outstanding borrowings under Eureka Hunter Pipeline's credit agreement (the "Eureka Hunter Pipeline Credit Agreement") approximate fair value as they are subject to short-term floating interest rates that approximate the rates available to the Company for those periods.  The fair value hierarchy for the MHR Senior Revolving Credit Facility and the Eureka Hunter Pipeline Credit Agreement is Level 3.

The fair value of Eureka Hunter Pipeline's second lien term loan as of December 31, 2013 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. Eureka Hunter Pipeline's second lien term loan was paid in full in March 2014.

The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company.

Fair Value on a Non-Recurring Basis

The Company follows the provisions of ASC Topic 820, Fair Value Measurement, for non-financial assets and liabilities measured at fair value on a non-recurring basis. As it relates to the Company, ASC Topic 820 applies to certain non-financial assets and

19

liabilities as may be acquired in a business combination and thereby measured at fair value, measurements of impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These ARO estimates are derived from historical costs as well as management's expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these measurements as Level 3.

As of September 30, 2014, the Company has measured the carrying value of certain long-lived assets of MHP previously classified as held for sale at their fair value in connection with their reclassification to assets held and used. See "Note 2 - Divestitures and Discontinued Operations". The fair value of these assets were derived using a variety of assumptions including market precedent transactions for similar assets, analyst pricing, and risk-adjusted discount rates for similar transactions. The Company has designated these valuations as Level 3.

NOTE 9 - FINANCIAL INSTRUMENTS AND DERIVATIVES

Investment Holdings

Below is a summary of changes in investments for the nine months ended September 30, 2014:

	Available for Sale Securities			Equity Method Investments (1)
	(in thousands)
Carrying value as of December 31, 2013	$	1,819		$	940
Securities received as consideration for assets sold	9,447			—
Equity in net loss recognized in other income (expense)	—			(504		)
Change in fair value recognized in other comprehensive loss	(3,190		)	—
Carrying value as of September 30, 2014	$	8,076		$	436

⁽¹⁾ Equity method investments includes $282,000 classified as long-term other assets.

The Company's investments have been presented in the consolidated balance sheet as of September 30, 2014 as follows:

	Available for Sale Securities		Equity Method Investments		Total
Investments - Current	$	8,076	$	154	$	8,230
Other Assets - Long-Term	—		282		282
Carrying value as of September 30, 2014	$	8,076	$	436	$	8,512

The cost for equity securities and their respective fair values as of September 30, 2014 and December 31, 2013 are as follows:

	September 30, 2014
	(in thousands)
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Securities available for sale, carried at fair value:
Equity securities	$	9,875	$	—	$	(4,030	)	$	5,845
Equity securities - related party (see "Note 15 - Related Party Transactions")	2,200		—		31			2,231
Total Securities available for sale	$	12,075	$	—	$	(3,999	)	$	8,076

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	December 31, 2013
	(in thousands)
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Securities available for sale, carried at fair value:
Equity securities	$	428	$	—	$	(281	)	$	147
Equity securities - related party (see "Note 15 - Related Party Transactions")	2,200		—		(528		)	1,672
Total Securities available for sale	$	2,628	$	—	$	(809	)	$	1,819

The methods of determining the fair values of Magnum Hunter's investments in equity securities are described in "Note 8 - Fair Value of Financial Instruments".

The Company's investment holdings are concentrated in three issuers whose business activities are related to the oil and natural gas or minerals mining industries. These investments are ancillary to the Company's overall operating strategy and such concentrations of risk related to investment holdings do not pose a substantial risk to the Company's operational performance. The Company evaluates factors that it believes could influence the fair value of the issuers' securities such as management, assets, earnings, cash generation, and capital needs.

The fair values of equity securities fluctuate based upon changes in market prices. Gross unrealized losses on investments are considered for other-than-temporary impairment when such losses have continued for more than a 12-month period. However, security specific circumstances may arise where an investment is considered impaired when gross unrealized losses have been observed for less than twelve months. As of September 30, 2014 and December 31, 2013, the Company did not hold any equity securities which were in a gross unrealized loss position for greater than a year, and no impairments were recognized for the periods then ended.

Commodity and Financial Derivative Instruments

The Company periodically enters into certain commodity derivative instruments such as futures contracts, swaps, collars, and basis swap contracts, to mitigate commodity price risk associated with a portion of the Company's future monthly natural gas and crude oil production and related cash flows. The Company has not designated any commodity derivative instruments as hedges.

In a commodities swap agreement, the Company trades the fluctuating market prices of oil or natural gas at specific delivery points over a specified period, for fixed prices. As a producer of oil and natural gas, the Company holds these commodity derivatives to protect the operating revenues and cash flows related to a portion of its future natural gas and crude oil sales from the risk of significant declines in commodity prices, which is intended to help reduce exposure to price risk and improve the likelihood of funding its capital budget.  If the price of a commodity rises above what the Company has agreed to receive in the swap agreement, the amount that it agrees to pay the counterparty would theoretically be offset by the increased amount it received for its production.

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As of September 30, 2014, the Company had the following commodity derivative instruments:

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Collars (1)	Oct 2014- Dec 2014	15,000	$4.27 - $5.23
Swaps	Oct 2014 - Dec 2014	41,000	$4.18
	Jan 2015 - Dec 2015	30,000	$4.12
Ceilings purchased (call)	Oct 2014 - Dec 2014	16,000	$5.91
Ceilings sold (call)	Oct 2014 - Dec 2014	16,000	$5.91
			Weighted Average
Crude Oil	Period	Bbl/day	Price per Bbl
Collars (1)	Oct 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collars (2)	Oct 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Oct 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00

________________________________    

(1) A collar is a sold call and a purchased put. Some collars are "costless" collars with the premiums netting to approximately zero.

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

As of September 30, 2014, Bank of America, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, Citibank, N.A., ABN AMRO, the Royal Bank of Canada, and Goldman Sachs are the only counterparties to the Company's commodity derivatives positions.  The Company is exposed to credit losses in the event of nonperformance by the counterparties; however, it does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.  At September 30, 2014, all counterparties, or their affiliates, were participants in the MHR Senior Revolving Credit Facility, and the collateral for the outstanding borrowings under the MHR Senior Revolving Credit Facility was used as collateral for its commodity derivatives with those counterparties. Certain counterparties to the Company's commodity derivatives positions are no longer participants in the Company's credit facilities following the execution of new new credit agreements on October 22, 2014. See "Note 20 - Subsequent Events".

At September 30, 2014, the Company had preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of its Eureka Hunter Holdings Series A Preferred Units and Class A Common Units held by Ridgeline, which constituted all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units. See "Note 8 - Fair Value of Financial Instruments" and "Note 13 - Redeemable Preferred Stock". During the three-month period ended September 30, 2014, MSI entered into an agreement to purchase all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units. Contemporaneous with the closing of MSI's purchase, the Company, MSI, and all minority interest members of Eureka Hunter Holdings entered into the Second Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings (the "New LLC Agreement"), which became effective on October 3, 2014. In connection with that amendment, all Eureka Hunter Holdings Series A Preferred Units were converted to a new class of equity. As a result, the preferred stock derivative liability effectively settled on the effective date of the New LLC Agreement through this conversion. See "Note 20 - Subsequent Events".

At September 30, 2014, the Company also had a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. See "Note 8 - Fair Value of Financial Instruments" and "Note 15 - Related Party Transactions".

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The following table summarizes the fair value of the Company's commodity and financial derivative contracts as of the dates indicated:

		Derivative Assets				Derivative Liabilities
Derivatives not designated as hedging instruments	Balance Sheet Classification	September 30, 2014		December 31, 2013		September 30, 2014			December 31, 2013
		(in thousands)
Commodity
	Derivative assets	$	1,871	$	529	$	—		$	—
	Derivative assets - long-term	255		25		—			—
	Derivative liabilities	—		—		(48		)	(1,903		)
	Derivative liabilities - long-term	—		—		(66		)	(376		)
Total commodity		$	2,126	$	554	$	(114	)	$	(2,279	)
Financial
	Derivative assets	$	83	$	79	$	—		$	—
	Derivative liabilities - long-term	—		—		(173,205		)	(75,934		)
Total financial		$	83	$	79	$	(173,205	)	$	(75,934	)
Total derivatives		$	2,209	$	633	$	(173,319	)	$	(78,213	)

Certain of the Company's derivative instruments are subject to enforceable master netting arrangements that provide for the net settlement of all derivative contracts between the Company and a counterparty in the event of default or upon the occurrence of certain termination events.  The tables below summarize the Company's commodity derivatives and the effect of master netting arrangements on the presentation in the Company's consolidated balance sheets as of:

	September 30, 2014
	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset on the Consolidated Balance Sheet		Net Amount
	(in thousands)
Current assets:  Fair value of derivative contracts	$	2,399		(528	)	$	1,871
Long-term assets:  Fair value of derivative contracts	377			(122	)	255
Current liabilities:  Fair value of derivative contracts	(576		)	528		(48		)
Long-term liabilities:  Fair value of derivative contracts	(188		)	122		(66		)
	$	2,012		—		$	2,012

	December 31, 2013
	Gross Amounts of Assets and Liabilities			Gross Amounts Offset on the Consolidated Balance Sheet		Net Amount
	(in thousands)
Current assets:  Fair value of derivative contracts	$	4,034		(3,505	)	$	529
Long-term assets:  Fair value of derivative contracts	516			(491	)	25
Current liabilities:  Fair value of derivative contracts	(5,408		)	3,505		(1,903		)
Long-term liabilities:  Fair value of derivative contracts	(867		)	491		(376		)
	$	(1,725	)	—		$	(1,725	)

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The following table summarizes the net gain (loss) on all derivative contracts included in gain (loss) on derivative contracts, net on the consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013:

	Three Months Ended September 30,						Nine Months Ended   September 30,
	2014			2013			2014			2013
	(in thousands)
Gain (loss) on settled transactions	$	477		$	(6,582	)	$	(4,074	)	$	(6,887	)
Loss on open contracts	(50,113		)	(22,971		)	(88,051		)	(23,757		)
Total loss	$	(49,636	)	$	(29,553	)	$	(92,125	)	$	(30,644	)

NOTE 10 - DEBT

Long-term debt at September 30, 2014 and December 31, 2013 consisted of the following: 

	September 30, 2014			December 31, 2013
	(in thousands)
Senior Notes payable due May 15, 2020, interest rate of 9.75%, net of unamortized net discount of $2.7 million at September 30, 2014 and December 31, 2013	$	597,313		$	597,230
Various equipment and real estate notes payable with maturity dates January 2015 - April 2021, interest rates of 4.25% - 7.94%(1)	25,149			18,615
Eureka Hunter Pipeline Credit Agreement due March 28, 2018, interest rate of 3.66%	80,000			—
Eureka Hunter Pipeline second lien term loan due August 16, 2018, interest rate of 12.5%	—			50,000
MHR Senior Revolving Credit Facility due April 13, 2016, interest rate of 3.06% at September 30, 2014 and 3.56% at December 31, 2013	256,000			218,000
	958,462			883,845
Less: current portion	(8,670		)	(3,967		)
Total long-term debt obligations, net of current portion	$	949,792		$	879,878

 _________________________________

(1) Balance as of December 31, 2013 includes notes classified as liabilities associated with assets held for sale of which $0.2 million is current and $3.8 million is long-term.

The following table presents the scheduled or expected approximate annual maturities of debt, gross of unamortized discount of $2.7 million: 

	(in thousands)
2014	$	2,565
2015	7,717
2016	264,727
2017	2,548
2018	80,559
Thereafter	603,032
Total	$	961,148

MHR Senior Revolving Credit Facility and Second Lien Term Loan

On December 13, 2013, the Company entered into a Third Amended and Restated Credit Agreement (the "Credit Agreement") by and among the Company, Bank of Montreal, as Administrative Agent, the lenders party thereto and the agents party thereto. The Credit Agreement amended and restated that certain Second Amended and Restated Credit Agreement, dated as of April 13, 2011, by and among such parties, as amended (the "Prior Credit Agreement").

On May 6, 2014, the Company and the other parties to the Credit Agreement entered into the First Amendment to Third Amended and Restated Credit Agreement (the "Amendment"). The Amendment increased the borrowing base from $232.5 million to $325.0 million in connection with the regular semi-annual redetermination of the Company's borrowing base derived from the Company's proved crude oil and natural gas reserves. The borrowing base may be increased or decreased in connection with such

24

redeterminations up to a maximum commitment level of $750.0 million. The Amendment provides that such increased borrowing base shall be reduced (i) by the lesser of $25.0 million or 50% of the net proceeds from issuances by the Company of common equity on or before July 1, 2014 (other than common equity issued pursuant to any stock incentive or stock option plan or any other compensatory arrangements); (ii) by certain specified reductions in connection with certain proposed asset dispositions; (iii) on July 1, 2014 by $25.0 million less any prior adjustment of the borrowing base due to an equity issuance as contemplated by clause (i); and (iv) by $0.25 for each $1.00 of any additional Senior Notes issued by the Company. The Amendment further provides that from May 6, 2014 through July 1, 2014 the Applicable Margin (as defined in the Credit Agreement) component of the interest charged on revolving borrowings under the Credit Agreement shall be 2.75% for ABR Loans (as defined in the Credit Agreement) and 3.75% for Eurodollar Loans (as defined in the Credit Agreement). From and after July 1, 2014 through the date of the Company’s delivery of a certificate for the quarter ended June 30, 2014, with respect to, among other things, the Company’s compliance with the covenants in the Credit Agreement (the "Compliance Certificate"), the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement will range from 1.50% to 2.25% for ABR Loans and from 2.50% to 3.25% for Eurodollar Loans. From and after the Company’s delivery of the Compliance Certificate, the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement will range from 1.00% to 1.75% for ABR Loans and from 2.00% to 2.75% for Eurodollar Loans.

In addition, the Amendment modified certain of the Credit Agreement’s financial covenants, including:

(i) permitting the Company to take into account the borrowing base increase as though it occurred on March 31, 2014 for purposes of maintaining a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

(ii) providing for a ratio of EBITDAX to Interest Expense of not less than (A) 2.00 to 1.0 for the fiscal quarter ended March 31, 2014, (B) 2.25 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 2.50 to 1.0 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter; and

(iii) beginning with the fiscal quarter ended June 30, 2014, providing for a ratio of total Debt to EBITDAX of not more than (A) 4.75 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, (B) 4.50 to 1.0 for the fiscal quarter ending December 31, 2014, and (C) 4.25 to 1.0 for the fiscal quarter ending March 31, 2015 and for each fiscal quarter ending thereafter.

The Amendment also (i) amends the definition of EBITDAX and provides that certain acquisitions and dispositions be given pro forma effect in the calculation of EBITDAX; (ii) increases the letter of credit commitment from $10.0 million to $50.0 million and provides that outstanding letter of credit exposure not be included in certain determinations of Debt; (iii) requires the total value of the Company’s oil and gas properties included in the reserve reports for the borrowing base determinations in which the lenders under the Credit Agreement have perfected liens be increased from 80% to 90%; and (iv) modifies certain covenants in the Credit Agreement with respect to permitted investments by the Company to increase flexibility.

The Company incurred direct financing costs associated with entering into the Amendment to the Credit Agreement in the amount of $3.1 million, which will be deferred and amortized over the remaining term of the Credit Agreement.

As of September 30, 2014, the borrowing base under this facility was $265.0 million, and $256.0 million of borrowings were outstanding ($218.0 million outstanding as of December 31, 2013). The borrowing base as of September 30, 2014 reflects reductions in the borrowing base of $25 million, $27.5 million, and $7.5 million related to the issuance of equity in May 2014, the sale of our 100% equity interest in WHI Canada which closed in May 2014, and the sale of certain assets in North Dakota which closed in September 2014, respectively. The borrowing base is subject to further automatic reductions upon the issuance of additional Senior Notes and in certain other circumstances.

On October 22, 2014, the Company entered into (i) a Fourth Amended and Restated Credit Agreement (the "New Credit Agreement"), by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders party thereto and agents party thereto, and (ii) a Second Lien Credit Agreement (the "Second Lien Term Loan Agreement"), by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto. The New Credit Agreement amended and restated the Credit Agreement. The proceeds from the New Credit Agreement and the Second Lien Term Loan Agreement were used, in part, to refinance the amounts outstanding under the Credit Agreement on the date of closing.

As a result of the refinancing of the Credit Agreement with the New Credit Agreement and the Second Lien Term Loan Agreement, the Company was not required to provide compliance certificates for covenants stipulated in the Credit Agreement as of and for the period ended September 30, 2014.  See "Note 20 - Subsequent Events" for additional information.

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Eureka Hunter Pipeline Credit Agreement

On March 28, 2014, Eureka Hunter Pipeline entered into the Eureka Hunter Pipeline Credit Agreement, by and among Eureka Hunter Pipeline, as borrower, ABN AMRO Capital USA, LLC, as a lender and as administrative agent, and the other lenders party thereto.

The credit agreement, which has a maturity date of March 28, 2018, provides for a revolving credit facility in an aggregate principal amount of up to $117.0 million (with the potential to increase the aggregate commitment under the credit agreement to an aggregate principal amount of up to $150.0 million, subject to the consent of the lender parties and the satisfaction of certain conditions), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline and its subsidiaries, which include TransTex Hunter, as well as by Eureka Hunter Pipeline’s pledge of the equity in its subsidiaries. The subsidiaries of Eureka Hunter Pipeline also guarantee Eureka Hunter Pipeline’s obligations under the credit agreement. The credit agreement is non-recourse to Magnum Hunter. The Company incurred deferred financing costs directly associated with entering into the Eureka Hunter Pipeline Credit Agreement in the amount of $1.2 million which will be amortized straight-line over the term of the revolving credit facility. The straight-line method of amortization results in substantially the same periodic amortization as the effective interest method.

The terms of the credit agreement provide that the borrowings thereunder may be used, among other specified purposes, (1) to refinance existing indebtedness of Eureka Hunter Pipeline outstanding on the credit agreement closing date, including the term loan of $50.0 million in principal amount owed under the Second Lien Term Loan Agreement, dated August 16, 2011, by and among Eureka Hunter Pipeline and Pennant Park Investment Corporation, as a lender, the other lenders party thereto and U.S. Bank National Association, as collateral agent, (2) to finance future expansion activities related to Eureka Hunter Pipeline’s gathering system in West Virginia and Ohio, (3) to finance acquisitions by Eureka Hunter Pipeline and its subsidiaries permitted under the terms of the credit agreement, (4) to refinance from time to time certain letters of credit of Eureka Hunter Pipeline and its subsidiaries, (5) to provide working capital for their operations, and (6) for their other general business purposes.

The Eureka Hunter Pipeline Credit Agreement provides for a commitment fee based on the unused portion of the commitment under the credit agreement of 0.50% per annum when the consolidated leverage ratio is greater than or equal to 3.0 to 1.0 and a commitment fee of 0.375% when the consolidated leverage ratio is less than 3.0 to 1.0.

In general terms, borrowings under the credit agreement will, at Eureka Hunter Pipeline’s election, bear interest:

• on base rate loans, at the per annum rate equal to the sum of (A) the base rate (defined as the highest of (i) the per annum rate of interest established by JPMorgan Chase Bank, N.A. as its prime rate for U.S. dollar loans, (ii) the Adjusted Eurodollar Rate (as defined in the credit agreement) for an interest period of one-month, plus 1.0%, or (iii) the federal funds rate, plus 0.50% per annum), and (B) a margin of 1.0% to 2.50% per annum; or

• on Eurodollar Loans, at the per annum rate equal to the sum of (A) the Eurodollar Rate (as defined in the credit agreement) adjusted for certain statutory reserve requirements for Eurocurrency liabilities, and (B) a margin of 2.0% to 3.50% per annum.

If an event of default occurs under the credit agreement, generally, the applicable lenders may increase the interest rate then in effect by an additional 2.0% per annum for the period that the default exists.

The credit agreement contains customary affirmative covenants and negative covenants that, among other things, restrict the ability of each of Eureka Hunter Pipeline and its subsidiaries to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) enter into hedging transactions; (4) enter into a merger or consolidation or sell, lease, transfer or otherwise dispose of all or substantially all of its assets or the stock of any of its subsidiaries; (5) issue equity; (6) dispose of any material assets or properties; (7) pay or declare dividends or make certain distributions; (8) invest in, extend credit to or make advances or loans to any person or entity; (9) engage in material transactions with any affiliate; (10) enter into any agreement that restricts or imposes any condition upon the ability of (a) any of Eureka Hunter Pipeline or its subsidiaries to create, incur or permit any lien upon any of its assets or properties, or (b) any such subsidiary to pay dividends or other distributions, to make or repay loans or advances, to guarantee indebtedness or to transfer any of its property or assets to Eureka Hunter Pipeline or its subsidiaries; (11) change the nature of its business; (12) amend its organizational documents or material agreements; (13) change its fiscal year; (14) enter into sale and leaseback transactions; (15) make acquisitions; (16) make certain capital expenditures; or (17) take any action that could result in regulation as a utility.

The credit agreement requires Eureka Hunter Pipeline to satisfy certain financial covenants, including maintaining:

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• a maximum leverage ratio (defined as the ratio of (i) consolidated funded debt to (ii) annualized consolidated EBITDA), as of the end of each fiscal quarter, not greater than (A) 4.75 to 1.00 for the fiscal quarters ending March 31, 2014 through September 30, 2014, and (B) 4.50 to 1.00 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter; and

• a minimum interest coverage ratio (defined as the ratio of (i) annualized consolidated EBITDA to (ii) annualized consolidated interest charges for such period), as of the end of each fiscal quarter, not less than (A) 2.75 to 1.00 for the fiscal quarters ending March 31, 2014 through September 30, 2014, and (B) 2.50 to 1.00 for the fiscal quarter ending December 31, 2014 and each fiscal quarter ending thereafter.

The obligations of Eureka Hunter Pipeline under the credit agreement may be accelerated upon the occurrence of an event of default. Events of default include customary events for these types of financings, including, among other things, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations or warranties, material defaults under or termination of certain material contracts, defaults relating to judgments, certain bankruptcy proceedings, a change in control and any material adverse change.

As of September 30, 2014 the maximum amount available under the credit agreement was $90.2 million, and the Company had $80.0 million in borrowings outstanding. The borrowing capacity is subject to certain upward or downward reductions during the term of the credit agreement.

As of September 30, 2014, Eureka Hunter Pipeline was in compliance with all of its covenants contained in the Eureka Hunter Pipeline Credit Agreement.

Eureka Hunter Pipeline Credit Facilities

Upon executing the new Eureka Hunter Pipeline Credit Agreement on March 28, 2014, Eureka Hunter Pipeline terminated its revolving credit agreement with SunTrust Bank and the term loan agreement with Pennant Park (the "Original Eureka Hunter Credit Facilities"). Eureka Hunter Pipeline used proceeds from the Eureka Hunter Pipeline Credit Agreement to pay in full all outstanding obligations related to the termination of the Original Eureka Hunter Credit Facilities, which included the principal outstanding amount of $50.0 million, a prepayment penalty of $2.2 million, and accrued, unpaid interest of $1.5 million.

Equipment Note Payable

On January 21, 2014, the Company's wholly owned subsidiary, Alpha Hunter Drilling, LLC, entered into a master loan and security agreement with CIT Finance LLC to borrow $5.6 million at an interest rate of 7.94% over a term of forty-eight months. The note is collateralized by field equipment, and the Company is a guarantor on the note.

Building Note Payable

Effective September 30, 2014, MHP refinanced its $3.8 million term loan with Traditional Bank, Inc. that was due to mature in early 2015.  The new loan is collateralized by an office building owned by MHP and carried an initial principal balance of $3.8 million at an interest rate of 4.875% with a maturity date of September 30, 2024.

Interest Expense

The following table sets forth interest expense for the three and nine month periods ended September 30, 2014 and 2013, respectively:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2014		2013		2014		2013
	(in thousands)
Interest expense incurred on debt, net of amounts capitalized	$	17,013	$	14,648	$	53,748	$	49,691
Amortization and write-off of deferred financing costs	1,082		1,111		8,725		3,661
Total interest expense	$	18,095	$	15,759	$	62,473	$	53,352

The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. The Company capitalized interest on its Eureka Hunter Gas Gathering

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System of $723,000 and $1.6 million during the three and nine months ended September 30, 2014, respectively, and $582,000 and $2.0 million during the three and nine months ended September 30, 2013, respectively.

For the nine-month period ended September 30, 2014, interest expense incurred on debt includes a $2.2 million prepayment penalty incurred by Eureka Hunter Pipeline as a result of its early termination of the Original Eureka Hunter Credit Facilities on March 28, 2014, which penalty represents an additional cost of borrowing for a period shorter than contractual maturity. In addition, amortization and write-off of deferred financing costs for the nine-month period ended September 30, 2014 includes the write-off of $2.7 million in unamortized deferred financing costs related to those terminated agreements, which costs were expensed at the time of early extinguishment and $1.7 million in unamortized deferred financing costs related to the Amendment of the MHR Senior Revolving Credit Facility.

NOTE 11 - SHARE-BASED COMPENSATION

Under the Company's Amended and Restated Stock Incentive Plan, the Company may grant unrestricted common stock, restricted common stock, common stock options, and stock appreciation rights to directors, officers, employees and other persons who contribute to the success of Magnum Hunter.  Currently, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 9,274,248 shares had been issued under the plan as of September 30, 2014, of which 1,398,898 shares remained unvested at September 30, 2014. Additionally, 13,294,506 options to purchase shares and stock appreciation rights were outstanding as of September 30, 2014, of which 4,115,833 remained unvested at September 30, 2014.

The Company recognized share-based compensation expense of $2.3 million and $5.7 million for the three and nine months ended September 30, 2014, respectively, and $3.1 million and $11.8 million for the three and nine months ended September 30, 2013, respectively.

A summary of common stock option activity for the nine months ended September 30, 2014 and 2013 is presented below:

	Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands of shares)				Weighted Average Exercise Price per Share
Outstanding at beginning of period	16,891		14,847		$	5.69	$	6.01
Granted	—		4,938		$	—	$	4.11
Exercised	(2,355	)	(685	)	$	4.09	$	2.95
Forfeited	(1,241	)	(742	)	$	6.28	$	6.00
Outstanding at end of period	13,295		18,358		$	5.91	$	5.61
Exercisable at end of period	9,179		10,512		$	6.22	$	5.86

A summary of the Company’s non-vested common stock options and stock appreciation rights for the nine months ended September 30, 2014 and 2013 is presented below:

	Nine Months Ended September 30,
	2014		2013
	(in thousands of shares)
Non-vested at beginning of period	6,908		6,163
Granted	—		4,938
Vested	(1,916	)	(2,867	)
Forfeited	(876	)	(389	)
Non-vested at end of period	4,116		7,845

Total unrecognized compensation cost related to the non-vested common stock options was $4.7 million and $12.9 million as of September 30, 2014 and 2013, respectively.  The unrecognized compensation cost at September 30, 2014 is expected to be recognized over a weighted-average period of 1.1 years. At September 30, 2014, the weighted average remaining contract life of outstanding options was 5.6 years.

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During the nine months ended September 30, 2014, the Company granted 1,486,373 restricted shares of common stock to officers, executives, and employees of the Company which vest over a 3-year period with 33% of the restricted shares vesting one year from the date of the grant. The Company also granted 123,798 restricted shares to the directors of the Company which vest 100% one year from the date of the grant. The shares had a fair value at the time of grant of $10.8 million based on the stock price on grant date and estimated forfeiture rate of 3.4%.

Total unrecognized compensation cost related to non-vested, restricted shares amounted to $7.1 million and $66,000 as of September 30, 2014 and 2013, respectively.  The unrecognized cost at September 30, 2014, is expected to be recognized over a weighted-average period of 2.1 years.

Eureka Hunter Holdings, LLC Management Incentive Compensation Plan

On May 12, 2014, the Board of Directors of Eureka Hunter Holdings approved the Eureka Hunter Holdings, LLC Management Incentive Compensation Plan ("Eureka Hunter Holdings Plan") to provide long-term incentive compensation to attract and retain officers and employees of Eureka Hunter Holdings and its affiliates and allow such individuals to participate in the economic success of Eureka Hunter Holdings and its affiliates.

The Eureka Hunter Holdings Plan consists of (i) 2,336,905 Class B Common Units representing membership interests in Eureka Hunter Holdings ("Class B Common Units"), and (ii) 2,336,905 Incentive Plan Units issuable pursuant to a management incentive compensation plan, which represent the right to receive a dollar value up to the baseline value of a corresponding Class B Common Unit ("Incentive Plan Units"). The Eureka Hunter Holdings Plan is administered by the Board of Directors of Eureka Hunter Holdings, and, as administrator of the Eureka Hunter Holdings Plan, the board will from time to time make awards under the Eureka Hunter Holdings Plan to selected officers and employees of Eureka Hunter Holdings or its affiliates ("Award Recipients").

The Class B Common Units are profits interest awards that carry the right to share in the appreciation in the value of the aggregate common equity in Eureka Hunter Holdings over and above a baseline value that is determined on the date of grant of the Class B Common Units. The Class B Common Units vest in five substantially equal annual installments on each of the first five anniversaries of the date of grant, subject to the Award Recipient's continued employment, and automatically vest in full upon the occurrence of a liquidity event (as defined in the Eureka Hunter Holdings Plan) (including if the Award Recipient's employment is terminated by Eureka Hunter Holdings or an affiliate without cause or due to the Award Recipient's death or disability, in each case, within six months prior to the occurrence of a liquidity event). Subject to the Award Recipient's continued employment, the Incentive Plan Units become fully vested upon the occurrence of a liquidity event (including if the Award Recipient's employment is terminated by Eureka Hunter Holdings or an affiliate without cause or due to the Award Recipient's death or disability, in each case, within six months prior to the occurrence of a liquidity event).

If an Award Recipient’s employment is terminated under any other circumstances, all unvested Class B Common Units and Incentive Plan Units will be forfeited immediately upon the Award Recipient’s termination of employment. In addition, vested Class B Common Units will be forfeited if an Award Recipient’s employment is terminated prior to the occurrence of a liquidity event by Eureka Hunter Holdings or an affiliate for cause or due to the Award Recipient’s resignation. If, following a termination of his or her employment by Eureka Hunter Holdings or an affiliate without cause or due to the Award Recipient’s death or disability, an Award Recipient retains vested Class B Common Units, Eureka Hunter Holdings will have the right, but not the obligation, to repurchase such vested Class B Common Units at fair market value.

Distributions, if any, with respect to the Class B Common Units issued pursuant to the Class B Common Unit Agreement will be made in accordance with, and subject to, the New LLC Agreement, provided, that, no distributions shall be made with respect to any vested or unvested Class B Common Units unless and until a liquidity event has occurred (other than tax distributions that may be made in accordance with the New LLC Agreement). Payment in respect of vested Class B Common Units and Incentive Plan Units will become due upon the occurrence of a liquidity event and are expected to be settled in cash upon the occurrence of a liquidity event, except in the case of a qualified public offering (as defined in the Eureka Hunter Holdings Plan), in which case settlement will occur partially in cash and partially in shares of the resulting public entity, with the cash portion not to exceed the amount necessary to cover minimum statutory tax withholdings.

Upon approval of the plan on May 12, 2014, the Board of Directors of Eureka Hunter Holdings granted 894,102 Class B Common Units and 894,102 Incentive Plan Units to key employees of Eureka Hunter Holdings and its subsidiaries. The Class B Common Units and Incentive Plan Units are accounted for in accordance with ASC 718, Compensation - Stock Compensation. In accordance with ASC 718, compensation cost is accrued when the performance condition (i.e. the liquidity event) is probable of being achieved. As of September 30, 2014, a liquidity event, as defined, was not probable, and therefore, no compensation cost has been recognized.

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NOTE 12 - SHAREHOLDERS' EQUITY

Common Stock

During the nine months ended September 30, 2014, the Company:

i) issued 70,575 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;

ii) issued 2,355,000 shares of the Company’s common stock upon exercise of fully vested stock options;

iii) issued 4,300,000 shares of the Company's common stock in March 2014 in a private placement at a price of $7.00 per share, with net proceeds to the Company of $28.9 million after deducting sales agent commissions and other issuance costs. The Company subsequently filed a Form S-1 Registration Statement with the SEC which was declared effective on July 23, 2014 to register the resale of these shares by the holders thereof to satisfy the Company's registration obligations under the private placement. A post-effective amendment filed to convert the Form S-1 Registration Statement to a Form S-3 Registration Statement was declared effective by the SEC on September 11, 2014;

iv) issued 21,428,580 shares of the Company's common stock in May 2014 in a private placement at a price of $7.00 per share, with net proceeds to the Company of $149.7 million after deducting issuance costs. The Company subsequently filed a Form S-1 Registration Statement with the SEC to register the resale of these shares by the holders thereof to satisfy the Company's registration obligations under the private placement. A post-effective amendment filed to convert the Form S-1 Registration Statement to a Form S-3 Registration Statement was declared effective by the SEC on August 22, 2014; and

v) issued 249,531 shares of the Company's common stock to fund safe-harbor and discretionary matching contributions to the Company's 401k plan in respect of salary deferrals made by participants in the plan during 2013.

Common Stock Warrants

The Company issued 2,142,858 warrants to purchase common stock with an exercise price of $8.50 per share, subject to certain anti-dilution adjustments, in conjunction with the May 2014 private placement sales of common stock. The warrants became exercisable beginning on May 29, 2014, and will expire on April 15, 2016. The warrants are subject to redemption at the option of the Company at $0.001 per warrant upon not less than thirty days' notice to the holders, only if the Company also redeems the warrants it previously issued pursuant to that certain Warrants Agreement, dated October 15, 2013, by and between the Company and American Stock Transfer & Trust Company, Inc. The warrants were issued in connection with the May 2014 sale of 21,428,580 common shares, and the proceeds for the sale of the common shares and the warrants have been reflected in the Company's capital accounts as increases to common stock and additional paid in capital.

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Preferred Dividends Incurred

A summary of the Company's preferred dividends for the three and nine months ended September 30, 2014 and 2013 is presented below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Dividend on Eureka Hunter Holdings Series A Preferred Units	$	4,338	$	3,771	$	12,619	$	10,441
Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	2,306		1,826		6,583		4,990
Dividend on Series C Preferred Stock	2,562		2,562		7,686		7,686
Dividend on Series D Preferred Stock	4,424		4,424		13,273		13,231
Dividend on Series E Preferred Stock	1,862		1,834		5,557		5,686
Total dividends on Preferred Stock	$	15,492	$	14,417	$	45,718	$	42,034

Net Income or Loss per Share Data

Basic income or loss per common share is computed by dividing the income or loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted income or loss per common share considers the impact to net income and common shares for the potential dilution from stock options and stock appreciation rights, common stock purchase warrants and any outstanding convertible securities.

The Company has issued potentially dilutive instruments in the form of restricted common stock of Magnum Hunter granted and not yet issued, common stock warrants, common stock options granted to the Company's employees and directors, and the Company's Series E Preferred Stock. The Company did not include any of these instruments in its calculation of diluted loss per share during the periods presented, because to include them would be anti-dilutive due to the Company's loss from continuing operations during those periods.

The following table summarizes the types of potentially dilutive securities outstanding as of September 30, 2014 and 2013:

	September 30,
	2014	2013
	(in thousands of shares)
Series E Preferred Stock	10,946	11,185
Warrants	19,214	30,407
Unvested restricted shares	1,445	—
Common stock options and stock appreciation rights	13,295	18,358
Total	44,900	59,950

NOTE 13 - REDEEMABLE PREFERRED STOCK

Eureka Hunter Holdings 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, an affiliate of ArcLight. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200.0 million of Eureka Hunter Holdings Series A Preferred Units, representing membership interests of Eureka Hunter Holdings, of which $200.0 million had been purchased as of September 30, 2014.

During the nine months ended September 30, 2014, Eureka Hunter Holdings issued 610,000 Eureka Hunter Holdings Series A Preferred Units to Ridgeline for net proceeds of $12.0 million, net of transaction costs. The Eureka Hunter Holdings Series A

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Preferred Units outstanding at September 30, 2014 represented 40.9% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.

During the nine months ended September 30, 2014, Eureka Hunter Holdings issued 97,492 Eureka Hunter Holdings Series A Preferred Units as payment of $1.9 million in distributions paid-in-kind to holders of the Series A Preferred Units. The fair value of the embedded derivative feature of the outstanding Eureka Hunter Holdings Series A Preferred Units was determined to be $173.2 million at September 30, 2014.

Dividend expense included accretion of the Eureka Hunter Holdings Series A Preferred Units of $2.3 million and $6.6 million for the three and nine months ended September 30, 2014, and $1.8 million and $5.0 million for the three and nine months ended September 30, 2013, respectively.

On September 16, 2014, the Company entered into an agreement (the "Transaction Agreement") with MSI relating to a separate purchase agreement between MSI and Ridgeline providing for the purchase by MSI of all convertible preferred and common equity interests in Eureka Hunter Holdings owned by Ridgeline.

The Transaction Agreement provided for a New LLC Agreement of Eureka Hunter Holdings to be entered into by Magnum Hunter, MSI and the minority interest members of Eureka Hunter Holdings contingent upon and contemporaneously with the closing of MSI's purchase of Ridgeline's equity interests in Eureka Hunter Holdings, which occurred on October 3, 2014. In connection with the first closing on October 3, 2014, all of the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units of Eureka Hunter Holdings acquired by MSI from Ridgeline were converted into a new class of equity interests of Eureka Hunter Holdings, and all equity interests owned by MSI will have a liquidation preference under certain circumstances. The conversion of the Eureka Hunter Holdings Series A Preferred Units to a new class of equity resulted in an extinguishment of the Eureka Hunter Holdings Series A Preferred Units and the issuance of a new class of equity initially recorded at fair value. See "Note 20 - Subsequent Events".

NOTE 14 - TAXES

The Company's income tax benefit from continuing operations for the three and nine months ended September 30, 2014 and 2013 was:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2014		2013		2014		2013
	(in thousands)
Deferred	$	—	$	582	$	—	$	47,227
Income tax benefit	$	—	$	582	$	—	$	47,227

The Company recognizes deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. The Company maintains a full valuation allowance on deferred tax assets where the realization of those deferred tax assets is not more likely than not. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits is more likely than not to be utilized. The Company files income tax returns in the United States, various states and Canada. As of September 30, 2014, no adjustments have been proposed by any tax jurisdiction that would have a significant impact on the Company's liquidity, future results of operations or financial position.

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NOTE 15 - RELATED PARTY TRANSACTIONS

The following table sets forth the related party balances as of September 30, 2014 and December 31, 2013:

	September 30, 2014		December 31, 2013
	(in thousands)
Green Hunter (1)
Accounts payable - net	$	355	$	23
Derivative assets (2)	$	83	$	79
Investments (2)	$	2,385	$	2,262
Notes receivable (2)	$	1,360	$	1,768
Prepaid expenses	$	—	$	9

The Company holds investments in a related party consisting of 1,846,722 shares of common stock of GreenHunter with a carrying value of $154,252 as of September 30, 2014 and 88,000 shares of Series C preferred stock of GreenHunter with a carrying value of $2.2 million as of September 30, 2014.

The following table sets forth the related party transaction activities for the three and nine months ended September 30, 2014 and 2013, respectively:

		Three Months Ended   September 30,						Nine Months Ended   September 30,
		2014			2013			2014		2013
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	820		$	623		$	1,754	$	2,069
	Equipment rental (1)	74			95			215		167
	Gas gathering-trucking (1)	132			—			532		—
	MAG tank panels (1)	—			—			800		—
	Office space rental	—			—			36		—
	Interest income from note receivable (2)	38			51			121		159
	Dividends earned from Series C shares	55			73			165		165
	Unrealized gain/(loss) on investments (2)	(38		)	(24		)	123		653
Pilatus Hunter, LLC
	Airplane rental expenses (3)	49			26			207		94

_________________________________

(1) GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and Viking International Resources Co., Inc., wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.

(2) On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water, LLC ("GreenHunter Water"), a wholly-owned subsidiary of GreenHunter.  The Company recognized an embedded derivative asset resulting from the conversion option under the convertible promissory note it received as partial consideration for the sale.  See "Note 8 - Fair Value of Financial Instruments" for additional information. The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long-term assets and an available for sale investment in GreenHunter included in investments. 

(3) The Company rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans. Airplane rental expenses are recorded in general and administrative expense.

In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water. 

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As of September 30, 2014, Mr. Evans, the Company's Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Hunter Holdings. On October 3, 2014, in connection with the New LLC Agreement, these Class A Common Units were converted into Series A-1 Common Units. See "Note 20 - Subsequent Events".

NOTE 16 - COMMITMENTS AND CONTINGENCIES

Commitment for Firm Transportation

On August 18, 2014, Triad Hunter executed a Precedent Agreement for Texas Gas Transmission LLC's ("TGT") Northern Supply Access Line (the "TGT Transportation Services Agreement"). Through executing the TGT Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation capacity on TGT's Northern Supply Access Line. The term of the TGT Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to be in early 2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement is contingent upon TGT receiving appropriate approvals from the Federal Energy Regulatory Commission ("FERC") for their pipeline project. Upon executing a Firm Transportation Agreement, the Company will have minimum annual contractual obligations for reservation charges of approximately $12.8 million over the 15 year term of the agreement.

On October 21, 2014, Triad Hunter executed a Credit Support Agreement with TGT pursuant to which Triad Hunter agreed to provide, at discrete points in time, letters of credit to TGT tied to the expected payments for firm transportation. See "Note 20 - Subsequent Events" for additional information.

Agreement to Purchase Utica Shale Acreage

On August 12, 2013, Triad Hunter entered into an asset purchase agreement with MNW Energy, LLC ("MNW"). MNW is an Ohio limited liability company that represents an informal association of various land owners, lessees and sub-lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the purchase agreement, Triad Hunter has agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties, over a period of time, in staggered closings, subject to certain conditions. On December 30, 2013, a lawsuit was filed against the Company, Triad Hunter, MNW and others by Dux Petroleum, LLC ("Dux")asserting certain claims relating to the acreage covered by the asset purchase agreement with MNW. As a result of the litigation, no purchases were made during the first quarter of 2014. On May 28, 2014, the litigation was settled. As part of the settlement, the Company and Triad Hunter agreed to collectively pay Dux the aggregate amount of $500,000. Subsequent to the settlement of the lawsuit, Triad Hunter resumed closings of lease acquisitions from MNW. On June 5, 2014, Triad Hunter closed on the acquisition of 11,128 net leasehold acres for $45.9 million from MNW. To date, under the asset purchase agreement, Triad Hunter has now acquired a total of approximately 17,000 net leasehold acres from MNW, or approximately 53% of the approximately 32,000 total net leasehold acres anticipated under the asset purchase agreement.

Takeover Bid

On June 20, 2014, the Company lodged a Bidder’s Statement with the Australian Securities and Investments Commission, through its wholly owned subsidiary, Outback Shale Hunter Pty Ltd, an Australian company, to commence an off-market takeover offer (the "Offer") for Ambassador Oil and Gas Limited, an Australian company listed on the Australian Securities Exchange ("ASX") (ASX: AQO) ("Ambassador").  Pursuant to the Offer, the Company offered one share of its common stock, par value $0.01 per share, for every 23.6 ordinary (or common) shares of Ambassador. The Offer closed on September 5, 2014. Ambassador shareholders holding 23,116 shares of Ambassador ordinary (or common) shares, representing less than 1% of the total number of Ambassador shares outstanding, accepted the Offer. In October 2014, the Company issued a total of 980 shares of its common stock to the Ambassador shareholders who accepted the Offer.

Settlement Agreement with Seminole Energy Services

On January 10, 2014, the Company and certain of its subsidiaries entered into an Omnibus Settlement Agreement and Release (the "Settlement Agreement") dated January 9, 2014 with Seminole Energy Services, LLC and certain of its affiliates (collectively, "Seminole"). In connection with and pursuant to the terms of the Settlement Agreement, the Company and Seminole agreed to release and discharge each other from all claims and causes of action alleged in, arising from or related to certain legal proceedings and to terminate, amend and enter into certain new, related agreements effective immediately prior to year-end on December 31, 2013 (the "New Agreements").

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By entering into the New Agreements, the Company and Seminole restructured their existing agreements. The Company obtained a reduction in gas gathering rates it pays for natural gas owned or controlled by the Company that is gathered on the Stone Mountain Gathering System. The Company and Seminole collectively agreed to construct an enhancement of the Rogersville Plant designed to recover less ethane and more propane from the natural gas processed at the Rogersville Plant. The parties also agreed to reduce and extend the Company's contractual horizontal well drilling obligations owed to Seminole. The Company's drilling obligation to Seminole, which required the Company to drill and complete four wells in southern Appalachia, expired on June 30, 2014, and, pursuant to the Settlement Agreement, the Company paid Seminole $450,000 as a result of the Company's decision not to drill two out of the required four wells.

The Company and Seminole also agreed to modify the natural gas processing rates the Company will pay for processing at the Rogersville Plant, the Company's allocation of NGL recovered from gas processed and the costs of blend stock necessary to blend with the NGL produced from the Rogersville Plant, and certain deductions to the NGL purchase price the Company will pay Seminole for the Company's NGL produced from the Rogersville Plant. Seminole sold to the Company Seminole's 50% interest in a natural gas gathering trunk line and treatment facility located in southwestern Muhlenberg County, Kentucky, which had previously been owned equally by Seminole and the Company.

Drilling Rig Purchase

During June 2014, the Company, through its 100% owned subsidiary, Alpha Hunter Drilling, LLC, signed an agreement to purchase a new drilling rig for a total purchase price of approximately $6.5 million, including a $1.3 million deposit due on July 1, 2014 with the remainder due upon delivery on January 15, 2015.

PVA Arbitration Decision

On July 25, 2014, the Company received the final determination from the arbitrator in the disagreement related to the final working capital adjustments pertaining to the sale of Eagle Ford Hunter to Penn Virginia in 2013. In accordance with ASC 855, the Company took this final determination into account in estimating its liability as of June 30, 2014. As a result, the Company recorded a total liability of $33.7 million, plus accrued interest of $1.3 million, as of June 30, 2014 based upon the final determination made by the arbitrator. This liability was settled in cash on July 31, 2014. The arbitrator declined to rule, on the basis of lack of authority, on two claims made by Penn Virginia related to working capital adjustments governed by a transition services agreement in the amount of $7.8 million. Any potential liability from these claims cannot currently be estimated.

Legal Proceedings

Securities Cases

On April 23, 2013, Anthony Rosian, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against the Company and certain of its officers, two of whom, at that time, also served as directors, and one of whom continues to serve as a director. On April 24, 2013, Horace Carvalho, individually and on behalf of all other persons similarly situated, filed a similar class action complaint in the United States District Court, Southern District of Texas, against the Company and certain of its officers. Several substantially similar putative class actions were filed in the Southern District of New York and in the Southern District of Texas. All such cases are collectively referred to as the Securities Cases. The cases filed in the Southern District of Texas have since been dismissed. The cases filed in the Southern District of New York were consolidated and have since been dismissed. The plaintiffs in the Securities Cases had filed a consolidated amended complaint alleging that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company's internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company's 2012 Form 10-K, the dismissal of Magnum Hunter's previous independent registered accounting firm, the Company’s characterization of the auditors’ position with respect to the dismissal, and other matters identified in the Company's April 16, 2013 Form 8-K, as amended. The consolidated amended complaint asserted claims under Sections 10(b) and 20 of the Exchange Act based on alleged false statements made regarding these issues throughout the alleged class period, as well as claims under Sections 11, 12, and 15 of the Securities Act based on alleged false statements and omissions regarding the Company’s internal controls made in connection with a public offering that Magnum Hunter completed on May 14, 2012. The consolidated amended complaint demanded that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company's stock price between February 22, 2013 and April 22, 2013. In January 2014, the Company and the individual defendants filed a motion to dismiss the Securities Cases. On June 23, 2014, the United States District Court for the Southern District of New York granted the Company’s and the individual defendants' motion to dismiss the Securities Cases and, accordingly, the Securities Cases have now been dismissed. The plaintiffs have appealed the decision to the U.S. Court of Appeals for the Second Circuit, which the Company intends to vigorously defend. It is possible that additional investor lawsuits could be filed over these events.

35

On May 10, 2013, Steven Handshu filed a stockholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers. On June 6, 2013, Zachariah Hanft filed another stockholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers. On June 18, 2013, Mark Respler filed another stockholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers. On June 27, 2013, Timothy Bassett filed another stockholder derivative suit in the Southern District of Texas on behalf of the Company against the Company's directors and senior officers. On September 16, 2013, the Southern District of Texas allowed Joseph Vitellone to substitute for Mr. Bassett as plaintiff in that action. On March 19, 2014 Richard Harveth filed another stockholder derivative suit in the 125th District Court of Harris County, Texas.  These suits are collectively referred to as the Derivative Cases. The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the stockholder derivative case maintained by Joseph Vitellone and entered a final judgment of dismissal. The court held that Mr. Vitellone failed to plead particularized facts demonstrating that pre-suit demand on the Company’s board was excused. In addition, on December 13, 2013, the 151st Judicial District Court of Harris County, Texas dismissed the lawsuit filed by Steven Handshu for want of prosecution after the plaintiff failed to serve any defendant in that matter. On January 21, 2014, the Hanft complaint was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the United States District Judge for the District of Delaware granted the Company’s supplemental motion to dismiss the Derivative Case filed by Mark Respler. All of the Derivative Cases have now been dismissed, except the Derivative Case filed by Richard Harveth, for which the Company is presently seeking dismissal. It is possible that additional stockholder derivative suits could be filed over these events.

In addition, the Company has received several demand letters from stockholders seeking books and records relating to the allegations in the Securities Cases and the Derivative Cases under Section 220 of the Delaware General Corporation Law. On September 17, 2013, Anthony Scavo, who is one of the stockholders that made a demand, filed a books and records action in the Delaware Court of Chancery pursuant to Section 220 of the Delaware General Corporation Law (the "Scavo Action"). The Scavo Action seeks various books and records relating to the claims in the Securities Cases and the Derivative Cases, as well as costs and attorneys’ fees. The Company has filed an answer in the Scavo Action, which has now been dismissed. It is possible that additional similar actions may be filed and that similar stockholder demands could be made.

In April 2013, the Company also received a letter from the SEC stating that the SEC's Division of Enforcement was conducting an inquiry regarding the Company's internal controls, change in outside auditors and public statements to investors and asking the Company to preserve documents relating to these matters. The Company is complying with this request. On December 30, 2013, the Company received a document subpoena relating to the issues identified in the April 2013 letter, and the SEC has also issued subpoenas for testimony and has taken testimony from certain individuals. The Company intends to cooperate with the subpoenas.

Any potential liability from these claims cannot currently be estimated.

Twin Hickory Matter

On April 11, 2013, a flash fire occurred at Eureka Hunter Pipeline’s Twin Hickory site located in Tyler County, West Virginia. The incident occurred during a pigging operation at a natural gas receiving station. Two employees of third-party contractors received fatal injuries. Another employee of a third-party contractor was injured.

In mid-February 2014, the estate of one of the deceased third-party contractor employees sued Eureka Hunter Pipeline and certain other parties in Karen S. Phipps v. Eureka Hunter Pipeline, LLC et al., Civil Action No. 14-C-41, in the Circuit Court of Ohio County, West Virginia. In October 2014, in Exterran Energy Solutions, LP v. Eureka Hunter Pipeline, LLC and Magnum Hunter Resources Corporation, Civil Action No. 2014-63353, in the District Court of Harris County, Texas, Exterran Energy Solutions, LP, one of the co-defendants in the Phipps lawsuit, filed suit against the Company and Eureka Hunter Pipeline seeking a declaratory judgment that Eureka Hunter Pipeline is obligated to indemnify Exterran with respect to the Phipps lawsuit. In April 2014, the estate of the other deceased third-party contractor employee sued the Company, Eureka Hunter Pipeline and certain other parties in Antoinette M. Miller v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-111, in the Circuit Court of Ohio County, West Virginia. The plaintiffs allege that Eureka Hunter Pipeline and the other defendants engaged in certain negligent and reckless conduct which resulted in the wrongful death of the third-party contractor employees. The plaintiffs have demanded judgment for an unspecified amount of compensatory, general and punitive damages. Various cross-claims have been asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter Resources Corporation and certain other parties in Jonathan Whisenhunt v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-135, in the Circuit Court of Ohio

36

County, West Virginia. Investigation regarding the incident is ongoing. It is not possible to predict at this juncture the extent to which, if at all, Eureka Hunter Pipeline or any related entities will incur liability or damages because of this incident. However, the Company believes that its insurance coverage will be sufficient to cover any losses or liabilities it may incur as a result of this incident.

PRC Williston Matter

On December 16, 2013, Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. (together, the "Plaintiffs") filed suit against PRC Williston in the Court of Chancery of the State of Delaware. PRC Williston and the Plaintiffs entered into Participation Agreements in February 2007 in connection with the Plaintiffs extending credit to PRC Williston pursuant to a credit agreement entitling the Plaintiffs to a 12.5% collective interest in any distributions in respect of the equity interests of the members of PRC Williston. Plaintiffs claim that they are entitled to compensation for 12.5% of alleged past distributions on equity from PRC Williston to Magnum Hunter and 12.5% of any transfers of funds to Magnum Hunter from the proceeds of the December 30, 2013 sale of PRC Williston’s assets. On December 23, 2013, the Chancery Court entered a temporary restraining order prohibiting PRC Williston from transferring, assigning, removing, distributing or otherwise displacing to Magnum Hunter, Magnum Hunter’s creditors, or any other person or entity, $5.0 million of the proceeds received by PRC Williston in connection with the sale of its assets. On March 18, 2014, the Court granted Plaintiffs’ motion for a preliminary injunction, extending the relief granted by the temporary restraining order until after a full trial on the merits.

On July 24, 2014, the Company, PRC Williston, and the Plaintiffs executed a Settlement and Release Agreement ("the Settlement Agreement"). Per the terms of the Settlement Agreement, PRC Williston paid approximately $2.9 million in cash to Drawbridge Special Opportunities Fund LP. As a result of the Settlement Agreement, the Company, PRC Williston, and the Plaintiffs agreed to release each other from all claims, past, present or future, related to the dispute. In addition, with the execution of the Settlement Agreement, the parties agreed to terminate, in all respects, the Participation Agreements and that none of the parties would have any further rights or obligations thereunder. With the cash settlement payment and the termination of the Participation Agreements, the Company now has rights and claims to 100% of the equity interests in PRC Williston and its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston's equity reflected in our consolidated financial statements.

General

We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.

NOTE 17 - SUPPLEMENTAL CASH FLOW INFORMATION

The following table summarizes cash paid (received) for interest and income taxes, as well as non-cash investing transactions:

	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Cash paid for interest	$	38,565	$	38,225
Non-cash transactions
Common stock issued for 401k matching contributions	$	1,593	$	1,192
Non-cash consideration received from sale of assets	$	9,447	$	—
Change in accrued capital expenditures	$	129,778	$	(5,742	)
Non-cash additions to asset retirement obligation	$	2,439	$	2,089
Eureka Hunter Holdings Series A Preferred Unit dividends paid in kind	$	1,950	$	6,367

NOTE 18 - SEGMENT REPORTING

Magnum Hunter has three reportable current operating segments: U.S. upstream, midstream and marketing, and oilfield services represent the current operating segments of the Company.  Beginning September 30, 2013, the Canadian upstream segment, comprised of the WHI Canada operations, was classified as held for sale on the consolidated balance sheet and as a discontinued operation on the consolidated statement of operations. The Company sold 100% of the equity in WHI Canada in May 2014.

37

The following tables set forth operating activities by segment for the three and nine months ended September 30, 2014 and 2013, respectively.

	As of and for the Three Months Ended September 30, 2014
	U.S. Upstream			Canadian Upstream		Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	63,438		$	—	$	11,845		$	8,176		$	—		$	(3,789	)	$	79,670
Depletion, depreciation, amortization and accretion	31,217			—		4,224			929			—			—			36,370
Gain on sale of assets, net	(7,988		)	—		(12		)	—			—			—			(8,000		)
Other operating expenses	87,035			—		7,350			6,569			11,711			(3,789		)	108,876
Other income (expense)	1,907			—		(58,078		)	(205		)	(9,237		)	—			(65,613		)
Income (loss) from continuing operations before income tax	(44,919		)	—		(57,795		)	473			(20,948		)	—			(123,189		)
Total income (loss) from discontinued operations, net of tax 1	(259		)	—		—			—			1			—			(258		)
Net income (loss)	$	(45,178	)	$	—	$	(57,795	)	$	473		$	(20,947	)	$	—		$	(123,447	)
Total assets	$	1,475,305		$	—	$	443,008		$	45,661		$	74,614		$	(5,023	)	$	2,033,565
Total capital expenditures	$	104,265		$	—	$	88,525		$	3,628		$	21		$	—		$	196,439

_________________________________

(1) Gain (loss) on disposal of discontinued operations related to WHI Canada is included in the Corporate Unallocated segment, as the Company sold 100% of its ownership interest in the entity.

	As of and for the Three Months Ended September 30, 2013
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	59,325		$	—		$	14,618		$	6,448		$	—		$	(2,100	)	$	78,291
Depletion, depreciation, amortization and accretion	25,233			—			3,174			720			—			—			29,127
Loss on sale of assets, net	40,952			—			—			—			—			—			40,952
Other operating expenses	100,484			—			11,140			4,931			11,457			74			128,086
Other income (expense)	2,038			—			(16,572		)	(141		)	(20,814		)	2,268			(33,221		)
Income (loss) from continuing operations before income tax	(105,306		)	—			(16,268		)	656			(32,271		)	94			(153,095		)
Income tax benefit (expense)	17,794			926			—			—			(18,138		)	—			582
Total income (loss) from discontinued operations, net of tax	(13,881		)	(132,861		)	—			—			1,742			(94		)	(145,094		)
Net income (loss)	$	(101,393	)	$	(131,935	)	$	(16,268	)	$	656		$	(48,667	)	$	—		$	(297,607	)
Total assets	$	1,406,515		$	106,438		$	269,692		$	42,648		$	62,182		$	(1,659	)	$	1,885,816
Total capital expenditures	$	149,577		$	181		$	19,918		$	5,850		$	504		$	—		$	176,030

38

	As of and for the Nine Months Ended September 30, 2014
	U.S. Upstream			Canadian Upstream		Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	223,788		$	—	$	98,697		$	23,882		$	—		$	(14,752	)	$	331,615
Depletion, depreciation, amortization and accretion	87,345			—		11,831			2,557			—			—			101,733
Gain on sale of assets, net	(4,231		)	—		(12		)	(369		)	—			—			(4,612		)
Other operating expenses	197,013			—		86,120			19,643			35,253			(14,752		)	323,277
Other income (expense)	1,739			—		(98,505		)	(625		)	(54,979		)	—			(152,370		)
Income (loss) from continuing operations before income tax	(54,600		)	—		(97,747		)	1,426			(90,232		)	—			(241,153		)
Total income (loss) from discontinued operations, net of tax 1	(7,283		)	10,636		—			—			(12,775		)	—			(9,422		)
Net income (loss)	$	(61,883	)	$	10,636	$	(97,747	)	$	1,426		$	(103,007	)	$	—		$	(250,575	)
Total assets	$	1,475,305		$	—	$	443,008		$	45,661		$	74,614		$	(5,023	)	$	2,033,565
Total capital expenditures	$	320,719		$	305	$	171,152		$	6,575		$	127		$	—		$	498,878

_________________________________

(1) Gain (loss) on disposal of discontinued operations related to WHI Canada is included in the Corporate Unallocated segment, as the Company sold 100% of its ownership interest in the entity.

	As of and for the Nine Months Ended September 30, 2013
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	158,217		$	—		$	48,071		$	13,873		$	—		$	(5,802	)	$	214,359
Depletion, depreciation, amortization and accretion	69,420			—			9,142			1,579			—			—			80,141
Loss on sale of assets, net	42,110			—			—			4			—			—			42,114
Other operating expenses	198,363			—			41,276			12,884			38,932			(3,628		)	287,827
Other income (expense)	440			—			(24,261		)	(372		)	(47,330		)	2,288			(69,235		)
Income (loss) from continuing operations before income tax	(151,236		)	—			(26,608		)	(966		)	(86,262		)	114			(264,958		)
Income tax benefit	23,560			—			—			—			23,667			—			47,227
Total income (loss) from discontinued operations, net of tax	181,233			(134,070		)	—			—			(6,571		)	(114		)	40,478
Net income (loss)	$	53,557		$	(134,070	)	$	(26,608	)	$	(966	)	$	(69,166	)	$	—		$	(177,253	)
Total assets	$	1,406,515		$	106,438		$	269,692		$	42,648		$	62,182		$	(1,659	)	$	1,885,816
Total capital expenditures	$	322,768		$	14,317		$	55,003		$	19,971		$	927		$	—		$	412,986

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NOTE 19 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS

Guarantor Subsidiaries

Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, Shale Hunter, Magnum Hunter Marketing, LLC, Magnum Hunter Production, Inc., NGAS Hunter, LLC, Triad Hunter, and Viking International Resources, Co., Inc. (collectively, "Guarantor Subsidiaries"), jointly and severally guarantee on a senior unsecured basis, the obligations of the Company under all the Senior Notes issued under the indenture entered into by the Company on May 16, 2012, as supplemented. The Guarantor Subsidiaries also may guarantee any debt of the Company issued pursuant to the Form S-3 Registration Statement filed by the Company with the SEC on August 5, 2014.

These condensed consolidating guarantor financial statements have been revised to reflect Eagle Ford Hunter and PRC Williston as non-guarantors as the subsidiaries are no longer guarantors of the Company's Senior Notes.

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, 2014 and December 31, 2013, and for the three and nine months ended September 30, 2014 and 2013, are as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of September 30, 2014
	Magnum Hunter Resources Corporation		100% Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	52,405	$	43,367	$	10,301		$	(5,022	)	$	101,051
Intercompany accounts receivable	1,084,519		—		—			(1,084,519		)	—
Property and equipment (using successful efforts method of accounting)	5,614		1,390,673		395,027			—			1,791,314
Investment in subsidiaries	193,337		100,392		—			(293,729		)	—
Assets held for sale and other	16,594		87,291		37,315			—			141,200
Total Assets	$	1,352,469	$	1,621,723	$	442,643		$	(1,383,270	)	$	2,033,565
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	40,822	$	124,895	$	94,550		$	(5,025	)	$	255,242
Intercompany accounts payable	—		1,044,555		42,201			(1,086,756		)	—
Long-term liabilities	856,161		45,822		253,257			—			1,155,240
Redeemable preferred stock	100,000		—		151,685			—			251,685
Shareholders' equity (deficit)	355,486		406,451		(99,050		)	(291,489		)	371,398
Total Liabilities and Shareholders' Equity	$	1,352,469	$	1,621,723	$	442,643		$	(1,383,270	)	$	2,033,565

40

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of December 31, 2013
	Magnum Hunter Resources Corporation		100% Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	53,161	$	43,841	$	27,096	$	(3,372	)	$	120,726
Intercompany accounts receivable	965,138		—		—		(965,138		)	—
Property and equipment (using successful efforts method of accounting)	7,214		1,272,027		234,838		—			1,514,079
Investment in subsidiaries	372,236		102,314		—		(474,550		)	—
Other assets	17,308		100,894		103,644		—			221,846
Total Assets	$	1,415,057	$	1,519,076	$	365,578	$	(1,443,060	)	$	1,856,651
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	54,826	$	97,520	$	34,929	$	(3,410	)	$	183,865
Intercompany accounts payable	—		921,237		43,866		(965,103		)	—
Long-term liabilities	818,651		39,067		127,663		—			985,381
Redeemable preferred stock	100,000		—		136,675		—			236,675
Shareholders' equity (deficit)	441,580		461,252		22,445		(474,547		)	450,730
Total Liabilities and Shareholders' Equity	$	1,415,057	$	1,519,076	$	365,578	$	(1,443,060	)	$	1,856,651

41

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Three Months Ended September 30, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	10		$	72,809		$	11,141		$	(4,290	)	$	79,670
Expenses	21,317			115,817			70,015			(4,290		)	202,859
Income (loss) from continuing operations before equity in net income of subsidiaries	(21,307		)	(43,008		)	(58,874		)	—			(123,189		)
Equity in net income of subsidiaries	(105,762		)	(1,093		)	—			106,855			—
Income (loss) from continuing operations before income tax	(127,069		)	(44,101		)	(58,874		)	106,855			(123,189		)
Income tax benefit (expense)	—			—			—			—			—
Income (loss) from continuing operations	(127,069		)	(44,101		)	(58,874		)	106,855			(123,189		)
Income from discontinued operations, net of tax	—			—			—			—			—
Gain on sale of discontinued operations, net of tax	(259		)	—			1			—			(258		)
Net income (loss)	(127,328		)	(44,101		)	(58,873		)	106,855			(123,447		)
Net income attributable to non-controlling interest	—			—			—			2,764			2,764
Net income (loss) attributable to Magnum Hunter Resources Corporation	(127,328		)	(44,101		)	(58,873		)	109,619			(120,683		)
Dividends on preferred stock	(8,848		)	—			(6,644		)	—			(15,492		)
Net income (loss) attributable to common shareholders	$	(136,176	)	$	(44,101	)	$	(65,517	)	$	109,619		$	(136,175	)
	Three Months Ended September 30, 2013
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	29		$	71,246		$	9,112		$	(2,096	)	$	78,291
Expenses	35,350			171,183			27,045			(2,192		)	231,386
Income (loss) from continuing operations before equity in net income of subsidiaries	(35,321		)	(99,937		)	(17,933		)	96			(153,095		)
Equity in net income of subsidiaries	(236,767		)	163			(28,543		)	265,147			—
Income (loss) from continuing operations before income tax	(272,088		)	(99,774		)	(46,476		)	265,243			(153,095		)
Income tax benefit (expense)	(18,138		)	17,793			927			—			582
Income (loss) from continuing operations	(290,226		)	(81,981		)	(45,549		)	265,243			(152,513		)
Income (loss) from discontinued operations, net of tax	1,743			—			(77,220		)	(96		)	(75,573		)
Gain on sale of discontinued operations, net of tax	(13,880		)	—			(55,641		)	—			(69,521		)
Net income (loss)	(302,363		)	(81,981		)	(178,410		)	265,147			(297,607		)
Net income attributable to non-controlling interest	—			—			—			725			725
Net income (loss) attributable to Magnum Hunter Resources Corporation	(302,363		)	(81,981		)	(178,410		)	265,872			(296,882		)
Dividends on preferred stock	(8,820		)	—			(5,597		)	—			(14,417		)
Net income (loss) attributable to common shareholders	$	(311,183	)	$	(81,981	)	$	(184,007	)	$	265,872		$	(311,299	)

42

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Nine Months Ended September 30, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	124		$	313,898		$	32,846		$	(15,253	)	$	331,615
Expenses	92,622			363,587			131,812			(15,253		)	572,768
Income (loss) from continuing operations before equity in net income of subsidiaries	(92,498		)	(49,689		)	(98,966		)	—			(241,153		)
Equity in net income of subsidiaries	(153,569		)	(1,922		)	—			155,491			—
Income (loss) from continuing operations before income tax	(246,067		)	(51,611		)	(98,966		)	155,491			(241,153		)
Income tax benefit (expense)	—			—			—			—			—
Income (loss) from continuing operations	(246,067		)	(51,611		)	(98,966		)	155,491			(241,153		)
Income from discontinued operations, net of tax	—			—			4,561			—			4,561
Gain (loss) on sale of discontinued operations, net of tax	(20,058		)	—			6,075			—			(13,983		)
Net income (loss)	(266,125		)	(51,611		)	(88,330		)	155,491			(250,575		)
Net income attributable to non-controlling interest	—			—			—			3,653			3,653
Net income (loss) attributable to Magnum Hunter Resources Corporation	(266,125		)	(51,611		)	(88,330		)	159,144			(246,922		)
Dividends on preferred stock	(26,516		)	—			(19,202		)	—			(45,718		)
Net income (loss) attributable to common shareholders	$	(292,641	)	$	(51,611	)	$	(107,532	)	$	159,144		$	(292,640	)
	Nine Months Ended September 30, 2013
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	(134	)	$	194,599		$	25,693		$	(5,799	)	$	214,359
Expenses	91,559			337,827			55,845			(5,914		)	479,317
Income (loss) from continuing operations before equity in net income of subsidiaries	(91,693		)	(143,228		)	(30,152		)	115			(264,958		)
Equity in net income of subsidiaries	(274,930		)	(479		)	(37,930		)	313,339			—
Income (loss) from continuing operations before income tax	(366,623		)	(143,707		)	(68,082		)	313,454			(264,958		)
Income tax benefit (expense)	23,667			23,560			—			—			47,227
Income (loss) from continuing operations	(342,956		)	(120,147		)	(68,082		)	313,454			(217,731		)
Income (loss) from discontinued operations, net of tax	(6,570		)	22,661			(78,429		)	(115		)	(62,453		)
Gain on sale of discontinued operations, net of tax	158,572			—			(55,641		)	—			102,931
Net income (loss)	(190,954		)	(97,486		)	(202,152		)	313,339			(177,253		)
Net income attributable to non-controlling interest	—			—			—			1,614			1,614
Net income (loss) attributable to Magnum Hunter Resources Corporation	(190,954		)	(97,486		)	(202,152		)	314,953			(175,639		)
Dividends on preferred stock	(26,603		)	—			(15,431		)	—			(42,034		)
Net income (loss) attributable to common shareholders	$	(217,557	)	$	(97,486	)	$	(217,583	)	$	314,953		$	(217,673	)

43

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended September 30, 2014
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(127,328	)	$	(44,101	)	$	(58,873	)	$	106,855	$	(123,447	)
Foreign currency translation gain	—			—			—			—		—
Unrealized loss on available for sale securities	—			(2,583		)	—			—		(2,583		)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	—			—			—			—		—
Comprehensive income (loss)	(127,328		)	(46,684		)	(58,873		)	106,855		(126,030		)
Comprehensive income attributable to non-controlling interest	—			—			—			2,764		2,764
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(127,328	)	$	(46,684	)	$	(58,873	)	$	109,619	$	(123,266	)

	Three Months Ended September 30, 2013
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(302,363	)	$	(81,981	)	$	(178,410	)	$	265,147	$	(297,607	)
Foreign currency translation loss	—			—			3,856			—		3,856
Unrealized gain (loss) on available for sale securities	3,562			173			—			—		3,735
Amounts reclassified from accumulated other comprehensive income	(8,262		)	—			—			—		(8,262		)
Comprehensive income (loss)	(307,063		)	(81,808		)	(174,554		)	265,147		(298,278		)
Comprehensive income attributable to non-controlling interest	—			—			—			725		725
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(307,063	)	$	(81,808	)	$	(174,554	)	$	265,872	$	(297,553	)

44

	Nine Months Ended September 30, 2014
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(266,125	)	$	(51,611	)	$	(88,330	)	$	155,491	$	(250,575	)
Foreign currency translation loss	—			—			(1,218		)	—		(1,218		)
Unrealized loss on available for sale securities	—			(3,188		)	—			—		(3,188		)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	20,741			—			—			—		20,741
Comprehensive income (loss)	(245,384		)	(54,799		)	(89,548		)	155,491		(234,240		)
Comprehensive income attributable to non-controlling interest	—			—			—			3,653		3,653
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(245,384	)	$	(54,799	)	$	(89,548	)	$	159,144	$	(230,587	)

	Nine Months Ended September 30, 2013
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(190,954	)	$	(97,486	)	$	(202,152	)	$	313,339	$	(177,253	)
Foreign currency translation loss	—			—			(7,943		)	—		(7,943		)
Unrealized gain (loss) on available for sale securities	8,262			(78		)	—			—		8,184
Amounts reclassified from accumulated other comprehensive income	(8,262		)	—			—			—		(8,262		)
Comprehensive income (loss)	(190,954		)	(97,564		)	(210,095		)	313,339		(185,274		)
Comprehensive income attributable to non-controlling interest	—			—			—			1,614		1,614
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(190,954	)	$	(97,564	)	$	(210,095	)	$	314,953	$	(183,660	)

45

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	Nine Months Ended September 30, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(261,039	)	$	222,520		$	52,074		$	—	$	13,555
Cash flow from investing activities	63,502			(211,560		)	(99,246		)	—		(247,304		)
Cash flow from financing activities	193,885			2,232			38,542			—		234,659
Effect of exchange rate changes on cash	—			—			44			—		44
Net increase (decrease) in cash	(3,652		)	13,192			(8,586		)	—		954
Cash at beginning of period	47,895			(17,651		)	11,469			—		41,713
Cash at end of period	$	44,243		$	(4,459	)	$	2,883		$	—	$	42,667

	Nine Months Ended September 30, 2013
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(264,051	)	$	236,112		$	107,136		$	—	$	79,197
Cash flow from investing activities	422,056			(245,179		)	(132,054		)	—		44,823
Cash flow from financing activities	(152,265		)	2,105			23,893			—		(126,267		)
Effect of exchange rate changes on cash	—			—			(93		)	—		(93		)
Net increase (decrease) in cash	5,740			(6,962		)	(1,118		)	—		(2,340		)
Cash at beginning of period	26,872			(4,187		)	34,938			—		57,623
Cash at end of period	$	32,612		$	(11,149	)	$	33,820		$	—	$	55,283

46

NOTE 20 - SUBSEQUENT EVENTS

Second Amended and Restated Eureka Hunter Holdings LLC Agreement

On September 16, 2014, the Company entered into a Transaction Agreement with MSI relating to a separate purchase agreement between MSI and Ridgeline providing for the purchase by MSI of all the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units owned by Ridgeline. The Transaction Agreement contemplates two closings comprised of (i) the purchase by MSI of Ridgeline's equity interests in Eureka Hunter Holdings and the execution of the New LLC Agreement; and (ii) the purchase by MSI of an additional equity interest in Eureka Hunter Holdings from MHR as described below. On October 3, 2014, the first closing contemplated in the Transaction Agreement was consummated between MSI and Ridgeline. The Company was not a party to the transaction between MSI and Ridgeline.

Contemporaneously with the first closing, the New LLC Agreement for Eureka Hunter Holdings became effective. In accordance with the terms of the New LLC Agreement, all of the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units of Eureka Hunter Holdings acquired by MSI from Ridgeline were converted into a new class of common equity interests of Eureka Hunter Holdings (the "Series A-2 Units"). Magnum Hunter's Class A Common Units held on the date of the first closing were also converted into a new class of common equity (the "Series A-1 Common Units"). The Series A-2 Units will have a liquidation preference to the Series A-1 Common Units if a Sale Transaction (as defined in the New LLC Agreement) or Initial Public Offering (as defined in the New LLC Agreement) occurs subsequent to January 1, 2017. The liquidation preference available to the Series A-2 Unit members provides a specified Internal Rate of Return (as defined in the New LLC Agreement), depending upon the proceeds available for distribution upon a Sale Transaction or an Initial Public Offering. Once the Internal Rate of Return (as defined in the New LLC Agreement) applicable to Series A-2 Unit members is achieved, Series A-2 Unit members and Series A-1 Unit members will participate in remaining distributions according to their Upside Sharing Percentages (as defined in the New LLC Agreement).

As a result of the conversion of the Eureka Hunter Holdings Series A Preferred Units into Series A-2 Units, the features, terms, and cash flows associated with the Series A-2 Units are substantially different than those of the former Eureka Hunter Holdings Series A Preferred Units. Consequently, it is anticipated that the conversion will be treated as an extinguishment of a class of equity, and an issuance of a new class of equity that will be recorded initially at fair value. Additionally, the accrued and unpaid dividends outstanding on the Eureka Hunter Holdings Series A Preferred Units and the fair value associated with the embedded derivative attached to the Eureka Hunter Holdings Series A Preferred Units, which has been accounted for as a liability in these consolidated financial statements, will be included in determining the total carrying value of the equity to be extinguished.

The Transaction Agreement further provides that Magnum Hunter will sell to MSI in a second closing, that is expected to occur in mid-January 2015, a portion of its Eureka Hunter Holdings Series A-1 Common Units, which, assuming completion of the full amount of additional capital contributions expected to be made by MSI, would constitute approximately 6.5% of the total common equity interests then outstanding in Eureka Hunter Holdings. Any Series A-1 Common Units purchased by MSI from the Company under a second closing will convert immediately into Series A-2 Units. The purchase price of such additional equity interests is expected to be approximately $65 million. Such closing, together with follow on capital contributions expected to be made by MSI in 2014, will result in Magnum Hunter and MSI owning approximately equal equity interests in Eureka Hunter Holdings which collectively will constitute an approximate 98% equity interest in Eureka Hunter Holdings. Upon consummation of the second closing, the Company will reassess its subsequent accounting for Eureka Hunter Holdings in accordance with the criteria for consolidation.

Also, in accordance with the terms and conditions of the New LLC Agreement, Magnum Hunter will have the right, under certain circumstances, to not make its portion of certain required future capital contributions to Eureka Hunter, and, if Magnum Hunter validly exercises its right to do so, MSI will make the capital contributions which otherwise would be made by Magnum Hunter, with Magnum Hunter having the right to make capital contributions within 180 days that will bring Magnum Hunter's ownership interest back to the level prior to the capital call. This catch-up feature will be at no cost to Magnum Hunter but will be subject to a maximum of $40 million for each 180-day period.

Sales of Certain North Dakota Assets

On October 15, 2014, Bakken Hunter closed on the sale of certain non-operated working interests in oil and natural gas properties located in Divide County, North Dakota for cash consideration of $84.8 million, subject to customary purchase price adjustments. The effective date of the sale is August 1, 2014.

47

Fourth Amended and Restated Credit Agreement and New Second Lien Term Loan

Revolving Credit Facility

On October 22, 2014, the Company entered into a New Credit Agreement, by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto. The New Credit Agreement amended and restated the Credit Agreement, dated as of December 13, 2013, by and among those parties, as amended.

The New Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing October 22, 2018 (the "Revolving Facility") with an initial borrowing base of $50 million. The Revolving Facility is governed by a semi-annual borrowing base redetermination derived from the Company’s proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or increased up to a maximum commitment level of $250 million. As discussed below, however, provisions of the Second Lien Term Loan Agreement limit the amount of indebtedness that the Company may incur under the New Credit Agreement.

The terms of the New Credit Agreement provide that the Revolving Facility may be used for loans and, subject to a $50 million sublimit, letters of credit. The New Credit Agreement provides for a commitment fee of 0.5% based on the unused portion of the borrowing base under the Revolving Facility.

Borrowings under the Revolving Facility will, at the Company’s election, bear interest at either (i) an alternate base rate ("ABR") equal to the higher of (A) the prime rate (as determined by Bank of Montreal) (B) the overnight federal funds effective rate, plus 0.50% per annum, and (C) the adjusted one-month LIBOR plus 1.00% or (ii) the adjusted LIBO Rate (which is based on LIBOR), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.00% to 2.00% for ABR loans and from 2.00% to 3.00% for adjusted LIBO Rate loans. Accrued interest on each ABR loan is payable in arrears on the last day of each March, June, September and December and accrued interest on each adjusted LIBO Rate loan is payable in arrears on the last day of the Interest Period (as defined in the New Credit Agreement) applicable to the borrowing of which such adjusted LIBO Rate loan is a part and, in the case of an adjusted LIBO Rate borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.

The New Credit Agreement contains negative covenants that, among other things, restrict the ability of the Company and its restricted subsidiaries to, with certain exceptions, (i) incur indebtedness, (ii) grant liens, (iii) make certain payments, (iv) change the nature of its business, (v) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions, (vi) make investments, loans or advances, (vii) pay cash dividends, unless certain conditions are met, and with respect to the payment of dividends on preferred stock, subject to (A) no Event of Default (as defined in the New Credit Agreement) existing, (B) after giving effect to any such preferred stock dividend payment, the Company maintaining availability under the borrowing base in an amount greater than the greater of (x) 2.50% percent of the borrowing base then in effect or (y) $5,000,000 and (C) a "basket" of $45,000,000 per year, (viii) enter into transactions with affiliates, and (ix) enter into hedging transactions.

In addition, the New Credit Agreement requires the Company to satisfy certain financial covenants, including maintaining:

(i) a current ratio of not less than 1.0 to 1.0, commencing with the fiscal quarter ending December 31, 2014;

(ii) a leverage ratio (secured net debt to EBITDAX (as defined in the New Credit Agreement) with, beginning with the fiscal quarter ending March 31, 2016, a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than (A) 2.5 to 1.0 as of the last day of the fiscal quarter ending December 31, 2014, (B) 2.25 to 1.00 as of the last day of the fiscal quarter ending March 31, 2015 and (C) 2.0 to 1.0 as of the last day of the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter; and

(iii) the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement described below.

The obligations of the Company under the New Credit Agreement may be accelerated upon the occurrence of an Event of Default. Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations and warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a Change of Control (as defined in the New Credit Agreement) and any "Event of Default" under the Second Lien Term Loan Agreement, subject to certain cure periods.

Subject to certain exceptions, the Revolving Facility is secured by substantially all of the assets of the Company and its restricted subsidiaries, including, without limitation, no less than 90% of the present value (with a discount rate of 10%) of the proved oil

48

and gas reserves of the Company and its restricted subsidiaries. Additionally, any collateral pledged as security for the Second Lien Term Loan (as defined below) is required to be pledged as security for the New Credit Agreement. In connection with the New Credit Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Revolving Facility is unconditionally guaranteed by such restricted subsidiaries. The Company’s restricted subsidiaries under the New Credit Agreement and the Second Lien Term Loan do not include the Company’s majority-owned subsidiaries through which the Company conducts its midstream operations, including Eureka Hunter Holdings, Eureka Hunter Pipeline and TransTex Hunter.

Second Lien Term Loan

On October 22, 2014, the Company also entered into a Second Lien Credit Agreement (the "Second Lien Term Loan Agreement"), by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto.

The Second Lien Term Loan Agreement provides for a $340 million term loan facility (the "Second Lien Term Loan"), secured by, subject to certain exceptions, a second lien on substantially all of the assets of the Company and its restricted subsidiaries. The entire $340 million Second Lien Term Loan was drawn on October 22, 2014. The Company used the proceeds of the Second Lien Term Loan to repay amounts outstanding under its Credit Agreement, to pay transaction expenses related to the New Credit Agreement and the Second Lien Term Loan Agreement, and for working capital and general corporate purposes. Amounts borrowed under the Second Lien Term Loan that are repaid or prepaid may not be reborrowed. The Second Lien Term Loan has a maturity date of October 22, 2019 and will amortize (beginning December 31, 2014) in equal quarterly installments in an aggregate annual amount equal to 1.00% of the original principal amount of the Second Lien Term Loan.

Borrowings under the Second Lien Term Loan will, at the Company’s election, bear interest at either (i) an alternate base rate (which is equal to the higher of (A) the prime rate (as determined by Credit Suisse), (B) the overnight federal funds effective rate, plus 0.50% per annum, and (C) the adjusted one-month LIBOR plus 1.00%) plus 6.50% or (ii) the adjusted LIBO Rate (which is based on LIBOR) plus 7.50%.

The Second Lien Term Loan Agreement contains negative covenants substantially similar to those in the New Credit Agreement that, among other things, restrict the ability of the Company and its restricted subsidiaries to, with certain exceptions: (i) incur indebtedness; (ii) grant liens; (iii) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (iv) change the nature of its business; (v) make investments, loans, or advances or guarantee obligations; (vi) pay cash dividends or make certain other payments; (vii) enter into transactions with affiliates; (viii) enter into sale and leaseback transactions; (ix) enter into hedging transactions; and (x) amend its organizational documents or the New Credit Agreement. The Second Lien Term Loan Agreement limits the amount of indebtedness that the Company may incur under the New Credit Agreement to the greater of (a) the sum of $50 million plus the aggregate amount of loans repaid or prepaid under the Second Lien Term Loan Agreement and (b) an amount equal to 25% of Adjusted Consolidated Net Tangible Assets (as defined in the Second Lien Term Loan Agreement) of the Company and its restricted subsidiaries; provided, in the case of clause (b), after giving effect to such incurrence of indebtedness and the application of proceeds therefrom, aggregate secured debt may not exceed 25% of the Adjusted Consolidated Net Tangible Assets of the Company and its restricted subsidiaries as of the date of such incurrence.

The Second Lien Term Loan Agreement also requires the Company to satisfy certain financial covenants, including maintaining

(i) a ratio of proved reserves to secured debt of not less than 1.5 to 1.0 and a ratio of proved developed and producing reserves to secured debt of not less than 1.0 to 1.0, each as of the last day of any fiscal quarter commencing with the fiscal quarter ending December 31, 2014; and

(ii) commencing with the fiscal quarter ending March 31, 2016, a leverage ratio (secured net debt to EBITDAX (as defined in the Second Lien Term Loan Agreement) with a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than 2.5 to 1.0 as of the last day of any fiscal quarter for the trailing four-quarter period then ended.

The obligations of the Company under the Second Lien Term Loan may be accelerated upon the occurrence of an Event of Default (as defined in the Second Lien Term Loan Agreement). Events of Default are substantially similar to Events of Default under the Credit Agreement (except that a breach of a financial covenant under the New Credit Agreement will not constitute an Event of Default under the Second Lien Term Loan Agreement until acceleration) and include customary events for these types of financings.

In connection with the Second Lien Term Loan Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Second Lien Term Loan is unconditionally guaranteed by such restricted subsidiaries.

49

Proceeds from the new term loan were used to repay 100% of the outstanding borrowings under the Company's prior revolving credit facility upon closing ($256 million as of September 30, 2014), and to pay fees and expenses associated with the transactions. Additional proceeds and borrowing capacity under the Revolving Facility will be available to fund operations in the Marcellus and Utica Shale plays of West Virginia and Ohio, and for general corporate purposes.

TGT Credit Support Agreement

On October 21, 2014 Triad Hunter executed a Credit Support Agreement with TGT, related to the TGT Transportation Services Agreement executed on August 18, 2014 (the "Precedent Agreement Date"). In accordance with the provisions of the Credit Support Agreement, Triad Hunter will provide TGT with letters of credit on the dates and in the amounts that follow (the "Credit Support Amount"):

(i) during the period beginning on the date that is fourteen months after the Precedent Agreement Date and ending on the day immediately prior to the date that is twenty-one months after the Precedent Agreement Date, an amount equal to $13 million

(ii) during the period beginning on the date that is twenty-one months after the Precedent Agreement Date and ending on the day immediately prior to the date that is twenty-eight months after the Precedent Agreement Date, an amount equal to $36 million; and

(iii) during the period beginning on the date that is twenty-eight months after the Precedent Agreement Date and ending on the date the Credit Support Agreement terminates, an amount equal to $65 million.

Provided however, that the Credit Support Amount shall be subject to reduction (on a cumulative basis) at specified dates depending on Triad Hunter's Interest Coverage Ratio or if Triad Hunter meets the creditworthiness standards established in the Texas Gas FERC Gas Tariff as in effect on such date that Triad Hunter meets the said standard.

REX Transportation Agreement

On October 8, 2014, Triad Hunter executed a Precedent Agreement with Rockies Express Pipeline LLC ("REX"), (the "REX Transportation Services Agreement") for the delivery by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter. In executing the REX Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation from REX. The term of the REX Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to between mid-2016 and mid-2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement is contingent upon REX receiving appropriate approvals from FERC for their pipeline project. Upon executing a Firm Transportation Agreement, the Company will have minimum annual contractual obligations for reservation charges of approximately $16.4 million over the 15 year term of the agreement.

In addition, the Company will be required to provide Credit Support to REX, in the form of a letter of credit, in the initial amount of twenty-seven months of Triad Hunter's reservation charges, or approximately $37 million, within 45 days of executing the REX Transportation Services Agreement.

Amendment to Asset Purchase Agreement and Purchase of Utica Shale Acreage

On October 28, 2014, Triad Hunter and MNW entered into the First Amendment to the Asset Purchase Agreement and Partial Release of Earn-Out Agreement (the "Amendment"). In connection with the asset purchase agreement with MNW dated August 12, 2013, Triad Hunter and MNW also entered into an earn-out agreement dated August 12, 2013 which provided for MNW to perform certain consulting services for Triad Hunter and to be paid for such services through the release by Triad Hunter of escrow funds being withheld from the purchase price at each closing under the asset purchase agreement. The Amendment terminates MNW's obligation to perform further consulting services under the earn-out agreement, provides for the disbursement of funds to MNW that have been withheld from closings to date, and amends the asset purchase agreement to end further withholdings of escrow funds from the purchase price at future closings.

On October 30, 2014, Triad Hunter purchased approximately 5,160 net acres of undeveloped leasehold in the Utica Shale in Ohio for $20.6 million under its asset purchase agreement with MNW and also released $0.4 million in escrowed funds, for a total disbursement to MNW of approximately $21.0 million. Following this purchase, approximately 9,840 net acres remain to be purchased by the Company under the asset purchase agreement with MNW, contingent upon proposed leasehold acreage being cured of title defects.

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Sale of Certain West Virginia Assets

On November 3, 2014, Triad Hunter closed on the sale of certain non-core working interests in oil and gas properties located primarily in Calhoun and Roane, Counties, West Virginia, for cash consideration of $1.2 million, subject to customary purchase price adjustments. The effective date of the sale is August 1, 2014.

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

In this Quarterly Report on Form 10-Q, references to "we", "our", "us" or the "Company" refer to Magnum Hunter Resources Corporation and its subsidiaries on a consolidated basis unless the context requires otherwise. Unless stated otherwise, all monetary amounts reported in this Quarterly Report on Form 10-Q are expressed in U.S. dollars.

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to inform the reader about matters affecting the financial condition and results of operations of the Company for the three and nine months ended September 30, 2014. Results of operations for interim periods are not necessarily indicative of results for the entire year. As a result, the following discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2013, as amended.   

Cautionary Notice 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.

These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. 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 for the year ended December 31, 2013, as amended.  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 natural gas reserves,

• uncertainty of commodity prices in oil, natural gas and natural gas liquids,

• disruption of credit and capital markets,

• our financial position,

• our cash flow and liquidity,

• replacing our oil and natural gas reserves,

• our inability to retain and attract key personnel,

• uncertainty regarding our future operating results,

• uncertainties in exploring for and producing oil and natural gas,

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

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

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

• competition in the oil and natural gas industry,

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• marketing of oil, natural 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,

• acts of nature, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits,

• interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes, and

• other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2013, as amended, and our subsequent filings with the SEC, including this Quarterly Report on Form 10-Q.

Executive Overview

We are a Houston, Texas based independent oil and natural gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and NGL resources in the United States. We are active in what we believe to be three of the most prolific unconventional shale resource plays in North America, specifically, the Marcellus Shale in West Virginia and Ohio; the Utica Shale in southeastern Ohio and western West Virginia; and the Williston Basin/Bakken Shale in North Dakota. Our oil and natural gas reserves and operations are primarily concentrated in West Virginia, Ohio, and North Dakota. We are also engaged in midstream and oil field services operations, primarily in West Virginia and Ohio.

Our principal business strategy is to (a) exploit our substantial inventory of lower risk, liquids-weighted drilling locations, (b) acquire and develop long-lived proved reserves and undeveloped leases with significant exploitation and development opportunities primarily located in close proximity to our existing core areas of operation and (c) selectively monetize our assets at opportune times and attractive prices. We believe the increased scale in all our core resource plays allows for ongoing cost recovery and production efficiencies as we exploit and monetize our asset base. We are focused on the further development and exploitation of our asset base, selective bolt-on acquisitions of additional operated properties and mineral leasehold acreage positions in our core operating regions, expansion of our midstream operations and the monetization of selected assets.

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Financial and Operational Performance Highlights

The following are key financial and operational performance highlights for the Company for the third quarter of 2014:

• Oil and natural gas revenues from continuing operations increased by 5.8% to $62.5 million compared to $59.1 million during the same three-month period in 2013.

• We reported a net loss from continuing operations of $123.2 million for the three months ended September 30, 2014, compared to net loss from continuing operations of $152.5 million for the three months ended September 30, 2013.

• Our total oil and natural gas production from continuing operations increased to 16,361 Boe/d for the three months ended September 30, 2014, compared to 10,977 Boe/d for the same period in 2013. Average production for the third quarter of 2014 was comprised of 41.0% liquids and 59.0% natural gas.

• Our first Utica Shale well in West Virginia, the Stewart Winland 1300U, was drilled and completed in September of 2014 and tested at a peak rate of 46.5 MMCF of natural gas per day (~7,750 Boe/d).

• As of September 30, 2014, we had approximately 284,382 net leasehold acres in our core operating areas, including (i) approximately 80,559 net acres in the Marcellus Shale, (ii) approximately 117,916 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and (iii) approximately 85,907 net acres in the Williston Basin/Bakken Shale in North Dakota.

• Pipeline throughput in our Midstream Segment reached a record peak of 316,500 MMBTU/d in September 2014 and increased to an average of 223,708 MMBtu/d for the three months ended September 30, 2014 compared to 78,916 MMBtu/d for the same period in 2013.

• We closed on or executed definitive purchase and sale agreements to sell non-core assets located in Divide County, North Dakota and Calhoun and Roane Counties, West Virginia for cash consideration of approximately $109.5 million, subject to customary purchase price adjustments.

• Our capital expenditures of $196.4 million during the third quarter of 2014 increased from the second quarter of 2014 as we focused our efforts on drilling in the Marcellus Shale and Utica Shale.

Recent Developments

New Partnership with Morgan Stanley Infrastructure

On September 16, 2014 we announced that the Company had entered into an agreement (the "Transaction Agreement") with an affiliate of Morgan Stanley Infrastructure Inc. ("MSI") relating to a separate purchase agreement between MSI and Ridgeline Midstream Holdings, LLC ("Ridgeline"), an affiliate of ArcLight Capital Partners, LLC ("ArcLight"), providing for the purchase by MSI of all convertible preferred and common equity interests in Eureka Hunter Holdings, LLC ("Eureka Hunter") owned by Ridgeline.

The Transaction Agreement provided for a new amended and restated limited liability company agreement for Eureka Hunter (the "New LLC Agreement") to be entered into by Magnum Hunter, MSI and the minority interest members of Eureka Hunter contemporaneously with the closing of MSI's purchase of Ridgeline's equity interests in Eureka Hunter, which occurred on October 3, 2014. In connection with the closing and the execution and delivery of the New LLC Agreement, all the convertible preferred equity interests and common equity interests in Eureka Hunter acquired by MSI from Ridgeline (approximately 41% of the total equity interests in Eureka Hunter) were converted into a new class of equity interests of Eureka Hunter, and all new equity interests owned by MSI will have a liquidation preference under certain circumstances. The liquidation preference available to the Series A-2 Unit members provides a specified Internal Rate of Return (as defined in the New LLC Agreement), depending upon the proceeds available for distribution upon a Sale Transaction or an Initial Public Offering. Once the Internal Rate of Return (as defined in the New LLC Agreement) applicable to Series A-2 Unit members is achieved, Series A-2 Unit members and Series A-1 Unit members will participate in remaining distributions according to their Upside Sharing Percentages (as defined in the New LLC Agreement).

Additionally, the Transaction Agreement provides that Magnum Hunter will sell to MSI in a second closing, that is expected to occur in mid-January 2015, a portion of its Eureka Hunter Holdings Series A-1 Common Units, which, assuming completion of the full amount of additional capital contributions expected to be made by MSI, would constitute approximately 6.5% of the total common equity interests in Eureka Hunter. Any Series A-1 Common Units purchased by MSI from the Company under a second closing will convert immediately into Series A-2 Units. The purchase price of such additional equity interests is expected to be approximately $65 million. Such closing, together with follow on capital contributions expected to be made by MSI in 2014, will result in Magnum Hunter and MSI owning approximately equal equity interests in Eureka Hunter which collectively will constitute an approximate 98% equity interest in Eureka Hunter.

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Amendment to Senior Credit Facility

On May 6, 2014, the Company executed an amendment to the Third Amended and Restated Credit Agreement, dated as of December 13, 2013 (the "Credit Agreement"), by and among the Company, as borrower, the guarantors party thereto, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto. With the execution of the amendment, the Company's borrowing base under the Credit Agreement was increased from $232.5 million to $325.0 million in connection with the regular semi‑annual redetermination of the borrowing base derived from the Company’s proved crude oil and natural gas reserves. The amendment also provided for required reductions in the borrowing base upon sale of certain specified assets, and modified other terms including certain financial covenants. As of September 30, 2014, the borrowing base had been reduced to $265.0 million as a result of the sale of WHI Canada and the issuance of equity, as contemplated in the amendment.

On October 22, 2014, the Company executed a New Credit Agreement by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto. On October 22, 2014, the Company also closed on a new Second Lien Term Loan Agreement by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto. The proceeds from the New Credit Agreement and the Second Lien Term Loan Agreement were used, in part, to refinance the Company's existing revolving credit facility.

The New Credit Agreement consists of a $50 million senior secured first lien reserve-based revolving credit facility, maturing four years after the closing date, while the Second Lien Term Loan Agreement consists of a $340 million senior secured second lien term loan, maturing five years after the closing date. Subject to certain exceptions, the obligations of the Company under the New Credit Agreement and the Second Lien Term Loan Agreement are secured by substantially all of the assets of the Company and its restricted subsidiaries. Proceeds from the new term loan were used to repay 100% of the outstanding borrowings under the Company's prior revolving credit facility (approximately $241 million at the date of closing), to pay fees and expenses associated with the transactions, to fund operations in the Marcellus and Utica Shale plays of West Virginia and Ohio, and for general corporate purposes.

Ormet Asset Purchase Agreement

In June 2014, we executed an Asset Purchase Agreement ("Ormet Asset Purchase Agreement") to acquire mineral interests from Ormet Corporation in approximately 1,700 net acres, consisting of 1,375 net acres in Monroe County, Ohio and 325 net acres in Wetzel County, West Virginia. Prior to the execution of this agreement, the Company held leasehold interests in a portion of the subject acreage, which only included leasehold rights to the Marcellus zone, and carried a 12.5% royalty on production to Ormet Corporation. On July 1, 2014, the U.S. Bankruptcy Court of Delaware gave approval to proceed with the transaction, and the Company closed on the transaction on July 24, 2014 for total cash consideration of approximately $22.7 million. Through this asset purchase, we acquired the mineral interests, including any royalty interests, in the underlying acreage, giving the Company 100% ownership of and rights to oil, natural gas, and other minerals located in or under and that may be produced from the property, at any depth.

MNW Lease Acquisitions

In June 2014, we resumed the acquisition of leasehold acreage from MNW Energy, LLC ("MNW") pursuant to the Asset Purchase Agreement (the "APA") entered into by Triad Hunter, LLC, our wholly-owned subsidiary ("Triad Hunter") and MNW in August 2013, which provided for the sale by MNW to Triad Hunter of a total of approximately 32,000 net leasehold acres located in Washington, Noble and Monroe Counties, Ohio, via staggered closings. Triad Hunter was forced to discontinue closings of this leasehold acreage under the APA earlier this year due to certain litigation filed against MNW and Triad Hunter by Dux Petroleum, LLC. The Company settled this litigation on May 28, 2014 and on June 5, 2014 resumed purchases pursuant to the APA, by acquiring certain oil and gas leases from MNW covering a total of approximately 12,200 gross (11,128 net) leasehold acres located in various areas in Washington and Monroe Counties, Ohio, for an aggregate purchase price of approximately $45.9 million (approximately $4,125 average per net leasehold acre). To date, under the APA, Triad Hunter has now acquired a total of approximately 17,000 net leasehold acres from MNW, or approximately 53% of the approximately 32,000 total net leasehold acres anticipated under the APA.

On October 28, 2014, Triad Hunter and MNW entered into the First Amendment to the Asset Purchase Agreement and Partial Release of Earn-Out Agreement (the "Amendment"). In connection with the asset purchase agreement with MNW dated August 12, 2013, Triad Hunter and MNW also entered into an earn-out agreement dated August 12, 2013 which provided for MNW to perform certain consulting services for Triad Hunter and to be paid for such services through the release by Triad Hunter of escrow funds being withheld from the purchase price at each closing under the asset purchase agreement. The Amendment terminates MNW's obligation to perform further consulting services under the earn-out agreement, provides for the disbursement of funds to MNW that have been withheld from closings to date, and amends the asset purchase agreement to end further withholdings of

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escrow funds from the purchase price at future closings. On October 30, 2014, Triad Hunter purchased approximately 5,160 net acres of undeveloped leasehold in the Utica Shale in Ohio for $20.6 million under its asset purchase agreement with MNW and also released $0.4 million in escrowed funds, for a total disbursement to MNW of approximately $21.0 million.

PRC Settlement

On July 24, 2014 the Company and PRC Williston executed a Settlement and Release Agreement ("the Settlement Agreement"). Per the terms of the Settlement Agreement, PRC Williston agreed to pay approximately $2.9 million in cash to Drawbridge Special Opportunities Fund LP. As a result of the Settlement Agreement, the Company, PRC Williston, and the Plaintiffs agreed to release each other from all claims, past, present or future, related to the dispute. In addition, with the execution of the Settlement Agreement, the parties agreed to terminate, in all respects, the Participation Agreements and that none of the parties would have any further rights or obligations thereunder. With the cash settlement payment and the termination of the Participation Agreements, the Company now has rights and claims to 100% of the equity interests in PRC Williston and its remaining assets and liabilities. The Settlement Agreement also resulted in the $5 million in restricted cash becoming unrestricted, with approximately $2.1 million net becoming available to the Company as of the settlement date.

Takeover Bid for Australian Company

On June 20, 2014, we lodged a Bidder’s Statement with the Australian Securities and Investments Commission, through our wholly owned subsidiary, Outback Shale Hunter Pty Ltd, an Australian company, to commence an off-market takeover offer (the "Offer") for Ambassador Oil and Gas Limited, an Australian company listed on the Australian Securities Exchange ("ASX") (ASX: AQO) ("Ambassador").  Pursuant to the Offer, we offered one share of our common stock, par value $0.01 per share, for every 23.6 ordinary (or common) shares of Ambassador.  On September 5, 2014, the Offer was closed. Ambassador shareholders holding 23,116 shares of Ambassador ordinary (or common) shares, representing less than 1% of the total number of Ambassador shares outstanding, accepted the Offer. In October 2014, the Company issued a total of 980 shares of its common stock to the Ambassador shareholders who accepted the Offer, valued at approximately $5,500 as of September 30, 2014.

Divestitures and Discontinued Operations

West Virginia Assets

On November 3, 2014, Triad Hunter closed on the sale of certain non-core working interests in oil and gas properties located primarily in Calhoun and Roane, Counties, West Virginia, for cash consideration of $1.2 million, subject to customary purchase price adjustments. The effective date of the sale is August 1, 2014.

North Dakota Assets

On September 30, 2014, we closed on the sale of certain non-core and non-operated working interests in oil and gas properties located in Divide County, North Dakota to a privately held company affiliated with Formation Energy L.P. The sales price for the transaction, which had an effective date of April 1, 2014, was $23.5 million in cash, subject to customary purchase price adjustments. At closing, these properties accounted for approximately 170 BOE of average daily production, net to the ownership interest sold to the buyer, and consisted of a non-operated working interest in approximately 34,600 gross (2,852 net) leasehold acres.

On October 15, 2014, we closed upon the sale of additional non-core, non-operated working interests in specific oil and gas properties, also located in Divide County, North Dakota, to an independent exploration and production company for a total sales price of $84.8 million in cash (before customary sales price adjustments). The effective date of the sale was August 1, 2014. At the time of closing, the properties sold accounted for approximately 720 BOE of average daily production, net to the ownership interest to be sold, and consisted of a non-operated working interest in approximately 105,661 gross (12,500 net) leasehold acres.

Eagle Ford Shale

On January 28, 2014, we closed on the sale of certain of our oil and natural gas properties and related assets in the Eagle Ford Shale in South Texas to New Standard Energy Texas, LLC ("NSE Texas"), a subsidiary of New Standard Energy Limited ("NSE"), an Australian Securities Exchange-listed Australian company. The divested properties and assets consisted primarily of leasehold acreage in Atascosa County, Texas and working interests in five horizontal wells, of which four were operated by the Company. We received cash consideration of $15.5 million, after customary purchase price adjustments, and 65,650,000 ordinary shares of NSE, with a fair value of approximately $5.7 million at September 30, 2014. The Company recognized a loss on the sale of these assets of $4.5 million. As a result of the sale, we own approximately 17% of the total outstanding common shares of NSE, and have the right to appoint, and have appointed, two designated representatives to NSE's board of directors.

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In connection with the sale, Shale Hunter, LLC ("Shale Hunter"), our wholly-owned subsidiary, entered into a transition services agreement with NSE Texas. The transition services agreement provides that, during a specified transition period, Shale Hunter will provide NSE Texas with certain transition services relating to the assets we sold to it for which Shale Hunter receives a monthly fee of $50,000.

WHI Canada and MHP

In September 2013, we adopted a plan to divest all of our interests in the operations of Magnum Hunter Production, Inc. ("MHP") and Williston Hunter Canada, Inc. ("WHI Canada"). On March 31, 2014, WHI Canada entered into a purchase and sale agreement (the "Alberta PSA") with BDJ Energy Inc., an Alberta corporation, to sell a portion of WHI Canada's oil and natural gas assets. Under the terms of the Alberta PSA, WHI Canada agreed to sell its right, title, and interest in certain oil and natural gas properties and assets located in Alberta, Canada, including operated working interests in approximately 1,910 gross (961 net) leasehold acres and three producing wells, for cash consideration of CAD $9.5 million (approximately US $8.7 million) in cash. The sale of these assets closed on April 10, 2014, with an effective date of January 1, 2014.

In addition, on April 21, 2014, we executed a definitive agreement to sell our 100% equity interest in WHI Canada to a private Canadian company for a purchase price of CAD $75.0 million (approximately US $68.8 million) in cash, subject to customary purchase price adjustments, with an effective date of March 1, 2014. WHI Canada's assets consist primarily of oil and natural gas properties located in the Tableland Field in Saskatchewan, Canada, and included 52,520 gross (49,470 net) acres with 84 gross wells producing approximately 630 Boe/d of current net production. The sale of our 100% equity interest in WHI Canada closed on May 12, 2014.

During the second and third quarters, we were engaged in sales discussions of MHP with a number of prospective purchasers and actively marketed MHP to be sold. However, in late September 2014, we made a decision to withdraw our plans to divest of MHP to further evaluate upside opportunities underlying the acreage in which MHP has leasehold rights or mineral interest rights held in fee. As a result, on September 30, 2014, the Company had ceased all marketing efforts for MHP.

As of September 30, 2014, the results of operations of MHP have been included in our results from continuing operations for all periods presented and MHP's assets have been reclassified as assets held for use as of September 30, 2014 in these interim consolidated financial statements. The Company had previously reported the results of MHP's operations as a component of discontinued operations in our consolidated financial statements and MHP's assets and liabilities were reflected as assets and liabilities held for sale. In connection with this reassessment, we recorded an additional impairment on MHP in the amount of $18.9 million to write individual assets down to the lesser of their fair value and net book value as of September 30, 2014. We also recorded an additional $1.7 million in depreciation expense for other fixed assets where their fair value was in excess of book value adjusted for depreciation that would have been recognized had the assets been held and used.

Equity Financing

During the nine-month period ended September 30, 2014, we raised cash in the total amount of $200.2 million in net proceeds after offering discounts, commissions and placement fees, but before other offering expenses. These capital market and equity transactions included:

• $149.7 million in net proceeds from the issuance of 21,428,580 shares of our common stock and warrants to purchase up to an aggregate of 2,142,858 shares of common stock in a private placement;

• $28.9 million in net proceeds from the issuance of 4,300,000 shares of our common stock in a private placement at a price of $7.00 per share;

• $12.0 million in net proceeds from issuances of Eureka Hunter Holdings Series A Preferred Units; and

• $9.6 million in net proceeds from the issuance of 2,355,000 shares of our common stock upon exercise of stock options.

Sale of Class A Common Units of Eureka Hunter Holdings

On July 1, 2014, the Company funded and closed on the purchase of 537,209 additional Class A Common Units in Eureka Hunter Holdings for cash of $10.7 million, increasing the Company’s ownership in Eureka Hunter Holdings to 59.1%. On July 14, 2014, the board of directors of Eureka Hunter Holdings approved the sale of up to 1.0 million additional Class A Common Units of Eureka Hunter Holdings to the Company and Ridgeline in proportion to their ownership interests, at $20.00 par, for total aggregate proceeds of $20 million. On July 18, 2014, the Company funded and closed on the purchase of its pro rata share, 590,976 Class A Common Units, for cash of $11.8 million. On July 29, 2014, Ridgeline exercised its pre-emptive right to purchase its proportionate share, 409,024 Class A Common Units, for total gross cash proceeds of $8.2 million. Ridgeline funded and closed on the purchase of its units on August 1, 2014.

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Early Termination of Eureka Hunter Pipeline Term Loan and Revolving Credit Facility

In March 2014, our majority-owned subsidiary, Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), entered into a new secured revolving credit agreement and facility with a new group of lenders (the "Eureka Hunter Pipeline Credit Agreement"), which has an aggregate commitment of $117.0 million, with a potential to increase the aggregate commitment up to $150.0 million. Initial proceeds from the Eureka Hunter Pipeline Credit Agreement were used to extinguish its two credit agreements with SunTrust Bank and Pennant Park. We incurred a prepayment penalty of $2.2 million in connection with the early termination of the SunTrust Bank and Pennant Park credit agreements, and wrote off approximately $2.7 million in unamortized deferred finance costs associated with those credit agreements. As of September 30, 2014, Eureka Hunter Pipeline had borrowed $80.0 million under the Eureka Hunter Pipeline Credit Agreement.

Consolidated Class Action Securities Case

In late 2013, certain class action cases that remained outstanding against the Company were consolidated (the "Securities Case") in the United States District Court for the Southern District of New York. The complaints in the Securities Case alleged that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company’s internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (which was filed by the Company with the SEC in June 2013), the dismissal of the Company’s previous independent registered accounting firm, and other matters. The complaints demanded that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company’s stock price between February 22, 2013 and April 22, 2013.

On June 23, 2014, the United States District Court for the Southern District of New York issued an opinion and order granting the Company’s and the individual defendants’ motion to dismiss the Securities Case and, accordingly, the Securities Case has now been dismissed.  The plaintiffs have appealed the decision to the U.S. Court of Appeals for the Second Circuit.

Seminole Settlement

In January 2014, we entered into an Omnibus Settlement Agreement and Release (the "Settlement Agreement") with Seminole Energy Services, LLC and certain of its affiliates (collectively, "Seminole"). In connection with and pursuant to the terms of the Settlement Agreement, the Company and Seminole agreed to release and discharge each other from all claims and causes of action alleged in, arising from or related to certain legal proceedings they had filed against each other and to terminate or amend certain existing agreements and enter into certain new, related agreements effective immediately prior to year-end on December 31, 2013 (collectively, the "Revised Agreements").

By entering into the Revised Agreements, we restructured our existing agreements with Seminole as follows:

• we obtained a reduction in the gas gathering rates that we pay for natural gas owned or controlled by us gathered on the Stone Mountain Gathering System located primarily in Tennessee and Kentucky which is owned by Seminole;

• together with Seminole, we are constructing an enhancement of the gas processing plant located near Rogersville, Tennessee (which we co-own with Seminole) (the "Rogersville Plant"), designed to recover less ethane and more propane from the natural gas processed at the Rogersville Plant;

• the parties agreed to reduce and extend the contractual horizontal well drilling obligations we owed to Seminole;

• the parties agreed to modify (i) the natural gas processing rates that we pay for processing natural gas at the Rogersville Plant, (ii) our allocation of NGL recovered from gas processed at the Rogersville Plant, (iii) our allocation of the costs of blend stock necessary to blend with the NGL produced from the Rogersville Plant, and (iv) certain deductions to the NGL purchase price that we pay Seminole for the Company's NGL produced from the Rogersville Plant; and

• we purchased Seminole's 50% interest in a natural gas gathering trunk line and treatment facility located in southwestern Muhlenberg County, Kentucky, which had previously been owned equally by Seminole and the Company, for $3.2 million.

As a result of the restructuring effected by the Settlement Agreement, the Company has been realizing operational savings, certain components of which savings will continue and increase over time, depending on the timing of implementation or completion of certain of the benefits provided to the Company under the Revised Agreements.

The Company's drilling obligation to Seminole, which required the Company to drill and complete four wells in Southern Appalachia, expired on June 30, 2014, and, pursuant to the Settlement Agreement, the Company paid Seminole $450,000 as a result of the Company's decision not to drill two of the required four wells.

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Loan Agreement

In January 2014, our wholly-owned subsidiary, Alpha Hunter Drilling, LLC, entered into a master loan and security agreement with CIT Finance LLC pursuant to which Alpha Hunter Drilling borrowed $5.6 million at an annual interest rate of 7.94%. Alpha Hunter Drilling used the proceeds of the loan to purchase equipment. The term of the loan is forty-eight months. The loan is collateralized by field equipment, and Magnum Hunter is a guarantor of the loan.

Refinancing of MHP Note Payable

Effective September 30, 2014, MHP refinanced its $3.8 million term loan with Traditional Bank, Inc. that was due to mature in early 2015.  The new loan is collateralized by an office building owned by MHP and carried an initial principal balance of $3.8 million at an interest rate of 4.875% with a maturity date of September 30, 2024.

Magnum Hunter Marketing Revenues

As a result of the substantial increase in their production of natural gas and other factors, in June 2014, JayBee Oil & Gas ("Jaybee"), the primary unaffiliated customer of Magnum Hunter Marketing ("MHM"), informed MHM that, effective July 1, 2014, it would be marketing all of its natural gas production previously marketed by MHM. MHM realized revenues from sales of natural gas purchased from Jaybee for the three and nine months ended September 30, 2014 of $0.4 million and $59.5 million, respectively. The gross margin realized through the marketing of Jaybee’s natural gas was approximately $22,000 and $0.2 million for the three and nine months ended September 30, 2014. Realized revenues from sales of natural gas purchased from Jaybee for the three and nine months ended September 30, 2013 was $7.7 million and $27.9 million, respectively. The gross margin realized through the marketing of Jaybee’s natural gas was approximately $0.9 million and $(9,000) for the three and nine months ended September 30, 2013. Absent new marketing agreements, MHM’s revenues from unaffiliated customers, and related costs, will continue to be substantially lower in the fourth quarter of 2014.

Oil, Natural Gas, and NGL Prices

During the third quarter of 2014, natural gas prices continued to decline due to mild weather and increases in overall production from the shale plays. The basis differential in Appalachia has widened against NYMEX during 2014. During the third quarter of 2014, the price realized per MMBtu by MHM through its marketing activities decreased compared to the prior quarter. If prices continue to decline as a result of increased supply without sufficient takeaway capacity for this region, this could impact the level of natural gas that companies are willing to produce until additional takeaway capacity becomes available.

During the three months ended September 30, 2014, our realized prices declined compared to the three month period ended June 30, 2014. These declines are consistent with overall declines in commodity markets in the United States. The table below shows the impact that volatility in the oil and natural gas markets has had on our realized prices over the past nine months.

			Average Prices (U.S. Dollars)
	Year Ended		Three Months Ended						Change from June 30, 2014 to September 30, 2014
	December 31, 2013		March 31, 2014		June 30, 2014		September 30, 2014		$			%
Oil (per Bbl)	$	89.79	$	82.89	$	97.02	$	90.55	$	(6.47	)	(7	)%
Natural gas (per Mcf)	$	4.04	$	5.60	$	5.20	$	3.43	$	(1.77	)	(34	)%
NGL (per BOE)	$	50.35	$	58.75	$	58.08	$	41.29	$	(16.79	)	(29	)%

Operational Update - Third Quarter 2014

During the three-month period ended September 30, 2014, we continued executing upon a capital intensive plan for the development and exploitation of our oil and natural gas assets in the U.S. Upstream segment with a focus on our shale resource plays in the Marcellus and Utica Shales. Concurrent with that development our Midstream segment, comprised primarily of our majority-owned subsidiary Eureka Hunter Pipeline, LLC, continued rapid expansion related to key growth opportunities for its natural gas gathering pipeline and related assets and increased the utilization of its gathering systems through tie-in of new Company and third-party wells and other third party throughput volume deliveries. The following section provides a summary of key developments in these business segments during the third quarter of 2014.

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U.S. Upstream

Operated Properties

Marcellus Shale

WVDNR Pad - The WVDNR #1207, #1208, and #1209 wells (~100% working interest), located in Wetzel County, West Virginia, began flowing to sales on April 2, 2014 and were subsequently shut-in on May 31, 2014 to prepare the WVDNR pad for drilling 4 additional down-dip laterals off the existing pad. For the 7-day period prior to shut-in, the WVDNR #1207, #1208, and #1209 had a combined average daily production (net) of approximately 1,575 BOE (9,450 MCF).

The WVDNR #1410, #1411, #1412 (~100% working interest) have been drilled and cased with an approximate true vertical depth of 7,500 feet. At September 30, 2014, we were drilling the WVDNR #1413 lateral, with approximately 3,000 feet remaining. The anticipated lateral lengths are 3,930 feet, 4,630 feet, 5,325 feet and 5,840 feet, for the WVDNR #1410, #1411, #1412, and #1413, respectfully. We anticipate that all the WVDNR wells will be online and flowing to sales through the Eureka Hunter Pipeline gathering system in December 2014.

Ormet Pad - Following the drilling and completion of the Ormet 1-9H, 2-9H, and 3-9H wells (~100% working interest) during the first quarter of 2014, these three wells located in Monroe County, Ohio began flowing to sales through the Eureka Hunter Pipeline gathering system during the second week of May 2014. The three wells were producing oil and natural gas (net) of an aggregate of approximately 1,250 BOE per day (7,500 MCF per day) at September 30, 2014. These wells were drilled and cased to an average vertical depth of 5,900 feet with a 3,900 foot average horizontal lateral. In July 2014, we purchased the mineral interest rights in fee, resulting in an approximate 100% net revenue interest to Triad Hunter in these three wells.

Stalder Pad - Our first Marcellus Shale well drilled (50 % working interest) on the Stalder Pad in Monroe County, Ohio, the Stalder #2MH, was drilled and completed in late March 2014. The Stalder #2MH was drilled and cased to a true vertical depth of 6,070 feet with a 5,474 foot horizontal lateral, and was fracture stimulated with 28 stages. The Stalder #2MH well peak test rates during flow-back were 3,707 MMcf of natural gas per day and 312 Bbl of condensate per day. This well is currently shut-in as we are drilling three additional Utica wells on the Stalder Pad.

Everett Weese Unit - We have drilled and completed three Marcellus wells (~100% working interest) on the Everett Weese unit, located in Tyler County, West Virginia. We shut-in these three wells, the Everett Weese #1107, #1108, and #1109, in mid-July 2014 in preparation for drilling and completing two additional Marcellus wells on the Everett Weese unit. As of September 30, 2014, we had spud the Everett Weese #1414 and #1415 wells and drilled them to kick-off point. Upon drilling and completing these two additional Marcellus wells, all wells on the Everett Weese unit will remain shut-in pending receipt of the necessary air quality permits from the State of West Virginia, which would then allow us to flow production to sales.

Stewart Winland Pad - We drilled and cased three ~100% owned Marcellus Shale wells, the Stewart Winland #1301M, #1302M, and #1303M, in Tyler County, West Virginia, to an average true vertical depth of 6,150 feet with a 5,750 foot average horizontal lateral. These wells have all been fracture stimulated and were ready for sales as of September 30, 2014. The Company is currently waiting on air quality permits from the State of West Virginia to begin flowing these Marcellus wells to sales. These wells were drilled and cased to true vertical depths with horizontal laterals as follows:

Well	True Vertical Depth	Lateral Length	Frac Stages
	(in feet)
Stewart Winland #1301M	6,155	5,762	27
Stewart Winland #1302M	6,147	5,676	29
Stewart Winland #1303M	6,149	5,762	29

Utica Shale

Stewart Winland Pad - The Stewart Winland #1300U (100% working interest), the Company's first Utica Shale well drilled and completed in the State of West Virginia and the most southeastern well in the entire play, was drilled to a true vertical depth of 10,825 feet with a 5,289 foot horizontal lateral, and was successfully fraced with 22 stages. The Stewart Winland #1300 well’s targeted Utica/Point Pleasant formation is approximately 350 feet deeper than that same formation to which the Company’s first Utica Shale dry gas well, the Stalder #3UH in Monroe County, Ohio, was drilled. The Stewart Winland tested at a peak rate of 46.5 MMCF of natural gas per day (~7,750 BOE per day) on an adjustable rate

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choke with 7,810 psi FCP. The Stewart Winland #1300U is currently shut-in pending the receipt of necessary air quality permits from the State of West Virginia.

Stalder Pad - We drilled and completed our first dry gas well, the Stalder #3UH (47% working interest), located on the Stalder Pad in Monroe County, Ohio, and placed it on production in February 2014. Initial flow tests peaked at a rate of 32.5MMcf (approximately 5.4MBoe) of natural gas per day on an adjustable rate choke with 4,300 psi FCP. The Stalder #3UH was drilled to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, and was successfully fracture stimulated with 20 stages. The well is currently shut-in as we are drilling three additional Utica wells on the Stalder Pad.

We are currently drilling the Stalder #6UH, #7UH and #8UH (~47% working interest). The estimated true vertical depth for the Utica laterals is 10,650 feet. The proposed measured depth and lateral lengths for each well are as follows:

Well	Measured Depth	Lateral Length
	(in feet)
Stalder #6UH	17,000	6,000
Stalder #7UH	17,100	6,500
Stalder #8UH	18,100	6,500

We have drilled and cased the intermediate section on the Stalder #8UH and #7UH. The Stalder #6UH has been drilled and cased to target depth, with a true vertical depth of approximately 10,680 feet and a lateral length of approximately 6,000 feet. We are now building the curve on the Stalder #7UH, and intermediate 9 5/8" casing has been set on the Stalder #8UH. We expect to report initial production rates from these three new Utica Shale wells in December 2014.

Ormet 15 Pad - The second Ormet Pad located in Monroe County, Ohio has 5 down-dip Marcellus and 4 down-dip Utica laterals planned. Initial plans are to drill three of the four Utica laterals. We have commenced drilling the Ormet #8-15UH, #9-15UH and #10-15UH (~100% working interest). The estimated true vertical depth for the Utica laterals is 11,100 feet. Following the purchase by Triad Hunter of the mineral interests held in fee in approximately 1,700 net mineral acres from Ormet Corporation in July 2014, which purchase included the mineral interests underlying this pad, the Company's net revenue interest has increased to almost 100%.

The proposed measured depth and lateral lengths for each well are as follows:

Well	Measured Depth	Lateral Length
	(in feet)
Ormet #8-15UH	15,800	4,600
Ormet #9-15UH	16,300	4,700
Ormet #10-15UH	16,900	4,800

In the process of drilling the first of three Utica laterals, the Company encountered a zone of increased pressure and porosity at approximately 1,200 feet into the lateral section. We have run 5 ½” casing with a retrievable packer and are in the process of open hole testing the well. Our plan for the remainder of the Utica laterals will be dependent upon the flow test results from this first Ormet #8-15UH well.

Farley Pad - We drilled and cased the Farley #1306H, on the Farley Pad in Washington County, Ohio, to a true vertical depth of 7,850 feet with a 6,313 foot horizontal lateral. We have also drilled and cased the Farley #1304H well to a true vertical depth of 7,914 feet with a 5,400 foot horizontal lateral. These two wells, along with the Farley #1305H, drilled in 2013, are still awaiting completion operations pending pipeline completion. We have redeployed our resources towards the Stalder and Stewart Winland wells, and expect to begin fracture stimulation of the new Utica wells, the Farley #1306H and #1304H, in 2015.

Non-operated Properties

Mills Wetzel - Stone Energy, which owns a 50% working interest, has been building out the production facility on Pad 3 that includes 8 Marcellus laterals. Triad Hunter has a 50% working interest in the Mills Wetzel wells. In early August 2014, several of the Mills Wetzel wells began flowing through to production at approximately 1,400 BOE/d (8,418 Mcf/d) in the aggregate.

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Merlin Unit - The Merlin #10PPH Utica lateral is being drilled and operated by EdgeMarc Energy. Triad Hunter owns a 13.56% working interest in the Merlin #10PPH. The Merlin #10PPH is located in Washington County, Ohio, approximately 5.1 miles southeast of Triad Hunter’s Farley Pad. The Merlin #10PPH has an estimated true vertical depth of 8,050 feet and estimated lateral length of 7,200 feet. The estimated measured depth is 15,800 feet. The operator finished drilling and casing the well in August 2014. Fracture stimulation is expected to begin in early November 2014.

Williston Basin/Bakken Shale

During the first nine months of 2014, we participated in the spudding of 22 gross (5.0 net) wells and the completion of 26 gross (6.8 net) wells in Divide County, North Dakota. Twelve of the completed wells utilized plug and perforation technology.

A third-party has been engaged to gather and transport oil from certain of our non-operated wells in Divide County to the Colt Hub in Epping, North Dakota to eliminate trucking costs and minimize downtime during spring break-up. We expect that approximately 51 existing wells and 18 wells scheduled to be drilled under the operator’s 2014 drilling program will be connected to the gathering system, which is expected to be fully operational by December 2014. A truck terminal will also be constructed and connected to the gathering system to minimize oil hauling costs from wells not connected to the gathering system. On the Bonneville pad, all four receipt points on the north lateral and three receipt points on the south lateral are operational. Construction is continuing on the south lateral tie-ins. Construction on the truck terminal began in October 2014. All of the equipment has been ordered and delivery is expected starting in the first week of December 2014. The facility is expected to be operational in January 2015.

At Tableland, Saskatchewan, construction of the pipeline from the Steppe Battery in Saskatchewan to the Oneok connection in North Dakota was completed in early September. Approximately 600 Mcf/d of associated gas started producing and will be applied towards our Oneok volume commitment.

As of September 30, 2014, our operators in Divide County have tied in approximately 202 gross wells into the Oneok gas gathering system in Divide County and production and revenues from the gathering of associated gas from the tied-in wells are growing monthly. Approximately 70% of the wells have been electrified.

U.S. Upstream Drilling and Capital Expenditures

In addition to the drilling and completion activities on our non-operated properties in the Williston Basin and Bakken Shale discussed above, during the three-month period ended September 30, 2014, the Company drilled a total of 5 gross (3.5 net) wells, and completed 4 wells in which we own a 100% interest in the Appalachian Basin.

During the third quarter of 2014, we incurred related capital expenditures of $109.9 million comprised of $93.7 million in proved property additions, and $16.2 million in leasehold acquisitions.

Midstream

Eureka Hunter Pipeline

Eureka Hunter Pipeline recently achieved a peak throughput rate of 316,500 MMBtu per day in September 2014. During the third quarter of 2014, Eureka Hunter’s gas gathering pipeline system averaged 223,708 MMBtu per day. During September 2014, Triad Hunter produced approximately 29% of the volumes that flowed through the Eureka Hunter Pipeline system.

Eureka Hunter Pipeline shippers are currently limited to capacity through the Mobley gas processing facility in West Virginia and downstream on Equitrans. A fourth Mobley plant is expected to come online in December 2014 adding 200,000 Mcf of processing, and Equitrans is adding compression to further expand capacity downstream of Mobley. Eureka Hunter Pipeline is also adding additional takeaway capacity at Mobley with a new residue line under construction to TCO (Colombia Gas). This new residue line will provide a competitive advantage for producers previously limited to one takeaway pipeline and its related gas markets.

Eureka Hunter Pipeline expects to add significant throughput volumes from a combination of Triad Hunter's new wells mentioned above and other third parties' production during the remainder of 2014. Much of the added throughput will be dry gas from the Utica Shale being delivered into various interstate pipeline connections planned in or near Monroe County, Ohio, which includes Dominion, REX and TETCO. The initiation of dry gas from the Utica Shale will mark a

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significant milestone for Eureka Hunter Pipeline as the system will be flowing dry gas north and will continue to move wet gas from the Marcellus Shale east to Mobley.

Eureka Hunter Pipeline has plans to add an interconnect into Natrium (Blue Racer Midstream) to increase its Marcellus Shale wet deliveries on the system to 400 MMcf/d plus, expected to be completed by year-end.

Eureka Hunter Pipeline continues to construct pipeline on five distinct project fronts, which include the Crescent Line, the REX-TEX, the Ormet Extension, the Stewart Winland, and the Mobley-TCO. These projects are in varying stages of construction and completion, utilizing three different construction crews. With the completion of expansion projects currently under construction, the Company expects the Eureka Hunter system will have a throughput capacity of approximately 1.5 Bcf/d by the end of 2014.

Eureka Hunter Pipeline has recently completed its mainline compression effort and has lowered line pressures by approximately 150-200 psi across the system. This new compression will help to effect steady deliveries into the Mobley facility. The reduced line pressure also helps producers move gas more easily into the Eureka Hunter Pipeline system.

Midstream Capital Expenditures

During the three-month period ended September 30, 2014, our Midstream segment incurred capital expenditures of $88.5 million. Capital expenditures for the Midstream segment exceeded the initial budget for 2014 as a result of certain pipeline projects which were accelerated to meet earlier than expected throughput demand from Triad Hunter and third party customers.

Oilfield Services

Alpha Hunter Drilling

We own and operate portable, trailer-mounted drilling rigs capable of drilling to depths of between 6,000 to 19,000 feet, which are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin. The drilling rigs are used primarily for our Appalachian Basin operations and to provide drilling services to third parties.

As of September 30, 2014, four of the Schramm T200XD drilling rigs were under contract to EQT in the Appalachian Basin area for the top-hole drilling of multiple wells through December 2015; one Schramm T200XD drilling rig was under contract through October 2014 to Eclipse Resources in the Appalachian Basin, until being released on October 4, 2014 and the rig was contracted to American Energy Partners on October 5, 2014 for a 5 well commitment; and our largest Schramm T500XD drilling rig was under contract to Triad Hunter for our Utica Shale drilling program. All these contracts, with the exception of one, are term contracts. Rigs deployed under contracts with non-affiliated companies were running on contracted daily rates of $12,500.

In June 2014, we executed a contract to purchase a new Schramm T500XD. We have made a down payment under this contract and expect the total price of the rig and related equipment to be approximately $17 million with delivery in the first quarter of 2015. We plan to use this rig in our drilling operations in the Utica Shale.

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Results of Operations

The following table sets forth summary information from continuing operations regarding oil, natural gas and NGL revenues, production, average product prices and average production costs and expenses for the three and nine months ended September 30, 2014 and 2013, respectively. As discussed in "Note 2 - Divestitures and Discontinued Operations", the results of operations have been adjusted to include MHP's results of operations in continuing operations for all periods presented. Current and prior periods have also been adjusted to exclude components classified as discontinued operations.

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2014		2013		2014		2013
Oil and natural gas revenue and production
Revenues (in thousands, U.S. Dollars)
Oil	$	34,495	$	40,471	$	111,354	$	103,545
Natural gas	18,247		12,417		74,031		41,145
NGL	9,768		6,173		36,862		12,082
Total oil and natural gas sales	$	62,510	$	59,061	$	222,247	$	156,772
Production
Oil (MBbl)	381		406		1,234		1,138
Natural gas (MMcf)	5,326		2,759		15,781		9,986
NGL (MBoe)	237		144		717		302
Total (MBoe)	1,505		1,010		4,581		3,105
Boe/d	16,361		10,977		16,778		11,372
Average prices (U.S. Dollars)
Oil (per Bbl)	$	90.55	$	99.69	$	90.27	$	90.95
Natural gas (per Mcf)	$	3.43	$	4.50	$	4.69	$	4.12
NGL (per Boe)	$	41.29	$	42.84	$	51.42	$	40.03
Total average price (per Boe)	$	41.53	$	58.48	$	48.52	$	50.50
Costs and expenses (per Boe)
Lease operating expense	$	16.26	$	19.39	$	14.11	$	15.68
Severance tax and marketing	$	4.09	$	5.50	$	4.11	$	4.18
Exploration expense	$	18.13	$	41.57	$	11.44	$	24.24
Impairment of proved oil and natural gas property	$	15.20	$	23.32	$	8.69	$	12.71
General and administrative expense (1)	$	12.79	$	23.67	$	12.23	$	20.51
Depletion, depreciation and accretion	$	24.16	$	28.84	$	22.21	$	25.81
Other segments (in thousands)
Natural gas transportation, gathering, processing and marketing revenues	$	10,285	$	12,545	$	90,461	$	42,854
Natural gas transportation, gathering, processing and marketing expenses	$	4,954	$	8,985	$	79,707	$	35,830
Oilfield services revenues	$	5,986	$	6,423	$	17,561	$	13,728
Oilfield services expenses	$	3,856	$	4,527	$	11,892	$	11,928

_________________________________

(1) General and administrative expense includes: (i) transaction and professional services expenses of $5.6 million ($3.71 Boe) for the three months ended September 30, 2014 and $6.9 million ($6.83 Boe) for the three months ended September 30, 2013, (ii) transaction and professional services expenses of $20.1 million ($4.39 Boe) for the nine months ended September 30, 2014 and $19.8 million ($6.39 Boe) the nine months ended September 30, 2013, (iii) non-cash stock compensation of $2.3 million ($1.53 Boe) for the three months ended September 30, 2014 and $3.1 million ($3.10 Boe) for the three months ended September 30, 2013, and (iv) non-cash stock compensation of $5.7 million ($1.24 Boe) for the nine months ended September 30, 2014 and $11.8 million ($3.81 Boe) for the nine months ended September 30, 2013.

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Three Months Ended September 30, 2014 and 2013

Oil and natural gas production. Production increased by 49.0%, or 495 MBoe, to 1,505 MBoe for the three months endedSeptember 30, 2014 compared to the three months endedSeptember 30, 2013. Our average daily production was 16,361 Boe/d during the 2014 period, representing an overall increase of 49.0%, or 5,384 Boe/d, compared to 10,977 Boe/d for the 2013 period. Natural gas production from the Appalachian Basin alone increased from 2,374 MMcf for the three months ended September 30, 2013 to 4,343 MMcf for the three months ended September 30, 2014; an increase of 83.0%. Production of natural gas and NGL's was favorable in the current quarter as a result of new Marcellus wells that began producing from the Collins, Spencer, Ormet, Stalder, and Mills Wetzel pads/units.

Oil and NGL production for the three months ended September 30, 2014 was 618 MBoe versus 550 MBoe for the three months ended September 30, 2013, an increase of 12.4%, primarily as a result of increased NGL production. The increase in NGL production in 2014 results from our Marcellus wells, which generally have a high liquid content. The additional Marcellus wells coming on production subsequent to September 30, 2013 resulted in NGL's being comparably higher in the current quarter.

Further, production of oil declined in 2014 as the result of our divestiture of non-core properties from the Williston/Bakken fields. Production from the Williston/Bakken fields contributed an additional 476 MBoe in oil production, producing from the Madison formation in North Dakota during the fourth quarter of 2013.

Total production for the three months ended September 30, 2014, on a Boe basis, was 41.0% oil and NGL and 59.0% natural gas compared to 54.5% oil and NGL and 45.5% natural gas for the same period in 2013.

Oil and natural gas sales. Oil and natural gas sales increased 5.8%, or $3.4 million, for the three months endedSeptember 30, 2014 to $62.5 million from $59.1 million for the three months endedSeptember 30, 2013. The increase in oil and natural gas sales primarily resulted from higher production volumes from our Marcellus wells and the tie-in of certain wells in the Williston/Bakken fields to the Oneok gas gathering system. Our total sales prices were impacted by declines in prices received for oil, natural gas, and NGL of 9.2%, 23.8% and 3.6%, respectively. Our natural gas sales in 2014 benefited from increased production from natural gas flowing to sales from our Collins, Spencer, Ormet, and Stewart Winland wells, which were not on production during the third quarter of 2013. Of the total increase in oil and natural gas sales for the 2014 period, $13.0 million was attributable to our increase in production, which was offset by a decrease of $9.6 million attributable to decreases in prices received. The prices we receive for our products are generally tied to commodity index prices.

Natural gas transportation, gathering, processing and marketing revenues. Revenue from midstream operations (which consist of Eureka Hunter Pipeline, TransTex Hunter, and Magnum Hunter Marketing operations) decreased by $2.3 million, or 18.0%, for the three months endedSeptember 30, 2014 to $10.3 million from $12.5 million for the three months endedSeptember 30, 2013. TransTex Hunter revenues decreased by $0.8 million. Eureka Hunter Pipeline revenues increased by $5.1 million as a result of new growth in third party customer contracts, pipeline extensions, and higher volumes of natural gas gathered from its existing customers. Eureka Hunter Pipeline increased throughput volumes by 196.1% or 14.2 million MMBtu to 21.5 million MMBtu for the three months ended September 30, 2014 from 7.3 million MMBtu for the three months ended September 30, 2013. Magnum Hunter Marketing revenues decreased by $6.6 million to $1.1 million during the three months ended September 30, 2014 from $7.7 million during the three months ended September 30, 2013. Magnum Hunter Marketing revenues decreased as a result of the decision made by Jaybee, a third party customer, to begin marketing their own natural gas, which had previously been marketed by Magnum Hunter Marketing on Jaybee's behalf.

Oilfield services revenue. Drilling services revenue decreased by 6.8%, or $0.4 million, for the three months endedSeptember 30, 2014 to $6.0 million from $6.4 million for the three months endedSeptember 30, 2013. This decrease was primarily attributable to the drilling of four wells for Triad Hunter. During the three months ended September 30, 2014, our drilling rig revenue days increased from 416 to 592 as compared to the three months ended September 30, 2013. For the three months ended September 30, 2014, the total effective equipment performance of our drilling rigs was 94%, and our rigs were 100% utilized.

Gain (loss) on sale of assets. We recorded a gain on sale of assets in operating expenses of $8.0 million for the three months ended September 30, 2014, primarily related to the sale of certain oil and natural gas properties in Divide County, North Dakota.

Lease operating expense. Our lease operating expenses ("LOE"), increased$4.9 million, or 25.0%, for the three months endedSeptember 30, 2014 to $24.5 million ($16.26 Boe) from $19.6 million ($19.39 Boe) for the three months endedSeptember 30, 2013. The fluctuation in LOE was comprised of an increase of $9.6 million attributable to increased production volumes, offset by a decrease of $4.7 million attributable to lower LOE/Boe costs. Of the decrease in LOE/Boe costs, $6.3 million and $4.2 million was due to lower recurring costs in the Appalachian and Williston Basins, respectively, and $0.5 million was due to lower non-

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recurring workover expenses in the Williston Basin. These decreases were partially offset by a $5.8 million increase in third party transportation costs for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013.

Severance taxes.  Our severance taxes increased$0.6 million, or 11.0%, for the three months endedSeptember 30, 2014, to $6.2 million from $5.6 million for the three months endedSeptember 30, 2013.  The increase in severance taxes was attributable primarily to the increase in our production and sales.  

Exploration.We record exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. We recorded $27.3 million of exploration expense for the three months ended September 30, 2014, compared to $42.0 million for the three months ended September 30, 2013. During the 2014 period, the Company's exploration expense was primarily attributable to $17.8 million of leasehold impairments relating to leases in the Williston Basin region and $9.1 million of leasehold impairments relating to leases in the Appalachian region that expired undrilled during the three months ended September 30, 2014 or are expected to expire and that the Company does not plan to develop. A portion of the exploration expense relating to leases in the Appalachian region relates to the assessment of MHP's carrying value upon reclassification into assets held for use and continuing operations as of September 30, 2014. The Company's exploration expense during the three months ended September 30, 2013 of $38.8 million primarily related to leases in the Williston Basin.

Impairment of proved oil and natural gas properties. Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows.

During the three months ended September 30, 2014, changes in oil and natural gas prices provided indications of possible impairment on two legacy fields that are unrelated to our current drilling and development plan. As a result of our assessment, we recorded impairment of proved oil and natural gas properties in continuing operations of $22.9 million during the three months ended September 30, 2014 to reduce the carrying value of these properties to their estimated fair values, a portion of which also relates to the assessment of MHP's carrying value upon reclassification into assets held for use and continuing operations as of September 30, 2014. During the three months ended September 30, 2013, we recorded impairment of proved oil and natural gas properties in the Appalachian Basin of $23.5 million. We calculated the estimated fair values using a discounted cash flow model. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Natural gas transportation, gathering, processing and marketing expenses. Expenses from the midstream operations decreased by $4.0 million, or 44.9%, for the three months endedSeptember 30, 2014 to $5.0 million from $9.0 million for the three months endedSeptember 30, 2013 due primarily to Magnum Hunter Marketing's decreased activities relating to the loss of the Jaybee marketing contract.

Oilfield services expenses.  Oilfield services expenses decreased by $0.7 million, or 14.8%, to $3.9 million for the three months endedSeptember 30, 2014 from $4.5 million for the three months endedSeptember 30, 2013.

Depletion, depreciation, amortization, and accretion. Our depletion, depreciation, amortization and accretion expense ("DD&A"), increased $7.2 million, or 24.9%, to $36.4 million for the three months endedSeptember 30, 2014, from $29.1 million for the three months endedSeptember 30, 2013, due to increases in accumulated costs from our capital expenditure and acquisition programs during 2013 and 2014, and increased production in 2014. Our DD&A/Boe decreased by $4.68, or 16.2%, to $24.16 Boe for the three months endedSeptember 30, 2014, compared to $28.84 Boe for the three months endedSeptember 30, 2013. The decrease in DD&A/Boe was primarily attributable to an increase in natural gas production from continuing operations. Natural gas wells generally have a lower rate on a Boe basis than oil and NGL. The Company's natural gas production increased significantly due to its drilling and completion activities in the Appalachian Basin.

General and administrative. Our general and administrative expenses ("G&A"), decreased $4.7 million, or 19.5%, to $19.3 million or $12.79 Boe for the three months endedSeptember 30, 2014 from $23.9 million or $23.67 Boe for the three months endedSeptember 30, 2013. G&A expenses decreased overall from 2013 mainly due to lower transaction and professional services expenses, as well as lower bad debt expense. Non-cash stock compensation expense decreased by $0.8 million, to approximately $2.3 million or $1.53 Boe for the three months endedSeptember 30, 2014 from $3.1 million or $3.10 Boe for the three months endedSeptember 30, 2013.

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Interest expense. Our interest expense, net of interest income, increased by 14.8%, to $18.1 million from $15.7 million for the three months endedSeptember 30, 2014, compared to the three months endedSeptember 30, 2013. A higher average debt level during the third quarter of 2014 compared to the 2013 period accounted for $2.4 million of the increase, which was partially offset by a decrease of $0.1 million due to lower amortization and write-off of deferred financing costs. Interest expense was offset by capitalized interest of $0.7 million and $0.6 million during the three months endedSeptember 30, 2014 and 2013, respectively. We capitalize interest on projects lasting six months or longer.

Commodity and financial derivative activities. Our commodity and financial derivative activity resulted in a net loss of $49.6 million for the quarter ended September 30, 2014, compared to a net loss of $29.6 million for the quarter ended September 30, 2013. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:

	Three Months Ended   September 30,
	2014			2013
	(in thousands)
Commodity derivatives
Realized gain (loss) on settled transactions	$	477		$	(6,582	)
Unrealized gain (loss) on open contracts	8,019			(7,629		)
Total commodity derivatives	8,496			(14,211		)
Financial derivatives
Unrealized loss on open contracts	(58,132		)	(15,342		)
Net loss	$	(49,636	)	$	(29,553	)

We do not designate our derivative instruments as cash-flow hedges.

At September 30, 2014, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Eureka Hunter Holdings Series A Preferred Units. This embedded derivative instrument resulted in unrealized losses of $57.9 million and $15.4 million in the three months endedSeptember 30, 2014 and 2013, respectively. The change in unrealized loss was driven primarily by increases in total enterprise value and a reduction in the expected term of the conversion feature.

The change in expected term is the result of management’s assessment of the likely time horizon for which a liquidity event will occur resulting in conversion of the Eureka Hunter Holdings Series A Preferred Shares to Class A Common Units of Eureka Hunter Holdings.  Multiple factors were considered in determining the expected term, which led to using a probability weighted average of the potential timing of a liquidity event.  The recent approval of the Eureka Hunter Holdings LLC Management Incentive Compensation Plan, the payout under which is linked to a defined liquidity event, led to management’s assessment of the potential timing of a liquidity event.  The weighting was based on the current market for master limited partnership initial public offerings.  These factors impacted our assessment of the expected term, and resulted in a shorter time horizon input for purposes of the fair value calculation that was based on the weighted average of potential expected liquidity events.

The change in total enterprise value was also impacted significantly by the recent agreement reached between MSI and Ridgeline for MSI to purchase all of Ridgeline's equity interests in Eureka Hunter Holdings, and which closed in October 2014. Management factored the purchase price of that transaction into its determination of total enterprise value as of September 30, 2014. As a result of this undertaking, the total enterprise value of Eureka Hunter Holdings at September 30, 2014 increased to approximately $929.7 million compared to $544 million at September 30, 2013.

Also at September 30, 2014, the Company has recognized an asset for an embedded derivative related to a convertible security, due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. An unrealized loss of $234,000 and an unrealized gain of $26,000 are recorded for this embedded derivative instrument in the three months endedSeptember 30, 2014 and 2013, respectively. Both derivative instruments originated in 2012 and the derivative instruments have resulted in no cash outlays as of September 30, 2014.

We record our open derivative instruments at fair value on our consolidated balance sheets as either current or long-term assets or liabilities, depending on the timing of expected cash flows. We record all realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled "Gain (loss) on derivative contracts, net".

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Income tax benefit.  We were in a net operating loss position as of September 30, 2014, and have a full valuation allowance on all deferred tax assets. As a result, we did not recognize an income tax benefit on our September 30, 2014 net loss, whereas we recognized a benefit of $0.6 million for the three months ended September 30, 2013 due to the gain on sale of discontinued operations which allowed us to utilize a portion of the deferred tax asset otherwise reserved against.

Income (loss) from discontinued operations, net of tax. In September 2013, the Company adopted a plan to divest all of its interests in WHI Canada. The Company reclassified the associated assets and liabilities to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented. The Company closed on the sale of its interests in WHI Canada during the second quarter of 2014.

We recognized loss from discontinued operations of $75.6 million for the three months ended September 30, 2013, compared to none during the three months ended September 30, 2014. The following table summarizes the loss from discontinued operations for the periods indicated:

	Three months ended September 30,
	2014		2013
	(in thousands)
Eagle Ford Hunter	$	—	$	(716	)
Williston Hunter Canada	—		(74,857		)
	$	—	$	(75,573	)

Gain (loss) on disposal of discontinued operations, net of tax. Loss on disposal of discontinued operations was $0.3 million and $69.5 million for the three months ended September 30, 2014 and 2013, respectively. The following table summarizes the loss on disposal of discontinued operations for the periods indicated:

	Three months ended September 30,
	2014			2013
	(in thousands)
Eagle Ford Hunter	$	(258	)	$	(13,880	)
Williston Hunter Canada	—			(55,641		)
	$	(258	)	$	(69,521	)

Net income attributable to non-controlling interest.  Net loss attributable to non-controlling interest was approximately $2.8 million for the three months ended September 30, 2014, which represents 1.6% of the net income or loss attributable to our majority-owned subsidiary, Eureka Hunter Holdings. Net loss attributable to non-controlling interest of $0.7 million for the three months ended September 30, 2013 represents 12.5% of the net income or loss of our subsidiary, PRC Williston, and 2.0% of the net income or loss attributable to our majority-owned subsidiary, Eureka Hunter Holdings. 

On December 30, 2013, PRC Williston, in which the Company owned an 87.5% interest as of December 31, 2013, sold substantially all of its assets. On July 24, 2014, the Company executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, the Company now owns 100% of the equity interests in PRC Williston and has all rights and claims its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston's equity reflected in the consolidated financial statements as of September 30, 2014.

Dividends on preferred stock. Total dividends on our preferred stock were approximately $15.5 million for the three months endedSeptember 30, 2014 compared to $14.4 million for the 2013 period.

The Series C Preferred Stock had a stated value of $100.0 million at September 30, 2014 and December 31, 2013, and carries a cumulative dividend rate of 10.25% per annum. The Series D Preferred Stock had a stated value of $221.2 million and $221.2 million at September 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million and $95.1 million as of September 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Eureka Hunter Holdings Series A Preferred Units had a liquidation preference of $271.4 million and $200.6 million as of September 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum.

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Nine Months Ended September 30, 2014 and 2013

Oil and natural gas production.  Production increased by 47.5%, or 1,476 MBoe, to 4,581 MBoe for the nine months ended September 30, 2014, compared to 3,105 MBoe for the nine months ended September 30, 2013. Our average daily production was 16,778 Boe/d during the 2014 period, representing an overall increase of 47.5%, or 5,406 Boe/d, compared to 11,372 Boe/d for the 2013 period. Natural gas production from the Appalachian Basin alone increased from 7,098 MMcf for the nine months ended September 30, 2013 to 13,005 MMcf for the nine months ended September 30, 2014, an increase of 83.2%. Production of natural gas and NGL's was favorable during the 2014 period as a result of new Marcellus wells that began producing from the Collins, Spencer, Ormet, Stalder, and Mills Wetzel pads/units. Oil and NGL production for the nine months ended September 30, 2014 was 1,951 MBoe versus 1,440 MBoe for the nine months ended September 30, 2013, an increase of 35.5%, primarily as a result of increased NGL production. The increase in NGL production in 2014 results from our Marcellus wells, which have a high liquid content. The additional Marcellus wells coming on production subsequent to September 30, 2013 resulted in NGL's being comparably higher in the current quarter.

Further, production of oil declined in 2014 as the result of our divestiture of non-core properties from the Williston/Bakken fields. Production from the Williston/Bakken fields contributed an additional 148,507 MBoe in oil production, producing from the Madison formation in North Dakota during the fourth quarter of 2013.

Total production for the nine months ended September 30, 2014, on a Boe basis, was 42.6% oil and NGL and 57.4% natural gas compared to 46.4% oil and 53.6% natural gas for the same period in 2013. 

Oil and natural gas sales.  Oil and natural gas sales increased$65.5 million, or 41.8% for the nine months ended September 30, 2014, to $222.2 million from $156.8 million for the nine months ended September 30, 2013.  The increase in oil and natural gas sales primarily resulted from higher production volumes from our Marcellus wells and the tie-in of certain wells in the Williston/Bakken fields to the Oneok gas gathering system.  Our total sales prices were impacted by increases in prices received for natural gas and NGL of 13.8% and 28.5%, respectively, offset by a decline in the price received for oil sales of 0.7%. Our natural gas sales benefited from increased production and higher demand due to a longer and colder winter in the northeastern United States.  In addition, natural gas sales increased due to sales from our Collins, Mills Wetzel, Ormet, Spencer, Stewart Winland, and WVDNR wells in 2014, which were not on production until April and May of 2013. Of the total increase in oil and natural gas sales for the 2014 period, $16.3 million was attributable to increases in prices received and $49.0 million was attributable our increase in production.  The prices we receive for our products are generally tied to commodity index prices. 

Natural gas transportation, gathering, processing and marketing revenues.  Revenue from midstream operations, (which consist of Eureka Hunter Pipeline, TransTex Hunter, and Magnum Hunter Marketing operations) increased by $47.6 million, or 111.1%, for the nine months ended September 30, 2014 to $90.5 million from $42.9 million for the nine months ended September 30, 2013.  TransTex Hunter revenues decreased by $2.4 million primarily as the result of inventory sales during the first quarter of 2013. Eureka Hunter Pipeline revenues increased by $11.4 million as a result of new growth in third party customer contracts as well as increased volumes of natural gas product gathered from its pipeline gathering system from existing customers. Eureka Hunter Pipeline increased throughput volumes by 186.7% or 36.2 million MMBtu to 55.6 MMBtu for the nine months ended September 30, 2014 from 19.4 million MMBtu for the nine months ended September 30, 2013. Magnum Hunter Marketing revenues increased by $38.8 million to $66.7 million during the nine months ended September 30, 2014 from $27.9 million during the nine months ended September 30, 2013. Magnum Hunter Marketing revenues increased primarily due to its marketing contract with Jaybee, and also as a result of new customers, growth from existing customers, and increased gas and NGL revenues from the MarkWest processing plant. Increases related to the marketing contract with Jaybee are not expected to continue, as Jaybee began marketing all of its natural gas production previously marketed by Magnum Hunter Marketing effective July 1, 2014. The loss of the marketing contract with Jaybee is not expected to have a significant impact on profits, as the margin on sales to Jaybee is insignificant overall.

Oilfield services revenue.  Drilling services revenue increased by $3.8 million, or 27.9%, for the nine months ended September 30, 2014 to $17.6 million from $13.7 million for the nine months ended September 30, 2013. This increase was primarily attributable to higher utilization of the fleet of rigs. During the nine months ended September 30, 2014, our drilling rig revenue days increased from 932 to 1,621 as compared to the nine months ended September 30, 2013. For the nine months ended September 30, 2014, the total effective equipment performance of our drilling rigs was 95%, and our rigs were 100% utilized.

Gain (loss) on sale of assets.  We recorded a net gain on sale of assets in operating expenses of $4.6 million for the nine months ended September 30, 2014, compared to a net loss on sale of assets of $42.1 million for the nine months ended September 30, 2013. During the nine months ended September 30, 2014, a gain of $8.8 million related to the sale of certain oil and natural gas properties located in Divide County, North Dakota was partially offset by a loss of $4.5 million related to additional costs in 2014 associated with the divestiture of Eagle Ford Shale in South Texas in 2013. Of the total net loss on sale of assets recorded during

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the nine months ended September 30, 2013, $38.1 million related to the sale of certain of our properties in Burke County, North Dakota.

Lease operating expense.  Our LOE increased $15.9 million, or 32.7% for the nine months ended September 30, 2014, to $64.6 million ($14.11 Boe) from $48.7 million ($15.68 Boe) for the nine months ended September 30, 2013.  The increase in LOE was comprised of $23.1 million attributable to increased production volumes offset by $7.2 million attributable to lower LOE/Boe costs. Of the decrease in LOE/Boe costs, $7.2 million and $8.2 million was due to lower recurring costs in the Appalachian and Williston Basins, respectively, and $1.8 million was due to lower non-recurring workover expenses in the Williston Basin. These decreases were partially offset by a $10.0 million increase in third party transportation charges for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013.

Severance taxes.  Our severance taxes increased$5.9 million, or 45.2%, for the nine months ended September 30, 2014, to $18.8 million from $13.0 million for the nine months ended September 30, 2013.  The increase in severance taxes was attributable primarily to the increase in our production and sales.  

Exploration.  We record exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. We recorded $52.4 million of exploration expense for the nine months ended September 30, 2014, compared to $75.3 million for the nine months ended September 30, 2013.  During the 2014 period, the Company's exploration expense was primarily attributable to $37.8 million of leasehold impairments relating to leases in the Williston Basin region that expired undrilled during the nine months ended September 30, 2014 or are expected to retire and that the Company does not plan to develop, and $13.5 million related to leases in the Appalachian Basin, a portion of which relates to the assessment of MHP's carrying value upon reclassification into assets held for use and continuing operations as of September 30, 2014. The Company's exploration expense during the nine months ended September 30, 2013 of $75.3 million primarily related to leases in the Williston Basin.

Impairment of proved oil and natural gas properties.  Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis bi-annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows.

During the nine months ended September 30, 2014, changes in oil and natural gas prices provided indications of possible impairment on two legacy fields that are unrelated to our current drilling and development plan. As a result of our assessment, we recorded impairment of proved oil and natural gas properties in the Appalachian Basin in continuing operations of $39.8 million for the nine months ended September 30, 2014 to reduce the carrying value of these properties to their estimated fair values, a portion of which relates to the assessment of MHP's carrying value upon reclassification into assets held for use and continuing operations as of September 30, 2014. During the nine months ended September 30, 2013, we recorded impairments on our proved oil and natural gas properties in the Williston and Appalachian Basins of $39.5 million. We calculated the estimated fair values using a discounted cash flow model. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Natural gas transportation, gathering, processing and marketing expenses. Expenses from the midstream operations increased by $43.9 million, or 122.5% for the nine months ended September 30, 2014, to $79.7 million from $35.8 million for the nine months ended September 30, 2013 due to increased cost of gas marketed by Magnum Hunter Marketing along with Magnum Hunter Marketing's increased activities.

Oilfield services expenses.  Oilfield services expenses remained consistent at approximately $11.9 million for the nine months ended September 30, 2014 and the nine months ended September 30, 2013. 

Depletion, depreciation, amortization, and accretion.  Our DD&A increased $21.6 million, or 26.9%, to $101.7 million for the nine months ended September 30, 2014, from $80.1 million for the nine months ended September 30, 2013, due to increases in accumulated costs from our capital expenditure and acquisition programs during 2013 and 2014, and increased production in 2014. Our DD&A/Boe decreased by $3.60, or 13.9%, to $22.21 Boe for the nine months ended September 30, 2014, compared to $25.81 Boe for the nine months ended September 30, 2013. The decrease in DD&A/Boe was primarily attributable to an increase in natural gas production from continuing operations. Natural gas wells generally have a lower rate on a Boe basis than oil and NGL. The Company's natural gas production increased significantly due to its drilling in the Appalachian Basin.

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General and administrative.  Our G&A decreased$7.6 million, or 12.0%, to $56.0 million ($12.23 Boe) for the nine months ended September 30, 2014, from $63.7 million ($20.51 Boe) for the nine months ended September 30, 2013.  G&A expenses decreased overall during 2014 mainly due to lower stock compensation expense. Non-cash stock compensation expense decreased by $6.1 million, to approximately $5.7 million ($1.24 Boe) for the nine months ended September 30, 2014, from $11.8 million ($3.81 Boe) for the nine months ended September 30, 2013 as a result of a grant during the first quarter of 2013 of which 25% vested immediately.

Interest expense, net.  Our interest expense, net of interest income, increased by 17.3%, to $62.3 million for the nine months ended September 30, 2014, from $53.1 million for the nine months ended September 30, 2013.  Our higher average debt level in the nine months ended September 30, 2014 compared to the same period in 2013 accounted for $4.1 million of the increase, and higher amortization and write-off of deferred financing costs accounted for $5.1 million of the increase. We also incurred a $2.2 million prepayment penalty through the early termination of credit agreements of Eureka Hunter Pipeline. Interest expense was offset by capitalized interest of $1.6 million and $2.0 million during the nine months ended September 30, 2014 and 2013, respectively. We capitalize interest on projects lasting six months or longer.

Commodity and financial derivative activities.  Our commodity and financial derivative activity resulted in net losses of $92.1 million and $30.6 million for the nine month periods ended September 30, 2014 and 2013, respectively. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:

	Nine Months Ended   September 30,
	2014			2013
	(in thousands)
Commodity derivatives
Realized loss on settled transactions	$	(4,074	)	$	(6,887	)
Unrealized gain (loss) on open contracts	3,737			(2,764		)
Total commodity derivatives	(337		)	(9,651		)
Financial derivatives
Unrealized loss on open contracts	(91,788		)	(20,993		)
Net loss	$	(92,125	)	$	(30,644	)

We do not designate our derivative instruments as cash-flow hedges.

At September 30, 2014, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Eureka Hunter Holdings Series A Preferred Units. This embedded derivative instrument resulted in unrealized losses of $91.8 million and $20.8 million in the nine months ended September 30, 2014 and 2013, respectively. The change in unrealized loss was driven primarily by increases in total enterprise value and a reduction in the expected term of the conversion feature.

The change in expected term is the result of management’s assessment of the likely time horizon for which a liquidity event will occur resulting in conversion of the Eureka Hunter Holdings Series A Preferred Shares to Class A Common Units of Eureka Hunter Holdings.  Multiple factors were considered in determining the expected term, which led to using a probability weighted average of the potential timing of a liquidity event.  The recent approval of the Eureka Hunter Holdings LLC Management Incentive Compensation Plan, the payout under which is linked to a defined liquidity event, led to management’s assessment of the potential timing of a liquidity event.  The weighting was based on the current market for master limited partnership initial public offerings.  These factors impacted our assessment of the expected term, and resulted in a shorter time horizon input for purposes of the fair value calculation that was based on the weighted average of potential expected liquidity events.

The change in total enterprise value was also impacted significantly by the recent agreement reached between MSI and Ridgeline for MSI to purchase all of Ridgeline's equity interests in Eureka Hunter Holdings, and which closed in October 2014. Management factored the purchase price of that transaction into its determination of total enterprise value as of September 30, 2014. As a result of this undertaking, the total enterprise value of Eureka Hunter Holdings at September 30, 2014 increased to approximately $929.7 million compared to $544 million at September 30, 2013.

Also at September 30, 2014, the Company has recognized an asset for an embedded derivative related to a convertible security, due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. An unrealized

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gain of $4,000 and an unrealized loss of $185,000 are recorded for this embedded derivative instrument in the nine months ended September 30, 2014 and 2013, respectively. Both derivative instruments originated in 2012 and the derivative instruments have resulted in no cash outlays as of September 30, 2014.

We record our open derivative instruments at fair value on our consolidated balance sheets as either current or long-term assets or liabilities, depending on the timing of expected cash flows. We record all realized and unrealized gains and losses on our consolidated statements of operations under the caption entitled "Loss on derivative contracts, net".

Income tax benefit.  We were in a net operating loss position as of September 30, 2014, and have a full valuation allowance on all deferred tax assets. As a result, we did not recognize a tax benefit on our September 30, 2014 net loss, whereas we recognized a benefit of $47.2 million for the nine months ended September 30, 2013.

Net loss attributable to non-controlling interest.  Net loss attributable to non-controlling interest was $3.7 million for the nine months ended September 30, 2014, which represents 1.6% of the net income or loss attributable to our majority-owned subsidiary, Eureka Hunter Holdings. Net loss attributable to non-controlling interest of $1.6 million for the nine months ended September 30, 2013 represented 2.0% of the net income or loss incurred by our majority-owned subsidiary, Eureka Hunter Holdings and 12.5% of the gain or loss incurred by our subsidiary, PRC Williston.

On December 30, 2013, PRC Williston, in which the Company owned an 87.5% interest as of December 31, 2013, sold substantially all of its assets. On July 24, 2014, the Company executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, the Company now owns 100% of the equity interests in PRC Williston and has all rights and claims its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston's equity reflected in the consolidated financial statements as of September 30, 2014.

Income (loss) from discontinued operations, net of tax.In September 2013, the Company adopted a plan to divest all of its interests in WHI Canada. The Company has reclassified the associated assets and liabilities to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented. The Company closed on the sale of its interests in WHI Canada during the second quarter of 2014.

Income from discontinued operations was $4.6 million for the nine months ended September 30, 2014, compared to a loss of $62.5 million for the nine months ended September 30, 2013. The following table summarizes the income (loss) from discontinued operations for the periods indicated:

	Nine months ended September 30,
	2014		2013
	(in thousands)
Eagle Ford Hunter	$	—	$	15,976
Williston Hunter Canada	4,561		(78,429		)
	$	4,561	$	(62,453	)

Gain (loss) on disposal of discontinued operations, net of tax. The Company recognized a loss on disposal of discontinued operations of $14.0 million for the nine months ended September 30, 2014 and a gain on disposal of discontinued operations of $102.9 million for the nine months ended September 30, 2013. The following table summarizes the gain (loss) on disposal of discontinued operations for the periods indicated:

	Nine months ended September 30,
	2014			2013
	(in thousands)
Eagle Ford Hunter	$	(7,282	)	$	158,572
Williston Hunter Canada	(6,701		)	(55,641		)
	$	(13,983	)	$	102,931

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During the nine months ended September 30, 2013, we estimated that the final working capital adjustment on the sale of Eagle Ford Hunter would be approximately $32.9 million. We accrued a liability of $32.9 million and recorded a corresponding downward adjustment to the $172.5 million preliminary gain recognized as of June 30, 2013. As of June 30, 2014, we estimated that the final working capital adjustment related to the Eagle Ford Hunter sale would be a reduction to the preliminary gain recognized of $33.7 million, plus accrued interest of $1.3 million.  This liability was settled in cash on July 31, 2014. The Company recorded a downward adjustment to the gain on sale of Eagle Ford Hunter of $7.3 million during the nine months ended September 30, 2014.

Dividends on preferred stock.  Total dividends on our preferred stock were approximately $45.7 million for the nine months ended September 30, 2014, and $42.0 million for the nine months ended September 30, 2013. 

The Series C Preferred Stock had a stated value of $100.0 million at both September 30, 2014 and December 31, 2013, and carries a cumulative dividend rate of 10.25% per annum.  The Series D Preferred Stock had a stated value of $221.2 million and $221.2 million at September 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million and $95.1 million at September 30, 2014 and December 31, 2013, 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 $271.4 million and $200.6 million at September 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum.

Liquidity and Capital Resources

Overview

We generally rely on cash generated from operations, borrowings under our credit facilities, proceeds from sales of assets and proceeds from the sale of securities in the capital markets, when market conditions are favorable, to meet 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 credit facilities, and, more broadly, on our ability to access the capital markets, all of which are 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 credit facilities will be available, or available on acceptable terms, or at all, in the foreseeable future.

Our future capital resources and liquidity depend, in part, on our success in developing our oil and natural gas properties, growing production from our properties, increasing our proved reserves, and building out our gathering system pipeline and increasing throughput on the system. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and evaluate our development plans in view of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes.

Our cash flow from operations is driven by commodity prices and production volumes and the effect of commodity derivatives. Prices for oil and natural gas are primarily 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. Recent declines in market prices for commodities and certain natural gas transportation capacity restraints that have resulted in an oversupply of natural gas in the Appalachian Basin have resulted in lower realized prices for the three months ended September 30, 2014 compared to prior periods.

Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices will cause us to (i) decrease our production volumes, if continued production will not be profitable based on such prices, and (ii) decrease our exploration and development expenditures, which may adversely affect our production volumes. Cash flows from operations are primarily used to fund exploration and development of our oil and natural gas properties and other capital expenditures. Although recent declines in market prices have affected our realized prices, we have not had to shut in production due to the economics of any of our wells during the three month period ended September 30, 2014. However, further declines in market prices for oil and natural gas may result in certain of our wells being shut-in, capital expenditures being curtailed, or a combination of both until market prices recover sufficiently to provide economic returns on such wells. Our capital expenditure budgets are based upon our plans to further explore and develop our oil and natural gas interests, but we have flexibility in the timing of a substantial portion of our discretionary capital spending. Consequently, market conditions may result in us deferring certain capital projects to future periods.

We utilize our credit agreements to fund a portion of our operating and capital needs.  On May 6, 2014, we entered into the First Amendment to the Third Amended and Restated Credit Agreement which increased our borrowing base under the MHR Senior Revolving Credit Facility from $232.5 million to $325.0 million. As called for under the terms of the First Amendment to the Third

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Amended and Restated Credit Agreement, the borrowing base was reduced by $25.0 million upon the issuance of common equity in a private placement, by $27.5 million upon the sale of WHI Canada, a wholly-owned subsidiary, and by $7.5 million upon the sale of certain North Dakota assets. The amendment also made modifications to the MHR Senior Revolving Credit Facility terms and conditions, including modifications to future financial ratio requirements, as more fully discussed in the Amendment to Credit Facilities section of Management's Discussion and Analysis of Financial Condition and Results of Operations. The Company had $256.0 million of outstanding principal and $2.3 million in letters of credit used under our MHR Senior Revolving Credit Facility at September 30, 2014, with available borrowing capacity at that date of $6.7 million.

We define liquidity as funds available under our credit facilities plus cash and cash equivalents, excluding amounts held by our subsidiaries that are designated as unrestricted subsidiaries under this facility. At September 30, 2014, liquidity for the Company, excluding Eureka Hunter Holdings and its subsidiaries, was $46.6 million, comprised of $6.7 million of available borrowing capacity under the MHR Senior Revolving Credit Facility and $39.9 million in available cash.

While we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities, available borrowing capacity under the credit facilities, proceeds from further potential sales of oil and natural gas assets and proceeds from capital market transactions, to the extent that we access such capital markets at opportune times, will be adequate to execute our corporate strategies and to meet debt service obligations, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. Significant reductions in our borrowing capacity as a result of a redetermination of our borrowing base could have an adverse impact on our capital resources and liquidity.  In addition, the ability of the Company to continue to execute on targeted oil and natural gas asset sales is critical to our ability to effectively manage our capital budget, financial condition, liquidity and results of operations.

Factors that will affect our liquidity in 2015 include the receipt of proceeds from further potential divestitures of certain oil and natural gas properties and operations and expected increases in operating cash flows on our remaining assets as a result of the successful results of our ongoing drilling program and the development of acquired properties. While the Company is currently evaluating the monetization of certain of our oil and natural gas assets, market factors, including further declines in the prices of oil and natural gas, may result in further impairments to our oil and natural gas assets.

We intend to fund the remainder of our 2014 capital expenditures and our 2015 capital budget, excluding any acquisitions, from a combination of internally-generated cash flows, borrowings under our MHR Senior Revolving Credit Facility (as amended), a new Second Lien Term Loan, Eureka Hunter Pipeline’s new senior secured revolving credit facility, proceeds from targeted oil and natural gas asset sales and proceeds from capital markets transactions, to the extent we access such capital markets at opportune times. A substantial portion of our capital expenditures are discretionary in nature, and we may need to exercise flexibility in the timing and extent of such expenditures as a result of market conditions to manage our capital needs.

As discussed below, we will have greater flexibility in our funding of certain required future capital contributions to Eureka Hunter subject to the terms of the New LLC Agreement of Eureka Hunter, which may include deferral of a portion of such capital contributions for up to 180 days without losing our share of ownership in Eureka Hunter should MSI fund Magnum Hunter's pro rata share during the deferral period.

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Liquidity Position

The following table summarizes our liquidity position at September 30, 2014 compared to December 31, 2013:

	As of September 30, 2014						As of December 31, 2013
	(in thousands)
	Magnum Hunter			Eureka Hunter			Magnum Hunter			Eureka Hunter
Borrowing base under MHR senior revolving credit facility	$	265,000		$	—		$	242,500		$	—
Eureka Hunter Pipeline second lien term loan	—			—			—			50,000
Eureka Hunter Pipeline Credit Agreement	—			90,200			—			—
Cash and cash equivalents	39,914			2,753			33,669			8,044
Borrowings under MHR Senior Revolving Credit Facility	(256,000		)	—			(218,000		)	—
Letters of credit issued	(2,325		)	—			(7,225		)	—
Borrowings under Eureka Hunter Pipeline second lien term loan	—			—			—			(50,000		)
Borrowings under Eureka Hunter Pipeline Credit Agreement	—			(80,000		)	—			—
Liquidity	$	46,589		$	12,953		$	50,944		$	8,044

The Company had $256.0 million outstanding under the MHR Senior Revolving Credit Facility and $2.3 million in issued letters of credit at September 30, 2014, with available borrowing capacity at that date of $6.7 million. We assess our liquidity situation based upon how our funds are available for use since cash and borrowings available to our majority owned subsidiary, Eureka Hunter Holdings and its subsidiaries, are restricted from use by or distributions to affiliated entities. As a result, we analyze liquidity for Eureka Hunter Holdings and its subsidiaries separately from the rest of the Company.

At September 30, 2014, liquidity for Eureka Hunter was $13.0 million. Under the Eureka Hunter Pipeline Credit Agreement, Eureka Hunter Pipeline may borrow up to $117 million, provided, however, that at period-end, it is in compliance with the financial ratios under that agreement. At September 30, 2014, Eureka Hunter Pipeline could borrow up to $90.2 million and still maintain compliance with financial ratios. Additionally, at that date, all capital funding commitments from the Company and Ridgeline, Eureka Hunter Holdings' minority interest holder at that time, had been fulfilled.

As a result of the refinancing of our MHR senior revolving credit facility, which closed on October 22, 2014, we were not required to submit debt compliance certificates as of and for the period ended September 30, 2014, as would otherwise have been required under the Third Amended and Restated Credit Agreement, as amended.

Liquidity Transactions

We continue to focus our efforts on improving our liquidity by (i) accessing the credit and capital markets where economic and when market conditions allow, (ii) focusing our exploration and development activities on our core oil and natural gas producing assets, (iii) marketing and divesting certain oil and natural gas assets, and (iv) reducing our non-essential general and administrative costs. During the first nine months of 2014, and through November 7, 2014, we closed on sales of non-core assets and raised cash through private offerings of common stock for aggregate proceeds of approximately $390.5 million, as follows:

• cash proceeds of approximately $15.5 million, before customary purchase price adjustments, and $9.4 million in common shares of NSE, from our sale of certain oil and natural gas assets in the Eagle Ford Shale area;

• cash proceeds of approximately $178.4 million from the private placements of 25,728,580 shares of our common stock and 2,142,858 warrants to purchase common stock;

• cash proceeds of approximately CAD $9.5 million (or US $8.7 million), subject to customary adjustments, from our sale of certain oil and natural gas assets in Alberta, Canada to BDJ Energy; and

• cash proceeds of approximately CAD $75.0 million (or US $68.8 million), subject to customary adjustments, from the sale of our 100% interest in WHI Canada, a wholly-owned subsidiary.

• cash proceeds of approximately $109.5 million, subject to customary adjustments, from the sale of our ownership interest in certain non-operated oil and natural gas properties located in Divide County, North Dakota and Calhoun and Roane Counties, West Virginia, which occurred through three separate transactions.

Upon closing of the sale of WHI Canada, our borrowing base under the MHR Senior Revolving Credit Facility decreased by $27.5 million. Additionally, until certain Canadian tax filing and related approval requirements were fulfilled, 25% of the CAD $75.0

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million purchase price was restricted and held in escrow at June 30, 2014, pending release by the Canadian Revenue Authority. This cash was received by the Company in July 2014.

The closing of the sale of the Company’s remaining Canadian properties represents a further step that we have taken in our strategy to identify and monetize assets, and reallocate our resources primarily to our existing properties and operations (including our midstream operations) in the Marcellus Shale and Utica Shale in West Virginia and Ohio, which we believe offer the opportunity for more attractive returns on invested capital.

On October 22, 2014, the Company closed on two new credit facilities and completely refinanced its prior revolving credit facility. The new credit facilities consist of (i) a $50 million senior secured first lien reserve-based revolving credit facility, maturing four years after the closing date, and (ii) a $340 million senior secured second lien term loan, maturing five years after the closing date. Subject to certain exceptions, the obligations of the Company under the New Credit Agreement and the Second Lien Term Loan Agreement are secured by substantially all the assets of the Company and its restricted subsidiaries. Proceeds from the new term loan were used to repay 100% of the outstanding borrowings under the Company’s existing revolving credit facility (approximately $241 million on October 22, 2014) along with customary transaction costs. The new available proceeds will be used primarily to fund the Company’s upstream operations in the Marcellus and Utica Shale plays of West Virginia and Ohio and for general corporate purposes. The gross proceeds from the two new credit facilities were reduced by financing costs of approximately 3% of the senior secured second lien term loan plus other applicable banking fees and charges.

The closing of these new credit facilities significantly enhanced our current liquidity position and provides us with greater financial flexibility to execute on our upstream development program in West Virginia and Ohio. However, as discussed in New Credit Agreements in Management's Discussion and Analysis of Financial Condition and Results of Operations, the Second Lien Term Loan Agreement limits the amount of indebtedness that the Company may incur under the New Credit Agreement to the greater of (a) the sum of $50 million plus the aggregate amount of loans repaid or prepaid under the Second Lien Term Loan Agreement and (b) an amount equal to 25% of Adjusted Consolidated Net Tangible Assets (as defined in the Second Lien Term Loan Agreement) of the Company and its restricted subsidiaries; provided, in the case of clause (b), after giving effect to such incurrence of indebtedness and the application of proceeds therefrom, aggregate secured debt may not exceed 25% of the Adjusted Consolidated Net Tangible Assets of the Company and its restricted subsidiaries as of the date of such incurrence.

Following the closing of the new credit facilities, the Company had total liquidity of $212 million, comprised of $164 million of cash and $48 million of borrowing availability under our new senior secured revolving credit facility.

In connection with a commitment to purchase firm transportation with Rockies Express Pipeline LLC, the Company will be required to post a standby letter of credit by November 22, 2014 in the amount of $37 million, which will reduce the Company's available liquidity until such amounts are reduced or otherwise assumed by a third party through a proposed asset management agreement (see related discussion in the Contractual Obligations section of Management's Discussion and Analysis of Financial Condition and Results of Operations).

On September 16, 2014, we entered into a Transaction Agreement with MSI relating to a separate purchase agreement between MSI and Ridgeline, an affiliate of ArcLight, providing for the purchase by MSI of all convertible preferred and common equity interests in Eureka Hunter owned by Ridgeline. The first closing contemplated by the Transaction Agreement occurred on October 3, 2014.

The Transaction Agreement provides that Magnum Hunter will sell to MSI in a second closing, that is expected to occur in mid-January 2015, a portion of its Eureka Hunter Holdings Series A-1 Common Units, which, assuming completion of the full amount of additional capital contributions expected to be made by MSI, would constitute approximately 6.5% of the total common equity interests in Eureka Hunter. Any Series A-1 Common Units purchased by MSI from the Company under a second closing will convert immediately into Series A-2 Units. The purchase price of such additional equity interests is expected to be approximately $65 million. Also, in accordance with the terms and conditions of the New LLC Agreement, Magnum Hunter will have the right, under certain circumstances, to not make its portion of certain required future capital contributions to Eureka Hunter, and, if Magnum Hunter validly exercises its right to do so, MSI will make the capital contributions which otherwise would be made by Magnum Hunter, with Magnum Hunter having the right to make capital contributions within 180 days that will bring Magnum Hunter's ownership interest back to the level prior to the capital call. This catch-up feature will be at no cost to Magnum Hunter but will be subject to a maximum of $40 million for each 180-day period.

Sources of Cash

For the nine months ended September 30, 2014, our primary sources of cash were cash flows from operating activities, proceeds from sales of assets, proceeds from issuance of common stock and borrowings under our MHR Senior Revolving Credit Facility.

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

	Nine Months Ended September 30,
	2014			2013
	(In thousands)
Cash flows provided by operating activities	$	13,555		$	79,197
Cash flows provided by (used in) investing activities	(247,304		)	44,823
Cash flows provided by (used in) financing activities	234,659			(126,267		)
Effect of foreign currency exchange rates	44			(93		)
Net decrease in cash and cash equivalents	$	954		$	(2,340	)

Operating Activities

Our cash flow from operations is driven by commodity prices and production volumes and the effect of commodity derivatives. Prices for oil and natural 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, which the Company manages using derivative instruments, and significant declines in prices will cause us to (i) decrease our production volumes, if continued production will not be profitable based on such prices, and (ii) decrease our exploration and development expenditures, which may adversely affect our production volumes. Cash flows from operations are primarily used to fund exploration and development of our oil and natural gas properties and other capital expenditures.

Our cash provided by operating activities was $13.6 million for the nine months ended September 30, 2014, compared to $79.2 million for the nine months ended September 30, 2013, a decrease of $65.6 million or 82.9%.  Increased oil and natural gas sales from the recent success in our drilling programs in the Marcellus Shale and Utica Shale and lower receivables resulted in increased cash available. Cash used in paying down working capital increased compared to the same period in 2013. Cash provided by operating activities for the nine months ended September 30, 2014 includes cash flows used by discontinued operations of $10.3 million. We do not expect the absence of cash flows from discontinued operations to have a material impact on future liquidity and capital resources.

Investing Activities

Our cash used in investing activities for the nine months ended September 30, 2014, was $247.3 million, principally from our drilling and completion programs in the Marcellus and Utica Shales as well as our expansion programs for our natural gas gathering pipeline system. These cash outflows were partially offset by cash proceeds from the sale of non-core assets and working interests of $110.7 million including our 100% equity interest in WHI Canada and the sale of certain of our working interests in proved and unproved acreage in Divide County, North Dakota.

Our primary focus is in developing our core areas which include the Marcellus Shale in West Virginia and Ohio, the Utica/Point Pleasant formation in Ohio and West Virginia, along with the Bakken formation in North Dakota. In addition to our ongoing drilling and completion and pipeline buildout activities, we continue to acquire leasehold acreage in our core areas and select other exploratory areas we believe are prospective for hydrocarbons.

Our cash provided by investing activities for the nine months ended September 30, 2013 was $44.8 million, principally from the cash proceeds from the sale of assets of $461.0 million, partially offset by capital expenditures of $418.2 million.

Non-Cash Investing Items

In connection with the sale of certain assets by Shale Hunter, we acquired 65,650,000 common shares of NSE, an Australian Securities Exchange listed Australian company, with a fair value of approximately $9.4 million upon acquisition.

Financing Activities

Our cash provided by financing activities for the nine months ended September 30, 2014 was $234.7 million mainly from borrowings of $279.6 million and proceeds from the issuance of shares of common stock. We raised $178.4 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through private offerings of 25,728,580 shares of our common stock and 2,142,858 warrants to purchase common stock. See "Note 12 - Shareholders' Equity" for additional

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information. Our majority owned subsidiary, Eureka Hunter Pipeline, paid in full and terminated its term loan with Pennant Park and borrowed $80.0 million from the new Eureka Hunter Pipeline Credit Agreement executed in March 2014 (see "Note 10 - Debt"). These increases were partially offset by debt pay-down under the MHR Senior Revolving Credit Facility and other debt agreements of approximately $208.3 million. In addition, we paid preferred dividends of $36.8 million and paid deferred finance costs on loans of $6.2 million during the nine months ended September 30, 2014.

Our cash used in financing activities for the nine months ended September 30, 2013 were $126.3 million, mainly from debt pay-down under the MHR Senior Revolving Credit Facility and other debt agreements of $379.5 million, partially offset by borrowings of $246.0 million. The Company also raised $10.2 million in proceeds from the issuance of shares of our 8.0% Series D Cumulative Perpetual Preferred Stock for cumulative net proceeds of approximately $9.6 million, and issued shares of our 8% Series E Cumulative Convertible Preferred Stock for cumulative net proceeds to the Company of $590,000. In the 2013 period, we paid preferred dividends of $29.9 million and incurred $1.2 million in deferred finance costs on loans.

As a result of our failure to file our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 within the time frames required by the SEC, for the past 12 months we were limited in our ability to access the public markets to raise debt or equity capital. We have now timely filed all our required SEC reports for a period of twelve months, and we are now eligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. We are now able to use a shelf registration statement on Form S-3 to conduct ATM offerings of our equity securities, which ATM offerings we had conducted on a regular basis with respect to our preferred stock prior to our delinquent SEC filings. On August 5, 2014, we filed a universal shelf Form S-3 Registration Statement to register the sale of an unlimited amount of equity and debt securities, and such registration statement became effective automatically upon filing.

We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) capital market related funding, (iv) borrowing capacity available under our credit facilities, and (v) further potential sales of oil and natural gas assets will provide sufficient means to conduct our operations, meet our contractual obligations, including our debt covenant requirements, as amended, and complete our budgeted capital expenditure program for the remainder of 2014 and for 2015.

2014 Capital Expenditures

The following table summarizes our actual capital expenditures (excluding acquisitions) for the nine months ended September 30, 2014 and our capital budget for 2014.  We intend to fund the remainder of our 2014 capital expenditures, excluding any acquisitions, partially out of internally-generated cash flows, anticipated sales of assets, borrowings under our credit facilities, and, when market conditions are favorable, proceeds from the sale of securities in the capital markets.   

	Capital Expenditures Incurred (2)		Capital Expenditure Budget
	Nine Months Ended September 30, 2014		For the Year ending December 31, 2014
	(In thousands)
Upstream Operations
Appalachian Basin drilling	$	158,012	$	260,000
Williston Basin drilling	60,669		50,000
Midstream and Marketing Operations
Eureka Hunter Holdings, gross of contributed expenditures (1)	171,152		210,000
Total capital expenditures	$	389,833	$	520,000

________________________________

(1) The expenditures are expected to be financed through debt facilities that are non-recourse to the Company and through capital contributions from the Company and MSI.

(2) Capital expenditures of $8.1 million incurred in other regions, leasehold acquisitions of approximately $86.4 million, and expenditures on other property, plant, and equipment of approximately $14.5 million are not included in the summary above.

Our capital expenditure budget for the remainder of 2014 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 natural 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 drilling locations.

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During the nine months ended September 30, 2014, the budget for our Midstream and Marketing Operations was increased from $150.0 million to $210.0 million as a result of the acceleration of certain of Eureka Hunter's capital projects that were necessary to meet earlier than expected natural gas gathering demands of Triad Hunter and third party customers.

Amendment to Credit Facility

On May 6, 2014, the Company executed an amendment (the "Amendment") to the Third Amended and Restated Credit Agreement, dated as of December 13, 2013 (the "Credit Agreement"), by and among the Company, as borrower, the guarantors party thereto, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto. Capitalized terms used but not otherwise defined herein shall have the meaning ascribed to such terms in the Credit Agreement, as amended where applicable.

With the execution of the Amendment, the borrowing base was increased from $232.5 million to $325.0 million in connection with the regular semi‑annual redetermination of the Company’s borrowing base derived from the Company’s proved crude oil and natural gas reserves. The borrowing base may be increased or decreased in connection with such redeterminations up to a maximum commitment level of $750.0 million.

The Amendment provides that such increased borrowing base shall be reduced (i) by the lesser of $25.0 million or 50% of the net proceeds from issuances by the Company of common equity on or before July 1, 2014 (other than common equity issued pursuant to any stock incentive or stock option plan or any other compensatory arrangements); (ii) by certain specified reductions in connection with certain proposed asset dispositions; (iii) on July 1, 2014 by $25.0 million less any prior adjustment of the borrowing base due to an equity issuance as contemplated by clause (i); and (iv) by $0.25 for each $1.00 of any additional Senior Notes issued by the Company. The Amendment further provides that from May 6, 2014 through July 1, 2014 the Applicable Margin component of the interest charged on revolving borrowings under the Credit Agreement shall be 2.75% for ABR Loans and 3.75% for Eurodollar Loans. From and after July 1, 2014 through the date of the Company’s delivery of a certificate for the quarter ended June 30, 2014, with respect to, among other things, the Company’s compliance with the covenants in the Credit Agreement (the "Compliance Certificate"), the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement will range from 1.50% to 2.25% for ABR Loans and from 2.50% to 3.25% for Eurodollar Loans. From and after the Company’s delivery of the Compliance Certificate, the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement will range from 1.00% to 1.75% for ABR Loans and from 2.00% to 2.75% for Eurodollar Loans.

In addition, the Amendment modified certain of the Credit Agreement’s financial covenants, including:

(i) permitting the Company to take into account the borrowing base increase as though it occurred on March 31, 2014 for purposes of maintaining a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

(ii) providing for a ratio of EBITDAX to Interest Expense of not less than (A) 2.00 to 1.00 for the fiscal quarter ended March 31, 2014, (B) 2.25 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (C) 2.5 to 1.0 for the fiscal quarter ending December 31, 2014 and for each fiscal quarter ending thereafter; and

(iii) beginning with the fiscal quarter ended June 30, 2014, providing for a ratio of total Debt to EBITDAX of not more than (A) 4.75 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, (B) 4.50 to 1.0 for the fiscal quarter ending December 31, 2014, and (C) 4.25 to 1.0 for the fiscal quarter ending March 31, 2015 and for each fiscal quarter ending thereafter.

The Amendment also (i) amends the definition of EBITDAX and provides that certain acquisitions and dispositions be given pro forma effect in the calculation of EBITDAX; (ii) increases the letter of credit commitment from $10.0 million to $50.0 million and provides that outstanding letter of credit exposure not be included in certain determinations of Debt; (iii) requires the total value of the Company’s oil and gas properties included in the reserve reports for the borrowing base determinations in which the lenders under the Credit Agreement have perfected liens be increased from 80% to 90%; and (iv) modifies certain covenants in the Credit Agreement with respect to permitted investments by the Company to increase flexibility.

The foregoing summary description of the Amendment does not purport to be complete and is qualified in its entirety by reference to the terms of the Amendment, a copy of which is filed herewith as Exhibit 10.5 and incorporated herein by reference.

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New Credit Agreements

Revolving Credit Facility

On October 22, 2014, the Company entered into a Fourth Amended and Restated Credit Agreement (the "New Credit Agreement"), by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto. The New Credit Agreement amended and restated the Credit Agreement, dated as of December 13, 2013, by and among those parties, as amended.

The New Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing October 22, 2018 (the "Revolving Facility") with an initial borrowing base of $50 million. The Revolving Facility is governed by a semi-annual borrowing base redetermination derived from the Company’s proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or increased up to a maximum commitment level of $250 million, provided, however, that the Second Lien Term Loan limits the amount of indebtedness the Company may incur under the New Credit Agreement (as discussed below).

The terms of the New Credit Agreement provide that the Revolving Facility may be used for loans and, subject to a $50 million sublimit, letters of credit. The New Credit Agreement provides for a commitment fee of 0.5% based on the unused portion of the borrowing base under the Revolving Facility. As discussed below, however, provisions of the Second Lien Term Loan Agreement limit the amount of indebtedness that the Company may incur under the New Credit Agreement.

Borrowings under the Revolving Facility will, at the Company’s election, bear interest at either (i) an alternate base rate ("ABR") equal to the higher of (A) the prime rate (as determined by Bank of Montreal) (B) the overnight federal funds effective rate, plus 0.50% per annum, and (C) the adjusted one-month LIBOR plus 1.00% or (ii) the adjusted LIBO Rate (which is based on LIBOR), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.00% to 2.00% for ABR loans and from 2.00% to 3.00% for adjusted LIBO Rate loans. Accrued interest on each ABR loan is payable in arrears on the last day of each March, June, September and December and accrued interest on each adjusted LIBO Rate loan is payable in arrears on the last day of the Interest Period (as defined in the New Credit Agreement) applicable to the borrowing of which such adjusted LIBO Rate loan is a part and, in the case of an adjusted LIBO Rate borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.

The New Credit Agreement contains negative covenants that, among other things, restrict the ability of the Company and its restricted subsidiaries to, with certain exceptions, (i) incur indebtedness, (ii) grant liens, (iii) make certain payments, (iv) change the nature of its business, (v) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions, (vi) make investments, loans or advances, (vii) pay cash dividends, unless certain conditions are met, and with respect to the payment of dividends on preferred stock, subject to (A) no Event of Default (as defined in the New Credit Agreement) existing, (B) after giving effect to any such preferred stock dividend payment, the Company maintaining availability under the borrowing base in an amount greater than the greater of (x) 2.50% percent of the borrowing base then in effect or (y) $5,000,000 and (C) a "basket" of $45,000,000 per year, (viii) enter into transactions with affiliates, and (ix) enter into hedging transactions.

In addition, the New Credit Agreement requires the Company to satisfy certain financial covenants, including maintaining:

(i) a current ratio of not less than 1.0 to 1.0, commencing with the fiscal quarter ending December 31, 2014;

(ii) a leverage ratio (secured net debt to EBITDAX (as defined in the New Credit Agreement) with, beginning with the fiscal quarter ending March 31, 2016, a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than (A) 2.5 to 1.0 as of the last day of the fiscal quarter ending December 31, 2014, (B) 2.25 to 1.00 as of the last day of the fiscal quarter ending March 31, 2015 and (C) 2.0 to 1.0 as of the last day of the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter; and

(iii) the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement described below.

The obligations of the Company under the New Credit Agreement may be accelerated upon the occurrence of an Event of Default. Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations and warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a Change of Control (as defined in the New Credit Agreement) and any "Event of Default" under the Second Lien Term Loan Agreement, subject to certain cure periods.

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Subject to certain exceptions, the Revolving Facility is secured by substantially all of the assets of the Company and its restricted subsidiaries, including, without limitation, no less than 90% of the present value (with a discount rate of 10%) of the proved oil and gas reserves of the Company and its restricted subsidiaries. Additionally, any collateral pledged as security for the Second Lien Term Loan (as defined below) is required to be pledged as security for the New Credit Agreement. In connection with the New Credit Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Revolving Facility is unconditionally guaranteed by such restricted subsidiaries. The Company’s restricted subsidiaries under the New Credit Agreement and the Second Lien Term Loan do not include the Company’s majority-owned subsidiaries through which the Company conducts its midstream operations, including Eureka Hunter Holdings, Eureka Hunter Pipeline and TransTex Hunter.

Second Lien Term Loan

On October 22, 2014, the Company also entered into a Second Lien Credit Agreement (the "Second Lien Term Loan Agreement"), by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto.

The Second Lien Term Loan Agreement provides for a $340 million term loan facility (the "Second Lien Term Loan"), secured by, subject to certain exceptions, a second lien on substantially all of the assets of the Company and its restricted subsidiaries. The entire $340 million Second Lien Term Loan was drawn on October 22, 2014. The Company used the proceeds of the Second Lien Term Loan to repay amounts outstanding under its Credit Agreement, to pay transaction expenses related to the New Credit Agreement and the Second Lien Term Loan Agreement, and for working capital and general corporate purposes. Amounts borrowed under the Second Lien Term Loan that are repaid or prepaid may not be reborrowed. The Second Lien Term Loan has a maturity date of October 22, 2019 and will amortize (beginning December 31, 2014) in equal quarterly installments in an aggregate annual amount equal to 1.00% of the original principal amount of the Second Lien Term Loan.

Borrowings under the Second Lien Term Loan will, at the Company’s election, bear interest at either (i) an alternate base rate (which is equal to the higher of (A) the prime rate (as determined by Credit Suisse), (B) the overnight federal funds effective rate, plus 0.50% per annum, and (C) the adjusted one-month LIBOR plus 1.00%) plus 6.50% or (ii) the adjusted LIBO Rate (which is based on LIBOR) plus 7.50%.

The Second Lien Term Loan Agreement contains negative covenants substantially similar to those in the New Credit Agreement that, among other things, restrict the ability of the Company and its restricted subsidiaries to, with certain exceptions: (i) incur indebtedness; (ii) grant liens; (iii) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (iv) change the nature of its business; (v) make investments, loans, or advances or guarantee obligations; (vi) pay cash dividends or make certain other payments; (vii) enter into transactions with affiliates; (viii) enter into sale and leaseback transactions; (ix) enter into hedging transactions; and (x) amend its organizational documents or the New Credit Agreement.

The Second Lien Term Loan Agreement limits the amount of indebtedness that the Company may incur under the New Credit Agreement to the greater of (a) the sum of $50 million plus the aggregate amount of loans repaid or prepaid under the Second Lien Term Loan Agreement and (b) an amount equal to 25% of Adjusted Consolidated Net Tangible Assets (as defined in the Second Lien Term Loan Agreement) of the Company and its restricted subsidiaries; provided, in the case of clause (b), after giving effect to such incurrence of indebtedness and the application of proceeds therefrom, aggregate secured debt may not exceed 25% of the Adjusted Consolidated Net Tangible Assets of the Company and its restricted subsidiaries as of the date of such incurrence.

The Second Lien Term Loan Agreement also requires the Company to satisfy certain financial covenants, including maintaining

(i) a ratio of proved reserves to secured debt of not less than 1.5 to 1.0 and a ratio of proved developed and producing reserves to secured debt of not less than 1.0 to 1.0, each as of the last day of any fiscal quarter commencing with the fiscal quarter ending December 31, 2014; and

(ii) commencing with the fiscal quarter ending March 31, 2016, a leverage ratio (secured net debt to EBITDAX (as defined in the Second Lien Term Loan Agreement) with a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than 2.5 to 1.0 as of the last day of any fiscal quarter for the trailing four-quarter period then ended.

The obligations of the Company under the Second Lien Term Loan may be accelerated upon the occurrence of an Event of Default (as defined in the Second Lien Term Loan Agreement). Events of Default are substantially similar to Events of Default under the Credit Agreement (except that a breach of a financial covenant under the Credit Agreement will not constitute an Event of Default under the Second Lien Term Loan Agreement until acceleration) and include customary events for these types of financings.

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In connection with the Second Lien Term Loan Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Second Lien Term Loan is unconditionally guaranteed by such restricted subsidiaries.

The foregoing summary descriptions of the New Credit Agreement and the Second Lien Term Loan Agreement do not purport to be complete and are qualified in their entirety by reference to the terms of the Credit Agreement and the Second Lien Term Loan Agreement, copies of which are filed herewith as Exhibits 10.3 and 10.4 and incorporated herein by reference.

Related Party Transactions

The following table sets forth the related party transaction activities for the three and nine months ended September 30, 2014 and 2013, respectively:

		Three Months Ended   September 30,						Nine Months Ended   September 30,
		2014			2013			2014		2013
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	820		$	623		$	1,754	$	2,069
	Equipment rental (1)	74			95			215		167
	Office space rental	—			—			36		—
	Gas gathering-trucking (1)	132			—			532		—
	MAG tank panels (1)	—			—			800		—
	Interest income from note receivable (2)	38			51			121		159
	Dividends received from Series C shares	55			73			165		165
	Unrealized gain/(loss) on investments (2)	(38		)	(24		)	123		653
Pilatus Hunter, LLC
	Airplane rental expenses (3)	49			26			207		94

__________________________________

(1) GreenHunter is an entity of which Gary C. Evans, our Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and Viking International Resources Co., Inc., wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and its affiliated companies White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.

(2) On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water.  The Company recognized an embedded derivative asset resulting from the conversion option under the convertible promissory note it received as partial consideration for the sale. The fair market value of the derivative was $83,000, and $79,000 at September 30, 2014 and December 31, 2013, respectively.  See "Note 8 - Fair Value of Financial Instruments" for additional information. The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long-term assets and an available for sale investment in GreenHunter included in investments. 

(3) We rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans.  Airplane rental expenses are recorded in general and administrative expense.

In connection with and as part of the consideration of the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water. 

As of September 30, 2014, Mr. Evans, the Company's Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Hunter Holdings. On October 3, 2014, in connection with the New LLC Agreement, these Class A Common Units were converted into Series A-1 Common Units.

Commitments and Contractual Obligations

Commitments for Firm Transportation

Throughout 2014, Triad Hunter's natural gas production has been constrained to deliveries into an over-supplied market in Appalachia, where natural gas is trading at a significant discount to the Henry Hub Natural Gas spot price ("Henry Hub"). Triad

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Hunter has been exploring alternative natural gas transportation routes for delivery into markets where natural gas supply is more tempered with respect to demand. By accessing such markets, Triad Hunter expects the differential between Henry Hub pricing and our realized price for natural gas to narrow.

On August 18, 2014, the Company, through its subsidiary Triad Hunter, executed a Precedent Agreement for Texas Gas Transmission LLC's ("TGT") Northern Supply Access Line (the "TGT Transportation Services Agreement"). In executing the TGT Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation. The term of the TGT Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to be in early 2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement ("FTA") is contingent upon TGT receiving appropriate approvals from the Federal Energy Regulatory Commission ("FERC") for their pipeline project. Upon executing an FTA, the Company will have minimum annual contractual obligations for reservation charges of approximately $12.8 million over the 15 year term of the agreement.

Additionally, on October 8, 2014, Triad Hunter, LLC and Rockies Express Pipeline LLC ("REX") executed a Precedent Agreement (the "REX Transportation Services Agreement") for the delivery by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter. In executing the REX Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation from REX. The term of the REX Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to be between mid-2016 and mid-2017, and will end 15 years thereafter. The execution of an FTA is contingent upon REX receiving appropriate approvals from FERC for their pipeline project. Upon executing an FTA, the Company will have minimum annual contractual obligations for reservation charges of approximately $16.4 million over the 15 year term of the agreement.

Triad Hunter is required to provide credit support to TGT and REX under the provisions of their respective agreements, which may include letters of credit or specified cash prepayments. In November 2014, Triad Hunter is required to post an approximate $37 million letter of credit in accordance with the provisions of the REX Transportation Services Agreement. Additionally, in October 2015, Triad Hunter will be required to begin posting letters of credit of approximately $13 million, escalating thereafter up to $65 million in December 2016.

Triad Hunter is currently engaged in discussions with various third parties that have expressed an interest in executing an asset management agreement ("AMA"). If such an AMA is negotiated and executed with a third party asset manager, we expect that, subject to counterparty consent, the third party asset manager would immediately step into Triad Hunter's credit obligations with TGT and REX, would purchase Triad Hunter's natural gas at specified delivery points and negotiated prices, and would manage and schedule all of Triad Hunter's transportation agreements.

These agreements with TGT and REX will provide alternative routes for delivery of Triad Hunter's natural gas production into markets where there is not a surplus in supply, and is expected to improve the margins on natural gas production. Additionally, the Company is required under these agreements to provide prepayments or letters of credit to TGT and REX, as discussed above, as a result of Triad Hunter not meeting their respective credit requirements. These prepayments and/or letters of credit are required to demonstrate the Company's ability to pay the monthly reservation charges to REX and TGT upon completion and the entry into service of the respective pipeline extension projects.

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The following table presents our contractual obligations as of September 30, 2014:

Contractual Obligations	Total		2014		2015 -2016		2017 - 2018		After 2018
Long-term debt (1)	$	961,148	$	2,565	$	272,444	$	83,107	$	603,032
Interest on long-term debt (2)	360,903		17,931		136,461		121,213		85,298
Gas transportation and compression contracts (3)	28,527		1,414		10,348		6,043		10,722
Asset retirement obligations (4)	26,658		1,199		1,460		6,725		17,274
Commodity derivative liabilities (5)	114		48		66		—		—
Operating lease obligations	1,347		312		734		248		53
Drilling rig installments	5,200		—		5,200		—		—
Total	$	1,383,897	$	23,469	$	426,713	$	217,336	$	716,379

No dividends on preferred securities issued by the Company and Eureka Hunter Holdings have been included in the table above because the total amounts to be paid are not determinable. See "Note 12 - Shareholders' Equity" and "Note 13 - Redeemable Preferred Stock" to our consolidated financial statements for further details regarding our obligations to preferred shareholders.

________________________________

(1) See "Note 10 - Debt", to the Company’s consolidated financial statements.

(2) Interest payments have been calculated by applying the interest rate in effect as of September 30, 2014 on the debt facilities in place as of September 30, 2014. This results in a weighted average interest rate of 7.46%.

(3) Gas transportation and compression contracts do not include the commitments for firm transportation with TGT and REX as discussed above because the FTA's have not been signed. The execution of each FTA is contingent upon TGT and REX receiving appropriate approvals from FERC.

(4) See "Note 7 - Asset Retirement Obligations" to our consolidated financial statements for a discussion of our asset retirement obligations.

(5) See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Note 9 - Financial Instruments and Derivatives" to our consolidated financial statements for additional information regarding the Company’s derivative obligations.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2014, the off-balance sheet arrangements and transactions that we have entered into include operating lease agreements and commitments to purchase firm transportation from third parties.  We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Critical Accounting Policies and Estimates

For disclosure regarding our critical accounting policies and estimates, see the discussion under the caption "Critical Accounting Policies and Estimates" in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2013, as amended.

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. See Note 1 - "General - Recently Issued Accounting Standards" to the consolidated financial statements included in Part I, Item 1 (Financial Statements (unaudited)) of this Quarterly Report on Form 10-Q.

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The Company's primary market risks are attributable to energy prices, interest rates, and market prices for publicly traded equity instruments. These risks can affect revenues and cash flow from operating, investing, and financing activities.

The Company's risk-management policies provide for the use of derivative instruments to manage commodity price risks. We may enter into financial swaps and collars to reduce the risk of commodity price fluctuations, but do not designate such instruments as cash flow hedges. For additional information related to the Company's financial instruments and derivatives, see "Note 9 - Financial Instruments and Derivatives".

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Commodity Price Risk

The Company's most significant market risk relates to prices for natural gas, crude oil, and NGL. Recent declines in market prices for natural gas, crude oil, and NGL have resulted in lower realized prices for the Company's production during the three month period ended September 30, 2014. Further declines could impact the extent to which the Company develops portions of its proved and unproved oil and natural gas properties, and may include temporarily shutting in certain wells that are uneconomic to produce. Given the current economic outlook, we expect 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 the carrying value of our oil and natural gas properties.

As of September 30, 2014, the Company had derivative instruments in place to reduce the price risk associated with future production of 16.1 Bcf of natural gas and 0.5 MMBbls of crude oil, representing a gross asset of $2.8 million and a gross liability of $0.8 million; or a net liability of $2.0 million. The table below shows the impact that a 10% increase or decrease in underlying commodity price index would have on the fair value of derivative instruments as of September 30, 2014:

	As of September 30, 2014
	Fair Value As Reported		Fair Value: 10% Price Increase			Fair Value: 10 % Price Decrease
	(in thousands)
Gas	$	1,965	$	(3,624	)	$	7,646
Crude oil	47		(1,986		)	2,429
Total Fair Value	$	2,013	$	(5,610	)	$	10,075
Change in Fair Value			$	(7,622	)	$	8,062

Any realized derivative gains or losses, however, would be substantially offset by the realized sales value of production covered by the derivative instruments.

At September 30, 2014, we had the following commodity derivative positions outstanding:

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Collars (1)	Oct 2014- Dec 2014	15,000	$4.27 - $5.23
Swaps	Oct 2014 - Dec 2014	41,000	$4.18
	Jan 2015 - Dec 2015	30,000	$4.12
Ceilings purchased (call)	Oct 2014 - Dec 2014	16,000	$5.91
Ceilings sold (call)	Oct 2014 - Dec 2014	16,000	$5.91
			Weighted Average
Crude Oil	Period	Bbls/day	Price per Bbl
Collars (1)	Oct 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collars (2)	Oct 2014 - Dec 2014	4,000	$64.94 - $85.00 - $102.50
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Oct 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00

______________________________

(1) A collar is a sold call and a purchased put. Some collars are "costless" collars with the premiums netting to approximately zero.

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

At September 30, 2014, the fair value of our open commodity derivative contracts was a liability of $2.0 million.

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The following table summarizes the gains and losses on settled and open commodity derivative contracts for the three and nine months ended September 30, 2014 and 2013:

	Three Months Ended   September 30,					Nine Months Ended   September 30,
	2014		2013			2014			2013
	(in thousands)
Gain (loss) on settled transactions	$	477	$	(6,582	)	$	(4,074	)	$	(6,887	)
Gain (loss) on open transactions	8,019		(7,629		)	3,737			(2,764		)
Total gain (loss)	$	8,496	$	(14,211	)	$	(337	)	$	(9,651	)

See "Note 9 - Financial Instruments and Derivatives" in the accompanying consolidated financial statements for additional information on derivative instruments.

Interest Rate Risk

Any borrowings under the MHR Senior Revolving Credit Facility and the Eureka Hunter Pipeline Credit Agreement are subject to variable interest rates. The balance of the Company's long-term debt on the Company's consolidated balance sheet is subject to fixed interest rates. A 10% increase or decrease in interest rates would increase or decrease interest expense by approximately $2.4 million and $704,000 for the three and nine months ended September 30, 2014, respectively.

Financial Instrument Price Risk

We have investments in both publicly-traded and non-publicly-traded financial instruments. Our ability to divest of these instruments is a function of overall market liquidity which is impacted by, among other things, the amount of outstanding securities of a particular issuer, trading history of the issuer, overall market conditions, and entity-specific facts and circumstances that impact a particular issuer. As a result, market volatility and overall financial performance and liquidity of the issuer could result in significant fluctuations in the fair value of these instruments, and we may be unable to recover the full cost of these investments. A 10% increase or decrease in market prices for our marketable securities would increase or decrease fair value by $0.8 million.

Eureka Hunter Holdings, a majority owned subsidiary, has issued Eureka Hunter Holdings Series A Preferred Units which have embedded conversion and redemption options to the holder. As a result of these embedded features we recognize, as a liability, the fair value of the conversion and redemption options as a derivative liability in our consolidated financial statements. The fair value of these derivative instruments are impacted primarily by the total enterprise value of Eureka Hunter Holdings and the implied volatility of the instruments. As of September 30, 2014, the fair value of the liability associated with these embedded features was $173.2 million. The table below shows the impact that a 5% change in either input would have on the fair value of these liabilities as of September 30, 2014:

	As of September 30, 2014
	Fair Value: Increase of 5%		Fair Value: Decrease of 5%
	(in thousands)
Total enterprise value	$	172,215	$	174,255
Volatility	$	172,740	$	173,680

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Item 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

The Company's management, including the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), performed an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of September 30, 2014. The Company's disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted 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.

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Based upon that evaluation, the CEO and CFO concluded that, as a result of the material weaknesses in internal control over financial reporting that are described in Item 9A our Annual Report on Form 10-K for the year ended December 31, 2013, the Company's disclosure controls and procedures were not effective as of September 30, 2014.

Management's Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process, under the supervision of the CEO and CFO, designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management conducts regular periodic evaluations of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework). A material weakness is defined as a deficiency, or a combination of 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 by our internal controls.

Our Annual Report on Form 10-K for the year ended December 31, 2013 identified three material weaknesses in internal control over financial reporting and a remediation plan to resolve those material weaknesses.

As of September 30, 2014, management continues to implement and execute upon its remediation plan with respect to the material weaknesses identified in our Annual Report on Form 10-K for the year ended December 31, 2013, as amended.

Management’s Plan for Remediation of Material Weaknesses

The Board of Directors, the Audit Committee, and senior management of the Company understand their responsibility to provide the appropriate direction and oversight governance to ensure the Company achieves effective and comprehensive internal control over financial reporting.  

Preparation and Review of Account Reconciliations

During 2014, management has continued to reorganize roles and responsibilities over the general accounting and financial reporting process in an effort to establish and maintain effective and sustainable controls. In addition, the Company implemented an account reconciliation software tool in 2013 to enable the tracking, monitoring and evidencing of balance sheet account reconciliations. The improvement in processes is continuing as management has implemented procedures to monitor the timely performance of internal controls over reconciliations.

Leasehold Property Costs

Management will continue the process of maintaining controls over leases in order to improve the completeness, accuracy, and reporting of the data.  Controls over maintenance of lease records will include authorization for updates to lease files, prevention of unauthorized access to or alteration of data and adequate support for and reconciliation of subsidiary property records.  Additional

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processes and controls will be implemented to address completeness and accuracy of and review transfers of leasehold property costs.

Tax

The Company has a dedicated full-time tax manager and director and engaged a consulting firm to provide advisory services on tax matters. A remediation plan and time-line has been put in place and management is monitoring the Company's remediation efforts.  Specifically, management has developed detailed procedures to ensure tax provisions and disclosures are properly reflected in the financial statements.

Under the direction of the CEO and CFO reporting to the Audit Committee of the Board of Directors, management will continue to take the necessary steps to improve the effectiveness of internal control over financial reporting.

This quarterly report does not include an attestation report of our registered independent public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered independent public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this quarterly report.

Changes in Internal Control over Financial Reporting

There were no material changes in our internal control over financial reporting that occurred during the three months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting with the exception of the remediations noted above.

PART II.  OTHER INFORMATION

Item 1.        Legal Proceedings.

Information required to be furnished in this Part II, Item 1 (Legal Proceedings) is incorporated by reference to Note 16 - "Commitments and Contingencies - Legal Proceedings" to the Consolidated Financial Statements included in Part I, Item 1 (Financial Statements (unaudited)) of this Quarterly Report on Form 10-Q.

Item 1A. Risk Factors.

There are restrictive covenants, governance and other provisions in the New LLC Agreement that may restrict our ability to pursue our business strategies with respect to our midstream operations.

The New LLC Agreement contains certain covenants that, among other things, restrict the ability of Eureka Hunter Holdings and its subsidiaries to, with certain exceptions:

• issue additional equity interests;

• pay distributions to its owners, or repurchase or redeem any of its equity securities;

• incur indebtedness;

• modify, amend or terminate material contracts;

• make any material acquisitions, dispositions or divestitures; or

• enter into a sale, merger, consolidation or other change of control transaction.

Further, pursuant to the terms of the New LLC Agreement, the number and composition of the board of managers of Eureka Hunter Holdings may change over time based on MSI’s percentage ownership interest in Eureka Hunter Holdings or the failure of Eureka Hunter Holdings to satisfy certain performance standards on and after December 31, 2018. Currently, the board of managers of Eureka Hunter Holdings is composed of a majority of members appointed by Magnum Hunter. Following the subsequent sale by Magnum Hunter to MSI of additional common equity interests in Eureka Hunter that is expected to occur in mid-January 2015 (the “Second Closing”), or if the Second Closing does not occur (other than due to MSI’s breach of its obligation under the Transaction Agreement to purchase such additional equity interest), MSI can designate one additional manager for the duration of the New LLC Agreement. As a result, the board of managers of Eureka Hunter Holdings will in the future be composed of an equal number of managers appointed by Magnum Hunter and MSI and, in certain cases, may be comprised of a majority of managers appointed by MSI.

The New LLC Agreement also allows MSI, as the holder of the Series A-2 Units, to initiate a “Qualified Public Offering” of securities of Eureka Hunter Holdings at any time, so long as MSI holds at least a 20% equity interest in Eureka Hunter Holdings. A Qualified Public Offering means an underwritten initial public offering of securities of Eureka Hunter Holdings for which

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aggregate cash proceeds to be received by Eureka Hunter Holdings from such offering are at least $25 million and which results in equity securities of Eureka Hunter Holdings being listed on a national securities exchange.

The New LLC Agreement also contains transfer restrictions on Magnum Hunter’s ownership interests in Eureka Hunter Holdings (subject to certain exceptions) and certain “drag-along” and “tag-along” rights in favor of MSI.

These restrictive covenants, governance and other provisions may restrict our ability to pursue our business strategies with respect to our midstream operations.

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

None.

Item 3.         Defaults upon Senior Securities

None.

Item 4.         Mine Safety Disclosures

Not applicable.

Item 5.         Other Information

None.

Item 6.        Exhibits

See list of exhibits in the Index to this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

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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 7, 2014		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman and Chief Executive Officer
Date: November 7, 2014		/s/ Joseph C. Daches
		Joseph C. Daches,
		Senior Vice President and Chief
		Financial Officer

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INDEX TO EXHIBITS

Exhibit Number	Description
2.1	Purchase and Sale Agreement, dated September 29, 2014, entered into on September 30, 2014, between Bakken Hunter, LLC and LGFE-BH L.P. (incorporated by reference from the Registrant's Current Report on Form 8-K filed on October 6, 2014).
2.2	Purchase and Sale Agreement, dated October 9, 2014, by and between Bakken Hunter, LLC and SM Energy Company (incorporated by reference from the Registrant's Current Report on Form 8-K filed on October 14, 2014).
10.1	Transaction Agreement, dated September 15, 2014 (entered into on September 16, 2014), by and among Eureka Hunter Holdings, LLC, Magnum Hunter Resources Corporation, MSIP II Buffalo Holdings LLC and, for certain limited purposes, Magnum Hunter Services, LLC (incorporated by reference from the Registrant's Current Report on Form 8-K filed on September 22, 2014).
10.2	Second Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings, LLC, dated October 3, 2014, by and among Eureka Hunter Holdings, LLC, Magnum Hunter Resources Corporation, MSIP II Buffalo Holdings LLC, and certain other limited liability company members (incorporated by reference from the Registrant's Current Report on Form 8-K filed on October 9, 2014).
10.3	Fourth Amended and Restated Credit Agreement, dated October 22, 2014, by and among Magnum Hunter Resources Corporation, Bank of Montreal, the lenders party thereto and the agents party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on October 28, 2014).
10.4	Second Lien Term Loan Agreement, dated October 22, 2014, by and among Magnum Hunter Resources Corporation, Credit Suisse AG, Cayman Islands Branch, the lenders party thereto and the agents party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on October 28, 2014).
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	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.^
#	Filed herewith.
@	This exhibit is furnished herewith and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

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^ These exhibits are furnished herewith. In accordance with Rule 406T of Regulation S-T, these exhibits are not deemed to be filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are not deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

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