Magnum Hunter Resources 10-Q 2014 Q1 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 March 31, 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 May 8, 2014, there were 177,331,298 shares of the registrant’s common stock ($0.01 par value) outstanding.

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED March 31, 2014

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited):
Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	1
Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013	3
Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2014 and 2013	4
Consolidated Statement of Shareholders’ Equity for the Three Months Ended March 31, 2014	5
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	6
Notes to Consolidated Financial Statements	7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3. Quantitative and Qualitative Disclosures About Market Risk	58
Item 4. Controls and Procedures	61
Part II. OTHER INFORMATION	62
Item 1. Legal Proceedings	62
Item 1A. Risk Factors	62
Item 3. Defaults Upon Senior Securities	62
Item 5. Other Information	62
Item 6. Exhibits	62
SIGNATURES	63

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

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

(unaudited)

	March 31, 2014		December 31, 2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	64,452	$	41,713
Restricted cash	5,000		5,000
Accounts receivable:
Oil and natural gas sales	28,698		25,099
Joint interests and other, net of allowance for doubtful accounts of $101 at March 31, 2014 and $196 at December 31, 2013	34,010		30,582
Derivative assets	35		608
Inventory	4,052		7,158
Investments	11,436		2,262
Prepaid expenses and other assets	3,471		2,938
Assets held for sale	5,018		5,366
Total current assets	156,172		120,726
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting, net	1,221,298		1,224,659
Gas transportation, gathering and processing equipment and other, net	317,187		289,420
Total property, plant and equipment, net	1,538,485		1,514,079
OTHER ASSETS
Deferred financing costs, net of amortization of $9,511 at March 31, 2014 and $9,735 at December 31, 2013	17,738		20,008
Derivative assets, long-term	585		25
Intangible assets, net	6,029		6,530
Goodwill	30,602		30,602
Assets held for sale	142,349		162,687
Other assets	1,893		1,994
Total assets	$	1,893,853	$	1,856,651

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

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MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS (Continued)

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

(unaudited)

	March 31, 2014			December 31, 2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Current portion of notes payable	$	5,372		$	3,804
Accounts payable	136,740			107,837
Accounts payable to related parties	451			23
Accrued liabilities	68,245			44,629
Revenue payable	11,317			6,313
Derivative liabilities	5,276			1,903
Liabilities associated with assets held for sale	20,159			12,865
Other liabilities	2,456			6,491
Total current liabilities	250,016			183,865
NONCURRENT LIABILITIES
Long-term debt	891,534			876,106
Asset retirement obligations	16,546			16,163
Derivative liabilities, long-term	72,611			76,310
Other long-term liabilities	2,218			2,279
Long-term liabilities associated with assets held for sale	12,983			14,523
Total liabilities	1,245,908			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 March 31, 2014 and December 31, 2013, respectively, with 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, 10,182,540 and 9,885,048 issued and outstanding as of March 31, 2014 and December 31, 2013, respectively, with liquidation preference of $206,520 and $200,620 as of March 31, 2014 and December 31, 2013, respectively	142,275			136,675
	242,275			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 March 31, 2014 and December 31, 2013, respectively, with 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 March 31, 2014 and December 31, 2013, respectively, with 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 177,331,297 and 172,409,023 issued, and 176,416,345 and 171,494,071 outstanding as of March 31, 2014 and December 31, 2013, respectively	1,773			1,724
Additional paid in capital	767,645			733,753
Accumulated deficit	(662,853		)	(586,365		)
Accumulated other comprehensive loss	(22,305		)	(19,901		)
Treasury Stock, at cost:
Series E Preferred Stock, 81 shares as of March 31, 2014 and December 31, 2013	(2,030		)	(2,030		)
Common stock, 914,952 shares as of March 31, 2014 and December 31, 2013	(1,914		)	(1,914		)
Total Magnum Hunter Resources Corporation shareholders’ equity	396,629			441,580
Non-controlling interest	9,041			9,150
Total shareholders’ equity	405,670			450,730
Total liabilities and shareholders’ equity	$	1,893,853		$	1,856,651

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

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MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

	Three Months Ended   March 31,
	2014			2013
REVENUES AND OTHER
Oil and natural gas sales	$	70,172		$	34,641
Natural gas transportation, gathering, processing, and marketing	31,649			15,896
Oilfield services	5,621			3,693
Other revenue	2			4
Total revenue	107,444			54,234
OPERATING EXPENSES
Lease operating expenses	19,956			7,668
Severance taxes and marketing	5,574			2,832
Exploration	14,029			29,733
Natural gas transportation, gathering, processing, and marketing	29,999			13,431
Oilfield services	3,947			3,335
Depletion, depreciation, amortization and accretion	29,408			17,288
Loss (gain) on sale of assets, net	3,459			(19		)
General and administrative	15,272			19,977
Total operating expenses	121,644			94,245
OPERATING LOSS	(14,200		)	(40,011		)
OTHER INCOME (EXPENSE)
Interest income	45			57
Interest expense	(23,849		)	(18,701		)
Gain (loss) on derivative contracts, net	347			(7,491		)
Other expense	(244		)	(216		)
Total other expense, net	(23,701		)	(26,351		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(37,901		)	(66,362		)
Income tax benefit	—			4,899
LOSS FROM CONTINUING OPERATIONS, NET OF TAX	(37,901		)	(61,463		)
Income from discontinued operations, net of tax	3,362			16,763
Loss on disposal of discontinued operations, net of tax	(27,162		)	—
NET LOSS	(61,701		)	(44,700		)
Net loss attributed to non-controlling interests	109			503
LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	(61,592		)	(44,197		)
Dividends on preferred stock	(14,896		)	(13,488		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(76,488	)	$	(57,685	)
Weighted average number of common shares outstanding, basic and diluted	172,146,431			169,624,616
Loss from continuing operations per share, basic and diluted	$	(0.30	)	$	(0.44	)
Income from discontinued operations per share, basic and diluted	(0.14		)	0.10
NET LOSS PER COMMON SHARE, BASIC AND DILUTED	$	(0.44	)	$	(0.34	)
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
Loss from continuing operations, net of tax	$	(37,792	)	$	(60,960	)
Income (loss) from discontinued operations, net of tax	(23,800		)	16,763
Net loss	$	(61,592	)	$	(44,197	)

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

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MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)

(in thousands)

	Three Months Ended   March 31,
	2014			2013
NET LOSS	$	(61,701	)	$	(44,700	)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation loss	(2,348		)	(4,729		)
Unrealized loss on available for sale investments	(56		)	(17		)
Total other comprehensive income (loss)	(2,404		)	(4,746		)
COMPREHENSIVE LOSS	(64,105		)	(49,446		)
Comprehensive loss attributable to non-controlling interests	109			503
COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	$	(63,996	)	$	(48,943	)

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

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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			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	—	—	25	—		—		—		1,061		—			—			—			—			1,061
Sale of common stock	—	—	4,300	—		—		43		28,854		—			—			—			—			28,897
Dividends on preferred stock	—	—	—	—		—		—		—		(14,896		)	—			—			—			(14,896		)
Shares of common stock issued upon exercise of common stock options	—	—	597	—		—		6		3,977		—			—			—			—			3,983
Net loss	—	—	—	—		—		—		—		(61,592		)	—			—			(109		)	(61,701		)
Foreign currency translation	—	—	—	—		—		—		—		—			(2,348		)	—			—			(2,348		)
Unrealized loss on available for sale securities, net	—	—	—	—		—		—		—		—			(56		)	—			—			(56		)
BALANCE, March 31, 2014	4,425	4	177,331	$	221,244	$	95,069	$	1,773	$	767,645	$	(662,853	)	$	(22,305	)	$	(3,944	)	$	9,041		$	405,670

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

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MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)

	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(61,701	)	$	(44,700	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	29,408			35,092
Exploration	13,712			29,353
Share-based compensation	1,061			6,250
Cash paid for plugging wells	(22		)	—
Loss (gain) on sale of assets	31,238			(19		)
Unrealized (gain) loss on derivative contracts	(2,631		)	8,447
Unrealized loss on investments	246			606
Amortization and write-off of deferred financing costs and discount on Senior Notes included in interest expense	3,621			857
Deferred tax benefit	—			(4,854		)
Changes in operating assets and liabilities:
Accounts receivable, net	(7,828		)	(2,865		)
Inventory	3,246			(506		)
Prepaid expenses and other current assets	(562		)	(269		)
Accounts payable	(26,020		)	30,115
Revenue payable	4,841			5,580
Accrued liabilities	15,268			14,534
Net cash provided by operating activities	3,877			77,621
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and advances	(39,127		)	(144,534		)
Change in deposits and other long-term assets	(107		)	57
Proceeds from sales of assets	16,415			40
Net cash used in investing activities	(22,819		)	(144,437		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from sale of common shares	28,897			—
Net proceeds from sale of preferred shares	—			10,264
Equity issuance costs	—			(109		)
Proceeds from sale of Eureka Hunter Holdings Series A Preferred Units	3,920			—
Proceeds from exercise of warrants and options	3,983			—
Preferred stock dividend	(10,770		)	(9,657		)
Repayments of debt	(84,683		)	(993		)
Proceeds from borrowings on debt	101,616			101,366
Deferred financing costs	(1,331		)	(445		)
Change in other long-term liabilities	24			(36		)
Net cash provided by financing activities	41,656			100,390
Effect of changes in exchange rate on cash	25			(21		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	22,739			33,553
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	41,713			57,623
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	64,452		$	91,176

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

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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 acquisition and development of producing properties and undeveloped acreage and the production of oil and natural gas, in the United States and Canada, along with certain midstream and oil field 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 55.79% as of March 31, 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, the Company's subsidiary, PRC Williston, LLC ("PRC Williston"), in which the Company owns 87.5%, sold substantially all of its assets. The consolidated financial statements also reflect the interests of Magnum Hunter Production, Inc. ("MHP") in various managed drilling partnerships. The Company accounts for the interests in these partnerships using the proportionate consolidation method.

Reclassification of Prior-Year Balances

Certain prior period balances have been reclassified to correspond with current-year presentation.  As a result of the Company's adoption of a plan in September 2013 to dispose of certain of its U.S. and Canadian properties, operating income and expenses related to these operations have been classified as discontinued operations for all periods presented. See "Note 2 - Divestitures and Discontinued Operations". 

Regulated Activities

Energy Hunter Securities, Inc. is a 100%-owned subsidiary and is a registered broker-dealer and member of the Financial Industry Regulatory Authority. Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended. Because it does not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities, Inc. is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness. At March 31, 2014 and December 31, 2013, Energy Hunter Securities, Inc. had net capital of $90,610 and $77,953, respectively, and aggregate indebtedness of $4,000 and $16,657, respectively.

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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 ASC 980-605, Regulated Operations-Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. During the three months ended March 31, 2014, the Company had gas transmission, compression and processing revenue, reported in income from discontinued operations, which included gas utility sales from Sentra Corporation's regulated operations aggregating to $171,072. During the three months ended March 31, 2013, the Company had no revenues 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 July 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 Accounting Standards Codification ("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 March, 2013, the FASB issued 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 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 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.

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NOTE 2 - DIVESTITURES AND DISCONTINUED OPERATIONS

Discontinued Operations

Planned Divestitures of Magnum Hunter Production and Williston Hunter Canada

In September 2013, the Company adopted a plan to divest all of its interests in (i) Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of the Company 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"), a wholly-owned subsidiary of the Company.

On April 10, 2014, the Company, through WHI Canada, closed on the sale of a portion of its interests in oil and natural gas properties and related assets in Alberta, Canada which were classified as held for sale at March 31, 2014 and December 31, 2013. On April 22, 2014, the Company entered into a definitive agreement to sell 100% of its ownership interest in WHI Canada. See "Note 20 - Subsequent Events". The Company is actively marketing its interests in MHP and anticipates entering into a purchase and sale agreement for MHP by the end of the second quarter of 2014. The Company has classified the associated assets and liabilities of MHP and WHI Canada to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented.

During the year ended December 31, 2013, the Company recorded an impairment expense of $92.4 million to record MHP and WHI Canada at their estimated selling price less costs to sell. Based upon additional information on estimated selling prices obtained through active marketing of the assets, the Company has recorded an additional impairment expense of $22.8 million for the three months ended March 31, 2014 to reflect the net assets at their estimated selling prices, less costs to sell, which is recorded in loss on disposal of discontinued operations for the three months ended March 31, 2014.

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

	March 31, 2014		December 31, 2013
	(in thousands)
Accounts receivable	$	3,947	$	4,362
Other current assets	1,071		1,004
Oil and natural gas properties, net	127,068		150,770
Gas transportation, gathering, and processing equipment and other, net	15,099		11,721
Other long-term assets	182		196
Total assets held for sale	$	147,367	$	168,053
Accounts payable	$	10,215	$	7,292
Accrued expenses and other liabilities	9,944		5,573
Asset retirement obligations	8,485		8,678
Other long-term liabilities	4,498		5,845
Total liabilities held for sale	$	33,142	$	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 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. The Company has recognized a preliminary gain on the sale of $172.5 million, net of tax, pending final working capital adjustments. The Company and Penn Virginia have been unable to agree upon the final settlement of the working capital adjustments and the disagreement has been submitted to arbitration. The Company is currently awaiting the ruling of the arbitrator.

As of March 31, 2014, the Company estimated that the final working capital adjustment is a reduction to the preliminary gain recognized in 2013 ranging from $22 million to $33 million, net of tax.  The Company has recorded a liability for its revised

9

estimate of the final adjustment, and has recorded the impact to earnings as a reduction to the gain on disposal of discontinued operations.

The Company included the results of operations of MHP and WHI Canada for all periods presented, and Eagle Ford Hunter through March 31, 2013, in discontinued operations as follows:

	Three Months Ended   March 31,
	2014			2013
	(in thousands)
Revenues	$	12,283		$	43,790
Expenses	(8,833		)	(28,225		)
Other income (expense)	(88		)	1,243
Income tax expense	—			(45		)
Income from discontinued operations, net of tax	3,362			16,763
Loss on sale of discontinued operations, net of taxes	(27,162		)	—
Income from discontinued operations, net of taxes	$	(23,800	)	$	16,763

Other Divestitures

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 its 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, four of which wells 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 represent approximately 17% of the total shares outstanding of NSE at January 28, 2014, and have been designated as available-for-sale securities, which are carried at fair value (See "Note 8 - Fair Value of Financial Instruments"). The Company recognized a loss on the sale of these assets of $4.5 million.

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, Shale Hunter will provide NSE Texas with certain transitional services relating to the assets sold for which it will receive 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 to $232.5 million as of the closing date.

NOTE 3 - OIL & NATURAL GAS SALES

During the three months ended March 31, 2014 and 2013, the Company recognized sales from oil, natural gas, and natural gas liquids ("NGLs") as follows:

	Three Months Ended March 31,
	2014		2013
	(in thousands)
Oil	$	34,272	$	25,572
Natural gas	24,130		8,453
NGLs	11,770		616
Total oil and natural gas sales	$	70,172	$	34,641

10

NOTE 4 - PROPERTY, PLANT, & EQUIPMENT

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:

	March 31, 2014			December 31, 2013
	(in thousands)
Mineral interests in properties:
Unproved leasehold costs	$	455,772		$	469,337
Proved leasehold costs	335,124			336,357
Wells and related equipment and facilities	570,133			536,023
Advances to operators for wells in progress	12,388			13,571
Total costs	1,373,417			1,355,288
Less accumulated depletion, depreciation, and amortization	(152,119		)	(130,629		)
Net capitalized costs	$	1,221,298		$	1,224,659

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. No impairments of proved property were recorded during the three months ended March 31, 2014 or 2013.

Depletion, depreciation, and amortization expense for proved oil and natural gas properties was $23.9 million and $13.0 million for the three months ended March 31, 2014 and 2013, respectively.

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 months ended March 31, 2014 and 2013, the Company recognized exploration expense as follows:

	Three Months Ended   March 31,
	2014		2013
	(in thousands)
Leasehold impairments	$	13,655	$	29,353
Geological and geophysical	374		380
Total exploration expense	$	14,029	$	29,733

Leasehold impairment expense recorded by the Company during the three months ended March 31, 2014 consisted of $11.1 million in the U.S. Upstream segment related to leases in the Williston Basin that expired undrilled during the period or are expected to expire that the Company does not plan to develop, and $2.6 million related to leases in the Appalachian Basin. Leasehold impairment expense of $29.4 million during the three months ended March 31, 2013 primarily related to leases in the Williston Basin.

Capitalized Costs Greater Than a Year

As of March 31, 2014, the Company had no suspended exploratory well costs capitalized for periods greater than one year.

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 March 31, 2014 and December 31, 2013 is summarized as follows:

11

	March 31, 2014			December 31, 2013
	(in thousands)
Gas transportation, gathering and processing equipment and other	$	347,995		$	315,642
Less accumulated depreciation	(30,808		)	(26,222		)
Net capitalized costs	$	317,187		$	289,420

Depreciation expense for gas transportation, gathering, and processing equipment and other property was $4.7 million and $3.2 million for the three months ended March 31, 2014 and 2013, respectively.

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 March 31, 2014 had a net carrying value of $11.6 million, and the terms of such leases provide for future lease payments to the Company extending up to August 2016.  As of March 31, 2014, primarily all the leases to third parties were non-cancelable, with future minimum aggregate base rentals payable to the Company of $3.3 million over the twelve months ending March 31, 2015 and $1.1 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:

	March 31,			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	(4,463		)	(3,962		)
Intangible assets, net of accumulated amortization	$	6,029		$	6,530

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 March 31, 2014 and December 31, 2013, the frac sand inventory is anticipated to be entirely used 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:

	March 31, 2014		December 31, 2013
	(in thousands)
Materials and supplies	$	3,647	$	6,790
Commodities	405		368
Inventory	$	4,052	$	7,158

12

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

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

	March 31, 2014			December 31, 2013
	(in thousands)
Asset retirement obligation at beginning of period	$	16,216		$	30,680
Assumed in acquisitions	—			17
Liabilities incurred	52			253
Liabilities settled	(17		)	(98		)
Liabilities sold	(12		)	(7,614		)
Accretion expense	368			2,264
Revisions in estimated liabilities (1)	—			1,935
Reclassified as liabilities associated with assets held for sale	—			(11,148		)
Effect of foreign currency translation	—			(73		)
Asset retirement obligation at end of period	16,607			16,216
Less: current portion (included in other liabilities)	(61		)	(53		)
Asset retirement obligation at end of period	$	16,546		$	16,163

________________________________

 (1)$1.5 million of the revisions in estimated liabilities is related to change in assumptions used with respect to certain wells in the Williston Basin in North Dakota during 2013.

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 (See "Note 2 - Divestitures and Discontinued Operations"). 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 March 31, 2014.

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

13

Level 1 Classification:

Available for Sale Securities

At March 31, 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. See "Note 9 - Financial Instruments and Derivatives".

Level 3 Classification:

Preferred Stock Embedded Derivative

At March 31, 2014 and December 31, 2013, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of its Eureka Hunter Holdings Series A Preferred Units. See "Note 13 - Redeemable Preferred Stock".

The fair value of the bifurcated conversion feature was valued using the “with and without” analysis in a simulation model. The key assumptions used in the model to determine fair value at March 31, 2014 were a volatility of 25%, credit spread of 12.9%, and a total enterprise value of Eureka Hunter Holdings of $578.0 million.

The fair value calculation is sensitive to movements in volatility and the total enterprise value of Eureka Hunter Holdings. 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 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:

	March 31, 2014
Life	2.9 years
Risk-free interest rate	0.96		%
Estimated volatility	40		%
Dividend	—
GreenHunter stock price at end of period	$	0.96

14

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
	March 31, 2014
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	11,210	$	—	$	—
Commodity derivative assets	—		585		—
Convertible security derivative assets	—		—		35
Total assets at fair value	$	11,210	$	585	$	35
Liabilities
Commodity derivative liabilities	$	—	$	5,571	$	—
Convertible preferred stock derivative liabilities	—		—		72,316
Total liabilities at fair value	$	—	$	5,571	$	72,316

	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

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 three-month period ended March 31, 2014:

	Preferred Stock Embedded Derivative Liability			Convertible Security Embedded Derivative Asset
	(in thousands)
Fair value at December 31, 2013	$	(75,934	)	$	79
Issuance of redeemable preferred stock	(2,318		)	—
Decrease in fair value recognized in other income (expense)	5,936			(44		)
Fair value as of March 31, 2014	$	(72,316	)	$	35

15

Other Fair Value Measurements

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

		March 31, 2014				December 31, 2013
	Fair Value Hierarchy	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
		(in thousands)
Senior Notes	Level 2	$	597,251	$	666,000	$	597,230	$	651,300
MHR Senior Revolving Credit Facility	Level 3	$	226,000	$	226,000	$	218,000	$	218,000
Eureka Hunter Pipeline second lien term loan	Level 3	$	—	$	—	$	50,000	$	58,921
Eureka Hunter Pipeline Credit Agreement	Level 3	$	55,000	$	55,000	$	—	$	—
Equipment notes payable	Level 3	$	25,609	$	25,659	$	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 value of the Company's senior revolving credit facility (the “MHR Senior Revolving Credit Facility") approximates fair value as it is 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 is Level 3.

The fair value of the Eureka Hunter Pipeline Credit Agreement outstanding as of March 31, 2014 approximates the carrying value as the agreement was entered into on March 28, 2014. 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.

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 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.

NOTE 9 - FINANCIAL INSTRUMENTS AND DERIVATIVES

Investment Holdings

Below is a summary of changes in investments for the period ended March 31, 2014:

	Available for Sale Securities (1)			Equity Method Investments (2)
	(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)	—			(246		)
Change in fair value recognized in other comprehensive loss	(56		)	—
Carrying value as of March 31, 2014	$	11,210		$	694

16

⁽¹⁾ Available for sale securities includes $142,000 that has been classified as held for sale associated with the classification of the MHP subsidiary.

⁽²⁾ Equity method investments includes $326,000 classified as long-term other assets.

The Company's investments have been presented in the consolidated balance sheet as of March 31, 2014 as follows:

	Available for Sale Securities		Equity Method Investments		Total
Investments - Current	$	11,068	$	368	$	11,436
Investments - Long-Term	—		326		326
Investments - Held for Sale	142		—		142
Carrying value as of March 31,2014	$	11,210	$	694	$	11,904

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

	March 31, 2014
	(in thousands)
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Securities available for sale, carried at fair value:
Equity securities	$	9,875	$	—	$	(324	)	$	9,551
Equity securities - related party (see "Note 15 - Related Parties)	2,200		—		(541		)	1,659
Total Securities available for sale	$	12,075	$	—	$	(865	)	$	11,210

	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 industry. 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 persisted 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 March 31, 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.

17

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.

As of March 31, 2014, the Company had the following commodity derivative instruments:

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Collars (1)	April 2014- Dec 2014	5,000	$4.00 - $5.25
Swaps	April 2014 - Dec 2014	31,000	$4.23
	Jan 2015 - Dec 2015	20,000	$4.18
Ceilings purchased (call)	April 2014 - Dec 2014	16,000	$5.91
Ceilings sold (call)	April 2014 - Dec 2014	16,000	$5.91
			Weighted Average
Crude Oil	Period	Bbl/day	Price per Bbl
Collars (1)	April 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collars (2)	April 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)	April 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.

Currently, Bank of America, Bank of Montreal, KeyBank National Association, Credit Suisse Energy, LLC, Citibank, N.A., ABN AMRO, the Royal Bank of Canada, and J. Aron & Company 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.  All counterparties, or their affiliates, are participants in the MHR Senior Revolving Credit Facility, and the collateral for the outstanding borrowings under the MHR Senior Revolving Credit Facility is used as collateral for its commodity derivatives with those counterparties.

At March 31, 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. See "Note 8 - Fair Value of Financial Instruments" and "Note 13 - Redeemable Preferred Stock".

At March 31, 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," "Note 2 - Divestitures and Discontinued Operations," and "Note 15 - Related Party Transactions".

18

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	March 31, 2014		December 31, 2013		March 31, 2014			December 31, 2013
		(in thousands)
Commodity
	Derivative assets	$	—	$	529	$	—		$	—
	Derivative assets - long-term	585		25		—			—
	Derivative liabilities	—		—		(5,276		)	(1,903		)
	Derivative liabilities - long-term	—		—		(295		)	(376		)
Total commodity		$	585	$	554	$	(5,571	)	$	(2,279	)
Financial
	Derivative assets	$	35	$	79	$	—		$	—
	Derivative liabilities - long-term	—		—		(72,316		)	(75,934		)
Total financial		$	35	$	79	$	(72,316	)	$	(75,934	)
Total derivatives		$	620	$	633	$	(77,887	)	$	(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:

	March 31, 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	$	1,561		1,561		$	—
Long-term assets:  Fair value of derivative contracts	928			343		585
Current liabilities:  Fair value of derivative contracts	(6,837		)	(1,561	)	(5,276		)
Long-term liabilities:  Fair value of derivative contracts	(638		)	(343	)	(295		)
	$	(4,986	)	—		$	(4,986	)

	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	)

19

The following table summarizes the net gain (loss) on all derivative contracts included in other income (expense) on the consolidated statements of operations for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	2014			2013
	(in thousands)
Gain (loss) on settled transactions	$	(2,284	)	$	956
Gain (loss) on open transactions	2,631			(8,447		)
Total gain (loss)	$	347		$	(7,491	)

NOTE 10 - DEBT

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

	March 31, 2014			December 31, 2013
	(in thousands)
Senior Notes payable due May 15, 2020, interest rate of 9.75%, net of unamortized net discount of $2.8 million at March 31, 2014 and December 31, 2013	$	597,251		$	597,230
Various equipment and real estate notes payable with maturity dates January 2015 - April 2021, interest rates of 4.25% - 7.94%(1)	25,609			18,615
Eureka Hunter Pipeline Credit Agreement due March 28, 2018, interest rate of 5.75%	55,000			—
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 2.96% at March 31, 2014 and 3.56% at December 31, 2013	226,000			218,000
	903,860			883,845
Less: current portion	(9,986		)	(3,967		)
Total long-term debt obligations, net of current portion	$	893,874		$	879,878

 _________________________________

⁽¹⁾   Includes notes classified as liabilities associated with assets held for sale of which $4.6 million is current and $2.3 million is long-term at March 31, 2014, and $0.2 million is current and $3.8 million is long-term at December 31, 2013.

The following table presents the scheduled or expected approximate annual maturities of debt, gross of unamortized discount of $2.8 million: 

	(in thousands)
2014	$	4,354
2015	9,989
2016	234,548
2017	2,358
2018	55,360
Thereafter	600,000
Total	$	906,609

MHR Senior Revolving Credit Facility

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"). The terms of the Credit Agreement are substantially similar to the Prior Credit Agreement.

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As of March 31, 2014, the borrowing base under this facility was $232.5 million, and $226.0 million of borrowings were outstanding ($218.0 million outstanding as of December 31, 2013). On May 6, 2014, the Company entered into an amendment to the Credit Agreement and the borrowing base was increased to $325.0 million. See "Note 20 - Subsequent Events". The borrowing base is subject to certain automatic reductions upon the issuance of additional Senior Notes and in certain other circumstances.

At March 31, 2014, the Company was in compliance with all of its covenants, as amended, contained in the MHR Senior Revolving Credit Facility. 

Eureka Hunter Pipeline Credit Agreement

On March 28, 2014, Eureka Hunter Pipeline entered into a credit agreement (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, LLC, 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

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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:

• 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) 2.75to 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 March 31, 2014 the maximum amount available under the credit agreement was $58.7 million, and the Company had $55.0 million in borrowings outstanding. The borrowing capacity is subject to certain upward or downward reductions during the term of the credit agreement.

As of March 31, 2014 the Company 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 those agreements, 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.

Interest Expense

The following table sets forth interest expense for the three-month period ended March 31, 2014 and 2013, respectively:

	Three Months Ended   March 31,
	2014		2013
	(in thousands)
Interest expense incurred on debt, net of amounts capitalized	$	20,228	$	17,844
Amortization and write-off of deferred financing costs	3,621		857
Total Interest Expense	$	23,849	$	18,701

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. Interest of $610,000 and $848,000 was capitalized on our Eureka Hunter Gas Gathering System during the three months ended March 31, 2014 and 2013, respectively.

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For the three-month period ended March 31, 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, 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 three-month period ended March 31, 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.

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 7,448,674 shares had been issued under the plan as of March 31, 2014.

The Company recognized share-based compensation expense of $1.1 million for the three months ended March 31, 2014 and $6.3 million for the three months ended March 31, 2013.

A summary of common stock option activity for the three months ended March 31, 2014 and 2013 is presented below:

	Three Months Ended March 31,
	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	—		4,363		$	—	$	4.16
Exercised	(597	)	—		$	6.67	$	—
Forfeited	(902	)	(225	)	$	6.37	$	7.37
Outstanding at end of period	15,392		18,985		$	5.61	$	5.57
Exercisable at end of period	10,003		9,946		$	5.74	$	5.65

A summary of the Company’s non-vested common stock options and stock appreciation rights for the three months ended March 31, 2014 and 2013 is presented below:

	Three Months Ended March 31,
	2014		2013
	(in thousands of shares)
Non-vested at beginning of period	6,908		6,163
Granted	—		4,363
Vested	(805	)	(1,482	)
Forfeited	(714	)	(6	)
Non-vested at end of period	5,389		9,038

Total unrecognized compensation cost related to the non-vested common stock options was $7.9 million and $17.2 million as of March 31, 2014 and 2013, respectively.  The unrecognized compensation cost at March 31, 2014 is expected to be recognized over a weighted-average period of 1.05 years. At March 31, 2014, the weighted average remaining contract life of outstanding options was 5.16 years.

During the three months ended March 31, 2014, the Company granted 1,342,575 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 $10.7 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 $9.3 million and $264,000 as of March 31, 2014 and 2013, respectively.  The unrecognized cost at March 31, 2014, is expected to be recognized over a weighted-average period of 2.61 years.

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NOTE 12 - SHAREHOLDERS' EQUITY

Common Stock

During the three months ended March 31, 2014, the Company:

i) issued 25,152 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 597,000 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 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 made an initial filing with the Securities and Exchange Commission (the "SEC") to register the resale of these shares by the holders of the issued common stock to satisfy the Company's registration obligations under the private placement.

Preferred Dividends Incurred

A summary of the Company's preferred dividends for the three months ended March 31, 2014 and 2013 is presented below:

	Three Months Ended March 31,
	2014		2013
	(in thousands)
Dividend on Eureka Hunter Holdings Series A Preferred Units	$	4,028	$	3,114
Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	2,048		1,468
Dividend on Series C Preferred Stock	2,562		2,562
Dividend on Series D Preferred Stock	4,424		4,382
Dividend on Series E Preferred Stock	1,834		1,962
Total dividends on Preferred Stock	$	14,896	$	13,488

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, 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.

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The following table summarizes the types of potentially dilutive securities outstanding as of March 31, 2014 and 2013:

	March 31,
	2014	2013
	(in thousands of shares)
Series E Preferred Stock	10,946	10,946
Warrants	17,071	13,376
Restricted shares granted, not yet issued	1,453	—
Common stock options and stock appreciations rights	15,392	18,985
Total	44,862	43,307

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 Midstream Holdings, LLC (“Ridgeline”), an affiliate of ArcLight Capital Partners, LLC ("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 $191.8 million had been purchased as of March 31, 2014. See "Note 20 - Subsequent Events" for additional information.

During the three months ended March 31, 2014, Eureka Hunter Holdings issued 200,000 Eureka Hunter Holdings Series A Preferred Units to Ridgeline for net proceeds of $3.9 million, net of transaction costs. The Eureka Hunter Holdings Series A Preferred Units outstanding at March 31, 2014 represented 42.4% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.

During the three months ended March 31, 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 $72.3 million at March 31, 2014.

Dividend expense included accretion of the Eureka Hunter Holdings Series A Preferred Units of $2.0 million for the three months ended March 31, 2014, and $1.5 million for the three months ended March 31, 2013.

NOTE 14 - TAXES

The Company's income tax benefit from continuing operations for the three months ended March 31, 2014 and 2013 was:

	Three Months Ended March 31,
	2014		2013
	(in thousands)
Deferred	—		4,899
Income tax benefit	$	—	$	4,899

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

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Canada. As of March 31, 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.

NOTE 15 - RELATED PARTY TRANSACTIONS

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

	March 31, 2014		December 31, 2013
	(in thousands)
Green Hunter (1)
Accounts payable - net	$	451	$	23
Derivative assets (2)	$	35	$	79
Investments (2)	$	2,027	$	2,262
Notes receivable (2)	$	1,632	$	1,768
Prepaid expenses	$	—	$	9

The Company holds investments in related parties consisting of 1,846,722 shares of common stock of GreenHunter Resources with a carrying value of $367,984 as of March 31, 2014 and 88,000 shares of Series C preferred stock of GreenHunter Resources with a carrying value of $1.7 million as of March 31, 2014.

The following table sets forth the related party transaction activities for the three months ended March 31, 2014 and 2013, respectively:

		Three Months Ended   March 31,
		2014		2013
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	322	$	856
	Equipment rental (1)	122		—
	Office space rental (1)	22		—
	Interest Income from Note Receivable (2)	45		55
	Dividends earned from Series C shares	55		—
	Loss on investments (2)	235		526
Pilatus Hunter, LLC
	Airplane rental expenses (3)	70		47

_________________________________

(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; of which David Krueger, the Company's former Chief Accounting Officer and Senior Vice President, is the former Chief Financial Officer; and of which Ronald D. Ormand, the Company’s former Chief Financial Officer and Executive Vice President, is a former director. Eagle Ford Hunter received, and Triad Hunter and Viking International Resources, 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.

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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. 

Mr. Evans, the Company's Chairman and Chief Executive Officer, holds 27,641 Class A Common Units of Eureka Hunter Holdings.

NOTE 16 - COMMITMENTS AND CONTINGENCIES

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 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 three months ended March 31, 2014.

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 have 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").

By entering into the New Agreements, the Company and Seminole have 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 and reduce and extend the Company's contractual horizontal well drilling obligations owed to Seminole. The Company and Seminole have also agreed to modify the natural gas processing rates the Company will pay for processing at the Rogersville Plant, the Company's allocation of natural gas liquids ("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.

As a result of the restructuring effected by the Settlement Agreement, the Company expects to realize operational savings, certain components of which savings would occur over time, depending on the implementation timing or completion of certain of the benefits provided to the Company.

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 have been 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, but the cases in the Southern District of New York have been consolidated and remain ongoing. The plaintiffs in the Securities Cases have 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

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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 asserts 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 demands 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, which is pending for decision. The Company and the individual defendants intend to vigorously defend the Securities Cases. It is possible that additional investor lawsuits could be filed over these events.

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, although 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. It is possible that additional similar actions may be filed and that similar stockholder demands could be made.

The Company also received an April 26, 2013 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 26, 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.

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.

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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 April 2014, the estate of the other descendant 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. A pre-suit settlement demand has also been received from the injured individual. 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. The Court also granted Plaintiffs’ motion for expedited proceedings, ordering expedited discovery and a hearing within 90 days on Plaintiffs’ motion for a preliminary injunction. 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. The Court has not set a trial date or any pre-trial deadlines. PRC Williston believes the claim is without merit and intends to vigorously defend the lawsuit.

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:

	Three Months Ended March 31,
	2014		2013
	(in thousands)
Cash paid for interest	$	3,660	$	3,928
Non-cash transactions
Non-cash consideration received from sale of assets	$	9,400	$	—
Change in accrued capital expenditures	$	55,396	$	9,377
Non-cash additions to asset retirement obligation	$	52	$	1,964
Eureka Hunter Holdings Series A Preferred Unit dividends paid in kind	$	1,900	$	2,253

29

NOTE 18 - SEGMENT REPORTING

Magnum Hunter has four reportable operating segments: U.S. Upstream, Midstream and Oilfield Services represent the operating segments of the Company.  Beginning September 30, 2013, the Canadian Upstream segment, comprised of the WHI Canada operations, has been classified as assets held for sale and discontinued operations.

The following tables set forth operating activities by segment for the three months ended March 31, 2014 and 2013, respectively.

	As of and for the Three Months Ended March 31, 2014
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	70,174		$	—		$	34,735		$	7,911		$	—		$	(5,376	)	$	107,444
Depletion, depreciation, amortization and accretion	24,939			—			3,678			791			—			—			29,408
Loss on sale of assets, net	3,457			—			—			2			—			—			3,459
Other operating expenses	44,729			—			32,070			6,713			10,488			(5,223		)	88,777
Other income (expense)	(278		)	—			30			(209		)	(23,244		)	—			(23,701		)
Loss from continuing operations before income tax	(3,229		)	—			(983		)	196			(33,732		)	(153		)	(37,901		)
Total income (loss) from discontinued operations, net of tax	(23,128		)	(825		)	—			—			—			153			(23,800		)
Net income (loss)	$	(26,357	)	$	(825	)	$	(983	)	$	196		$	(33,732	)	$	—		$	(61,701	)
Total assets	$	1,369,962		$	64,147		$	322,030		$	45,021		$	98,526		$	(5,833	)	$	1,893,853
Total capital expenditures	$	66,311		$	308		$	30,634		$	690		$	23		$	—		$	97,966

	As of and for the Three Months Ended March 31, 2013
	U.S. Upstream			Canadian Upstream		Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	34,645		$	—	$	17,302		$	3,731		$	—		$	(1,444	)	$	54,234
Depletion, depreciation, amortization and accretion	14,263			—		2,687			338			—			—			17,288
(Gain) loss on sale of assets, net	(19		)	—		—			—			—			—			(19		)
Other operating expenses	44,063			—		14,668			3,699			15,990			(1,444		)	76,976
Other income (expense)	(2,123		)	—		(1,095		)	(89		)	(23,126		)	82			(26,351		)
Loss from continuing operations before income tax	(25,785		)	—		(1,148		)	(395		)	(39,116		)	82			(66,362		)
Income tax benefit	4,854			—		—			—			45			—			4,899
Total income from discontinued operations, net of tax	16,489			356		—			—			—			(82		)	16,763
Net income (loss)	$	(4,442	)	$	356	$	(1,148	)	$	(395	)	$	(39,071	)	$	—		$	(44,700	)
Total assets	$	1,658,324		$	262,320	$	240,861		$	29,121		$	125,233		$	(1,930	)	$	2,313,929
Total capital expenditures	$	112,344		$	12,256	$	22,295		$	7,956		$	172		$	—		$	155,023

30

NOTE 19 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS

Senior Notes

Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, Bakken Hunter, LLC, 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.

These condensed consolidating guarantor financial statements have been revised to reflect Eagle Ford Hunter, PRC Williston, and Williston Hunter ND, LLC 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 March 31, 2014 and December 31, 2013, and for the three months ended March 31, 2014 and 2013, are as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of March 31, 2014
	Magnum Hunter Resources Corporation		100% Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries		Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	75,046	$	64,639	$	22,320	$	(5,833	)	$	156,172
Intercompany accounts receivable	953,626		—		—		(953,626		)	—
Property and equipment (using successful efforts method of accounting)	6,362		1,269,856		262,267		—			1,538,485
Investment in subsidiaries	347,169		102,469		—		(449,638		)	—
Assets held for sale and other	17,118		86,675		95,403		—			199,196
Total Assets	$	1,399,321	$	1,523,639	$	379,990	$	(1,409,097	)	$	1,893,853
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	76,184	$	131,868	$	47,832	$	(5,868	)	$	250,016
Intercompany accounts payable	—		911,751		41,843		(953,594		)	—
Long-term liabilities	826,507		40,506		128,879		—			995,892
Redeemable preferred stock	100,000		—		142,275		—			242,275
Shareholders' equity (deficit)	396,630		439,514		19,161		(449,635		)	405,670
Total Liabilities and Shareholders' Equity	$	1,399,321	$	1,523,639	$	379,990	$	(1,409,097	)	$	1,893,853

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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

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Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Three Months Ended March 31, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	108		$	104,014		$	8,698		$	(5,376	)	$	107,444
Expenses	34,793			107,084			8,692			(5,224		)	145,345
Loss from continuing operations before equity in net income of subsidiaries	(34,685		)	(3,070		)	6			(152		)	(37,901		)
Equity in net income of subsidiaries	(28,815		)	155			—			28,660			—
Loss from continuing operations before income tax	(63,500		)	(2,915		)	6			28,508			(37,901		)
Income tax benefit (expense)	—			—			—			—			—
Loss from continuing operations	(63,500		)	(2,915		)	6			28,508			(37,901		)
Income from discontinued operations, net of tax	—			(117		)	3,327			152			3,362
Gain on sale of discontinued operations, net of tax	(4,319		)	(18,649		)	(4,194		)	—			(27,162		)
Net income (loss)	(67,819		)	(21,681		)	(861		)	28,660			(61,701		)
Net loss attributable to non-controlling interest	—			—			—			109			109
Net loss attributable to Magnum Hunter Resources Corporation	(67,819		)	(21,681		)	(861		)	28,769			(61,592		)
Dividends on preferred stock	(8,820		)	—			(6,076		)	—			(14,896		)
Net income (loss) attributable to common shareholders	$	(76,639	)	$	(21,681	)	$	(6,937	)	$	28,769		$	(76,488	)

33

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Three Months Ended March 31, 2013
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	(175	)	$	47,362		$	8,491		$	(1,444	)	$	54,234
Expenses	39,632			71,673			10,817			(1,526		)	120,596
Income (loss) from continuing operations before equity in net income of subsidiaries	(39,807		)	(24,311		)	(2,326		)	82			(66,362		)
Equity in net income of subsidiaries	(9,083		)	(529		)	(7,805		)	17,417			—
Income (loss) from continuing operations before income tax	(48,890		)	(24,840		)	(10,131		)	17,499			(66,362		)
Income tax benefit	45			4,854			—			—			4,899
Income (loss) from continuing operations	(48,845		)	(19,986		)	(10,131		)	17,499			(61,463		)
Income from discontinued operations, net of tax	—			(109		)	16,954			(82		)	16,763
Gain on sale of discontinued operations, net of tax	—			—			—			—			—
Net income (loss)	(48,845		)	(20,095		)	6,823			17,417			(44,700		)
Net income attributable to non-controlling interest	—			—			—			503			503
Net income (loss) attributable to Magnum Hunter Resources Corporation	(48,845		)	(20,095		)	6,823			17,920			(44,197		)
Dividends on preferred stock	(8,906		)	—			(4,582		)	—			(13,488		)
Net income (loss) attributable to common shareholders	$	(57,751	)	$	(20,095	)	$	2,241		$	17,920		$	(57,685	)

34

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended March 31, 2014
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(67,819	)	$	(21,681	)	$	(861	)	$	28,660	(61,701	)
Foreign currency translation loss	—			—			(2,348		)	—		(2,348	)
Unrealized gain (loss) on available for sale securities	—			(56		)	—			—		(56	)
Comprehensive income (loss)	(67,819		)	(21,737		)	(3,209		)	28,660		(64,105	)
Comprehensive loss attributable to non-controlling interest	—			—			—			109		109
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(67,819	)	$	(21,737	)	$	(3,209	)	$	28,769	(63,996	)

	Three Months Ended March 31, 2013
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(48,845	)	$	(20,095	)	$	6,823		$	17,417	(44,700	)
Foreign currency translation loss	—			—			(4,729		)	—		(4,729	)
Unrealized gain (loss) on available for sale securities	—			(17		)	—			—		(17	)
Comprehensive income (loss)	(48,845		)	(20,112		)	2,094			17,417		(49,446	)
Comprehensive income attributable to non-controlling interest	—			—			—			503		503
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(48,845	)	(20,112		)	2,094			17,920		(48,943	)

35

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	Three Months Ended March 31, 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	$	(8,779	)	$	4,611		$	8,045		$	—	$	3,877
Cash flow from investing activities	(181		)	(4,070		)	(18,568		)	—		(22,819		)
Cash flow from financing activities	31,886			4,050			5,720			—		41,656
Effect of exchange rate changes on cash	—			—			25			—		25
Net increase (decrease) in cash	22,926			4,591			(4,778		)	—		22,739
Cash at beginning of period	47,895			(17,651		)	11,469			—		41,713
Cash at end of period	$	70,821		$	(13,060	)	$	6,691		$	—	$	64,452

	Three Months Ended March 31, 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	$	(33,357	)	$	89,742		$	22,072		$	(836	)	$	77,621
Cash flow from investing activities	(142		)	(89,577		)	(54,718		)	—			(144,437		)
Cash flow from financing activities	100,852			402			(864		)	—			100,390
Effect of exchange rate changes on cash	—			—			(21		)	—			(21		)
Net increase (decrease) in cash	67,353			567			(33,531		)	(836		)	33,553
Cash at beginning of period	26,871			(12,582		)	43,334			—			57,623
Cash at end of period	$	94,224		$	(12,015	)	$	9,803		$	(836	)	$	91,176

36

NOTE 20 - SUBSEQUENT EVENTS

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.

Issuance of Eureka Hunter Holdings Series A Preferred Units

On April 14, 2014, Eureka Hunter Holdings issued 410,000 Eureka Hunter Holdings Series A Preferred Units to Ridgeline for proceeds of $8.0 million net of transaction costs. This transaction completed Ridgeline's commitment to purchase up to $200 million of Eureka Hunter Holdings Series A Preferred Units under the Unit Purchase Agreement. As of the date of filing of this Quarterly Report on Form 10-Q, the Eureka Hunter Holdings Series A Preferred Units outstanding represented 42.98% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.

Additional Borrowing under the Eureka Hunter Pipeline Credit Agreement

On April 17, 2014, Eureka Hunter Pipeline borrowed an additional $10.0 million under the Eureka Hunter Pipeline Credit Agreement. As of the date of filing this Quarterly Report on Form 10-Q, the balance outstanding was $65.0 million.

Sale of WHI Canada

On April 21, 2014, the Company entered into a definitive agreement with a Canadian private company to sell 100% of its ownership interest in the Company's Canadian subsidiary, WHI Canada, whose assets consist 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. $67.5 million at the exchange rate as of the close of business on April 21, 2014), subject to customary purchase price adjustments with an effective date of March 1, 2014. The transaction is expected to close in May, 2014.

Amendment to Credit Agreement

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 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.

In connection with the borrowing base increase, the Company and the other parties to the Credit Agreement entered into the First Amendment to Third Amended and Restated Credit Agreement, dated as of May 6, 2014 (the "Amendment"). The Amendment increases the borrowing base to $325.0 million and 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 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 ending 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:

37

(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 more 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 ended December 31, 2014 and for each fiscal quarter ending thereafter; and

(iii) beginning with the fiscal quarter ending 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.

38

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-month period ended March 31, 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, 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 Securities and Exchange Commission ("SEC"), including this Quarterly Report on Form 10-Q.

Executive Overview

The Company is 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 U.S. 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.

Financial and Operational Performance Highlights

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

• We reported a net loss from continuing operations of $37.9 million for the three months ended March 31, 2014, compared to a net loss from continuing operations of $61.5 million for the three months ended March 31, 2013.

• Oil and natural gas revenues from continuing operations increased by 102.6% to $70.2 million compared to $34.6 million during the same three-month period in 2013.

• Our total oil and natural gas production from continuing operations increased to 14,796 Boe/d (17,241 Boe/d including discontinued operations) for the three months ended March 31, 2014, compared to 7,322 Boe/d (10,870 Boe/d including discontinued operations) for the same period in 2013. Average production for the first quarter of 2014 was comprised of 46.1% liquids and 53.9% natural gas.

• As of March 31, 2014, we had approximately 278,120 net leasehold acres in our core operating areas, including (i) approximately 78,597 net acres in the Marcellus Shale, (ii) approximately 102,947 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and (iii) approximately 96,576 net acres in the Williston Basin/Bakken Shale in North Dakota.

• Pipeline throughput in our Midstream Segment increased to an average of 152,625 MMBtu/d for the three months ended March 31, 2014 compared to 51,293 MMBtu/d for the same period in 2013.

• Our capital expenditures of $98.0 million during the first quarter of 2014 were lower than planned due to a longer winter in the Northeastern United States.

Recent Developments

Divestitures and Discontinued Operations

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, four of which 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 $9.4 million at March 31, 2014. The Company recognized a loss on the sale of these assets

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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, a designated representative to NSE's board of directors.

In connection with the sale, we also entered into a transition services agreement with NSE Texas, through our subsidiary Shale Hunter, LLC ("Shale Hunter"), which 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.

MHP and WHI Canada

In September 2013, we adopted a plan to divest all of our interests in the operations of Magnum Hunter Productions, 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 $67.5 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 include 52,520 gross (49,470 net) acres with 84 gross wells producing approximately 630 Boe/d of current net production. We expect to close on this transaction on or about May 12, 2014.

See "Note 2 - Divestitures and Discontinued Operations" for additional information.

Equity Financing

During the three months ended March 31, 2014, we raised cash in the total amount of $36.8 million in net proceeds after offering discounts, commissions and placement fees, but before other offering expenses. These capital market and equity transactions include:

• $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;

• $3.9 million in net proceeds from issuances of Eureka Hunter Holdings Series A Preferred Units; and

• $4.0 million in net proceeds from issuances of 597,000 shares of our common stock upon exercise of stock options.

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 March 31, 2014, Eureka Hunter Pipeline had borrowed $55.0 million under the Eureka Hunter Pipeline Credit Agreement.

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;

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• together with Seminole, we will construct 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 expects to realize operational savings, certain components of which savings would occur over time, depending on the timing of implementation or completion of certain of the benefits provided to the Company under the agreement.

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.

Operational Update - First Quarter 2014

During the three-month period ended March 31, 2014, we continued with our oil and natural gas development and exploitation activities in the U.S. Upstream segment with a focus on our shale resource plays in the Marcellus and Utica Shale. Additionally, we continued to increase utilization of our Midstream natural gas gathering pipeline and 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 first three months of 2014.

U.S. Upstream

Marcellus Shale

WVDNR Pad - We drilled and completed the fracture stimulation of three, 100% owned Marcellus Shale wells, the WVDNR #1207, #1208, and #1209, located in Wetzel County, West Virginia. These wells were drilled and cased to an average vertical depth of 7,500 feet with a 3,800 foot average horizontal lateral, and were completed with 20 stage, 19 stage, and 20 stage fracture stimulations, respectively. These wells were tested at the following peak rates of production:

	Natural Gas		Condensate
WVDNR #1207	9,575	Mcf/d	17	Bbl/d
WVDNR #1208	9,208	Mcf/d	18	Bbl/d
WVDNR #1209	10,005	Mcf/d	19	Bbl/d

These wells began flowing to sales on April 2, 2014 and are currently producing at a combined rate of 14 MMcf per day, due to water handling restrictions.

Ormet Pad - We drilled and completed three ~100% owned wells located on the Ormet Pad in Monroe County, Ohio. These wells were drilled and cased to an average vertical depth of 5,900 feet with a 3,900 foot average horizontal lateral. The Ormet wells tested at a combined rate of 11.7 MMcf (1.95 MBoe) of natural gas and 1,788 Bbl of condensate per day or 3,738 Boe/d. We expect these wells to flow to sales during the first part of May 2014 through the Eureka Hunter Pipeline system.

Stalder Pad - Our first Marcellus Shale well drilled (50 % working interest) on the Stalder Pad in Monroe County, Ohio, the Stalder #2MH, has been drilled and cased, and fracture stimulation of the remaining four stages of the well was 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-

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back were 3,707 Mcf of natural gas per day and 312 Bbl of condensate per day. This well is currently shut-in as we prepare to drill additional wells on the Stalder Pad.

Stewart Winland Pad - We drilled and cased three ~100% owned Marcellus Shale wells, the Stewart Winland #1301, #1302, and #1303, in Tyler county, West Virginia, to an average true vertical depth of 6,155 feet with a 5,750 foot average horizontal lateral. We are currently drilling the pilot hole for our first Utica Shale well in the State of West Virginia, the Stewart Winland #1300, to a true vertical depth of 10,750 feet. We will then plug back and drill a 5,500 foot Utica horizontal lateral. We expect to report initial production test rates from these four 100% owned wells in late-summer 2014.

Utica Shale

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 prepare to drill additional Utica wells on the Stalder Pad.

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. We will begin fracture stimulation of these two new Farley Utica wells in late May and expect initial production test rates in late-summer 2014.

Williston Basin/Bakken Shale

We participated in the spudding of 4 gross (0.7 net) wells and the completion of 13 gross (4 net) wells in Divide County, North Dakota. Four of these wells were completed using perforate and plug technology, and are showing encouraging initial production rates. A third party has been engaged to gather and transport oil from certain of our non-operated wells in Divide County, North Dakota to the Colt Hub in Epping, North Dakota to reduce or eliminate trucking costs and minimize downtime during spring break-up. We expect that approximately 51 existing wells and 18 wells expected to be drilled under the operator's 2014 drilling program will be connected to the gathering system, which we expect to be fully operational by September 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. As of March 31, 2014, our operators have electrified approximately 113 gross wells and tied approximately 125 gross wells into the Oneok gas gathering system.

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 ending March 31, 2014, the Company drilled a total of 5 wells in which we own a 100% interest, and completed 9 gross (6 net) wells) in the Appalachian Basin. We incurred related capital expenditures of $57.9 million comprised of $47.5 million in proved property additions, and $10.4 million in leasehold acquisitions. See the "2014 Capital Expenditures Budget" section of Management's Discussion and Analysis of Financial Condition and Results of Operations for additional information.

Midstream

Eureka Hunter Pipeline

Throughput volumes on Eureka Hunter Pipeline's gas gathering pipeline system located in West Virginia and Ohio averaged 152,625 MMBtu per day during the first quarter of 2014. Average throughput during the last week of the quarter was 210,836 MMBtu per day. During March 2014, Triad Hunter, LLC ("Triad"), our wholly-owned subsidiary, produced approximately 44.1% of the volumes that flowed through the Eureka Hunter Pipeline system. The Company expects Eureka Hunter Pipeline to flow an additional 40,000 MMBtu per day of throughput volumes from Triad's new WVDNR and Ormet wells located in Wetzel County, West Virginia and Monroe County, Ohio during the second quarter of 2014. These new wells are scheduled to flow to sales by the end of May 2014. In addition, based upon new Marcellus and Utica drilling schedules, the Company expects Eureka Hunter Pipeline to add significant throughput volumes shipped from a combination of Triad and third parties throughout 2014.

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Midstream Capital Expenditures

During the three-month period ending March 31, 2014 our midstream segment incurred capital expenditures of $30.6 million.

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. At March 31, 2014, our operating fleet consisted of five Schramm T200XD drilling rigs and one Schramm T500XD drilling rig. The Schramm T500XD rig is a portable, robotic drilling rig capable of drilling to depths (both vertically and horizontally) of up to 19,000 feet. This rig can be used to drill the horizontal sections of our Marcellus Shale and Utica Shale wells.

The T200XD drilling rigs primarily drill the top-holes of the Company's and third parties' Marcellus Shale and Utica Shale wells in preparation for larger drilling rigs, which drill the horizontal sections of the wells. This style of drilling has proved to reduce overall drilling costs, by minimizing mobilization and demobilization charges and significantly decreasing the overall time to drill horizontal wells on each pad site.

At March 31, 2014, four of the Schramm T200XD drilling rigs were under contract to a large producer 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 an independent producer in the Appalachian Basin, and will also be utilized by us for our top-hole drilling program; and the Schramm T500XD drilling rig was under contract to our subsidiary for our Marcellus Shale and Utica Shale drilling program. All these contracts are term contracts.

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Results of Operations

The following table sets forth summary information from continuing operations (current and prior periods reported have been adjusted for discontinued operations - See "Note 2 - Divestitures and Discontinued Operations") regarding oil, natural gas and NGL revenues, production, average product prices and average production costs and expenses for the three months ended March 31, 2014 and 2013, respectively. 

	Three Months Ended   March 31,
	2014		2013
Oil and natural gas revenue and production
Revenues (in thousands, U.S. Dollars)
Oil	$	34,272	$	25,572
Natural gas	24,130		8,453
NGL	11,770		616
Total oil and natural gas sales	$	70,172	$	34,641
Production
Oil (MBbl)	413		295
Natural gas (MMcf)	4,307		2,097
NGL (MBoe)	200		15
Total (MBoe)	1,332		659
Boe/d	14,796		7,322
Average prices (U.S. Dollars)
Oil (per Bbl)	$	82.89	$	86.79
Natural gas (per Mcf)	$	5.60	$	4.03
NGL (per Boe)	$	58.75	$	41.43
Total average price (per Boe)	$	52.70	$	52.57
Costs and expenses (per Boe)
Lease operating expense	$	14.99	$	11.64
Severance tax and marketing	$	4.19	$	4.30
Exploration expense	$	10.54	$	45.12
Impairment of proved oil and natural gas property	$	—	$	—
General and administrative expense (1)	$	11.47	$	30.31
Depletion, depreciation and accretion	$	22.08	$	26.23
Other segments (in thousands)
Natural gas transportation, gathering, processing and marketing revenues	$	31,649	$	15,896
Natural gas transportation, gathering, processing and marketing expenses	$	29,999	$	13,431
Oilfield services revenues	$	5,621	$	3,693
Oilfield services expenses	$	3,947	$	3,335

_________________________________

(1) General and administrative expense includes: (i) transaction and professional services expenses of $6.7 million ($5.05 Boe) for the three months ended March 31, 2014 and $7.1 million ($10.78 Boe) for the three months ended March 31, 2013, and (ii) non-cash stock compensation of $1.1 million ($0.80 Boe) for the three months ended March 31, 2014 and $6.3 million ($9.48 Boe) for the three months ended March 31, 2013.

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Three Months Ended March 31, 2014 and 2013

Oil and natural gas production. Production increased by 102.1%, or 673 MBoe, to 1,332 MBoe for the three months endedMarch 31, 2014 compared to the three months endedMarch 31, 2013. Our average daily production was 14,796 Boe/d during the 2014 period, representing an overall increase of 102.1%, or 7,474 Boe/d, compared to 7,322 Boe/d for the 2013 period. Oil and NGL production for the three months ended March 31, 2014 was 613 MBoe versus 310 MBoe for the three months ended March 31, 2013, an increase of 97.7%. The increase in production in 2014 was fueled by organic growth attributable to our drilling programs in the Appalachian Basin focusing on our Marcellus and Utica Shale plays and further development in our Bakken and Williston fields. Specifically, natural gas production from the Appalachian Basin alone, increased from 1,918 MMcf for the three months ended March 31, 2013 to 4,039 MMcf for the three-months ended March 31, 2014; an increase of 110.6%.

Further, the Williston/Bakken fields contributed an additional 132 MBoe in oil production, which was offset by sales of assets made by our subsidiaries, PRC Williston, LLC and Williston Hunter ND, LLC, producing from the Madison formation in North Dakota during the fourth quarter of 2013. Total Production for the three months ended March 31, 2014, on a Boe basis, was 46.1% oil and NGL and 53.9% natural gas compared to 47.0% oil and NGL and 53.0% natural gas for the same period in 2013.

Oil and natural gas sales. Oil and natural gas sales increased102.6%, or $35.5 million, for the three months endedMarch 31, 2014 to $70.2 million from $34.6 million for the three months endedMarch 31, 2013. The increase in oil and natural gas sales primarily resulted from higher production volumes from our Marcellus, Appalachian and Williston/Bakken fields. Our total sales prices were impacted by increases in prices received for natural gas and NGL of 39.0% and 41.8%, respectively, offset by a decline in the price received for oil sales of 4.5%. Our natural gas sales benefited from a combination of increased production and higher demand due to a longer and colder winter in the northeastern United States. Of the total increase in oil and natural gas sales for the 2014 period, $8.6 million was attributable to the increase in prices received and $26.9 million was attributable to our increase in production. The prices we receive for our products are generally tied to commodity index prices. We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices.

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 $15.7 million, or 99.1%, for the three months endedMarch 31, 2014 to $31.6 million from $15.9 million for the three months endedMarch 31, 2013. TransTex Hunter revenues decreased by $1.4 million primarily as the result of inventory sales during the first quarter of 2013. Eureka Hunter Pipeline revenues increased by $1.9 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 197.8% or 9.1 million MMBtu to 13.7 million MMBtu for the three months ended March 31, 2014 from 4.6 million MMBtu for the three months ended March 31, 2013. Magnum Hunter Marketing revenues increased by $15.3 million to $26.0 million during the three months ended March 31, 2014 from $10.7 million during the three months ended March 31, 2013. Magnum Hunter Marketing revenues increased by $5.0 million as a result of new customers and by $10.3 million from growth in existing customers, including $8.9 million in increased gas revenues and $1.4 million of increased NGL revenues from the Markwest processing plant.

Oilfield services revenue. Drilling services revenue increased by 52.2%, or $1.9 million, for the three months endedMarch 31, 2014 to $5.6 million from $3.7 million for the three months endedMarch 31, 2013. This increase was primarily attributable to a combination of additional rigs in service and higher utilization of the existing fleet. During the three months ended March 31, 2014, our drilling rig revenue days increased from 177 to 463 as compared to the three months ended March 31, 2013, primarily as a result of the addition of 2 rigs to our fleet and full utilization of 2 existing rigs.

Loss on sale of assets. We recorded a net loss on sale of assets in operating expenses of $3.5 million for the three months ended March 31, 2014, which included a loss of $3.3 million related to the sale of certain oil and natural gas properties and related assets in the Eagle Ford Shale in South Texas, partially offset by post-closing adjustments related to the sales of certain North Dakota oil and natural gas properties during the latter part of 2013.

Lease operating expense. Our lease operating expenses ("LOE"), increased$12.3 million, or 160.3%, for the three months endedMarch 31, 2014 to $20.0 million ($14.99 Boe) from $7.7 million ($11.64 Boe) for the three months endedMarch 31, 2013. The increase in LOE was comprised of $7.8 million attributable to increased production volumes and $4.5 million attributable to higher LOE/Boe costs. Of the increase in LOE/Boe costs, $2.3 million was due to higher Appalachian Basin gas transportation charges, $1.1 million was related to higher costs in the Appalachian Basin due in part to an increased production of NGL, which generally have higher LOE/Boe than natural gas, and $1.1 million was due to higher non-recurring work-over expenses in the Williston Basin for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013.

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Severance taxes.  Our severance taxes increased$2.7 million, or 96.8%, for the three months endedMarch 31, 2014, to $5.6 million from $2.8 million for the three months endedMarch 31, 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, and unproved property impairments and leasehold expiration as exploration expense. We recorded $14.0 million of exploration expense for the three months endedMarch 31, 2014, compared to $29.7 million for the three months ended March 31, 2013. During the 2014 period, the Company's exploration expense was primarily attributable to $11.1 million of leasehold impairments relating to leases in the Williston Basin region that expired undrilled during the three months ended March 31, 2014 or are expected to expire during the remainder of 2014 that the Company does not plan to develop, and $2.6 million related to leases in the Appalachian Basin. The Company's exploration expense during the three months ended March 31, 2013 of $29.4 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.

As a result of our assessment, during the three months endedMarch 31, 2014 and 2013, no impairment expense was deemed necessary on our proved oil and natural gas properties included in continuing operations. However, based upon developments in our marketing activities relating to MHP and the aggregate purchase prices under definitive agreements entered into by us for the sale of our Canadian operations, further impairments on our investment in MHP and WHI Canada were indicated. As a result, we recognized additional non-cash impairment charges of $22.8 million, included in loss on disposal of discontinued operations, to reduce the carrying value of these properties to their estimated fair values.

Natural gas transportation, gathering, processing and marketing expenses. Expenses from the midstream operations increased by $16.6 million, or 123.4%, for the three months endedMarch 31, 2014 to $30.0 million from $13.4 million for the three months endedMarch 31, 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 increased by $0.6 million, or 18.4% for the three months endedMarch 31, 2014, to $3.9 million from $3.3 million for the three months endedMarch 31, 2013, due to the addition of 2 rigs to our fleet and full utilization of 2 existing rigs.

Depletion, depreciation, amortization, and accretion. Our depletion, depreciation, amortization and accretion expense ("DD&A"), increased $12.1 million, or 70.1%, to $29.4 million for the three months endedMarch 31, 2014, from $17.3 million for the three months endedMarch 31, 2013, due to increases in capitalized costs subject to DD&A, stemming from our capital expenditures and acquisition programs during 2013, and increased production in 2014. Our DD&A/Boe decreased by $4.15, or 15.8%, to $22.08 Boe for the three months endedMarch 31, 2014, compared to $26.23 Boe for the three months endedMarch 31, 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.

General and administrative. Our general and administrative expenses ("G&A"), decreased $4.7 million, or 23.6%, to $15.3 million or $11.47 Boe for the three months endedMarch 31, 2014 from $20.0 million or $30.31 Boe for the three months endedMarch 31, 2013. G&A expenses decreased overall from 2013 mainly due to lower stock compensation expense partially offset by increases in travel and rent expenses. Non-cash stock compensation expense decreased by $5.2 million, to approximately $1.1 million or $0.80 Boe for the three months endedMarch 31, 2014 from $6.3 million or $9.48 Boe for the three months endedMarch 31, 2013 as a result of a grant during the first quarter of 2013 of which 25% vested immediately.

Interest expense. Our interest expense, net of interest income, increased by 27.7%, to $23.8 million from $18.6 million for the three months endedMarch 31, 2014, compared to the three months endedMarch 31, 2013. Our higher average debt level in the first quarter of 2014 compared to the 2013 period accounted for $2.4 million of the increase, and higher amortization and write-off of deferred financing costs accounted for $2.8 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

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of $610,000 and $848,000 during the three months endedMarch 31, 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 gains of $0.3 million for the quarter ended March 31, 2014, compared to net losses of $7.5 million for the quarter ended March 31, 2013. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts as of the dates indicated:

	Three Months Ended   March 31,
	2014			2013
	(in thousands)
Commodity derivatives
Gain (loss) on settled transactions	$	(2,284	)	$	956
Gain (loss) on open transactions	(3,261		)	(8,176		)
Total commodity derivatives	(5,545		)	(7,220		)
Financial derivatives
Gain (loss) on open transactions	5,892			(271		)
Net gain (loss)	$	347		$	(7,491	)

We did not designate our derivative instruments as cash-flow hedges. See "Note 9 - Financial Instruments and Derivatives".

At March 31, 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. See "Note 9 - Financial Instruments and Derivatives" and "Note 13 - Redeemable Preferred Stock." This embedded derivative instrument resulted in an unrealized gain of $5.9 million in the three months endedMarch 31, 2014. Also at March 31, 2014, the Company had an embedded derivative asset related to a convertible security, 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," "Note 2 - Divestitures and Discontinued Operations" and "Note 15 - Related Party Transactions". An unrealized loss of $44,000 is recorded for this embedded derivative instrument in the first quarter of 2014. Both derivative instruments originated in 2012 and the derivative instruments have resulted in no cash outlays as of March 31, 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”.

Income tax benefit.  As a result of losses incurred during the three-months ended March 31, 2014, we did not recognize an income tax benefit or incur income tax expense, whereas we recognized a benefit of $4.9 million for the three months ended March 31, 2013.

Income (loss) from discontinued operations, net of tax. In September 2013, the Company adopted a plan to divest all of its interests in MHP and WHI Canada. The Company has reclassified the associated assets and liabilities of these businesses to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented. During the year ended December 2013, the Company recorded an impairment expense of $92.4 million to record MHP and WHI Canada at their estimated selling price less costs to sell. Based upon additional information on estimated selling prices obtained through active marketing of these assets, the Company has recorded an additional impairment expense of $22.8 million for the three months ended March 31, 2014 to reflect the net assets at their estimated selling prices, less costs to sell, which is recorded in loss on disposal of discontinued operations for the three months ended March 31, 2014.

Income (loss) from discontinued operations was $3.4 million and $16.8 million for the three months ended March 31, 2014 and 2013, respectively. The following table summarizes the income (loss) from discontinued operations as of the dates indicated:

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	Three months ended March 31,
	2014			2013
	(in thousands)
Eagle Ford Hunter	$	—		$	16,611
Magnum Hunter Production	(7		)	(121		)
Williston Hunter Canada	3,369			273
	$	3,362		$	16,763

Loss on disposal of discontinued operations, net of tax. Loss on disposal of discontinued operations was $27.2 million for the three months ended March 31, 2014 as shown in the following table. There was no gain or loss on disposal for the three months ended March 31, 2013.

	Three months ended March 31,
	2014			2013
	(in thousands)
Eagle Ford Hunter	$	(4,319	)	$	—
Magnum Hunter Production	(18,649		)	—
Williston Hunter Canada	(4,194		)	—
	$	(27,162	)	$	—

Net income attributable to non-controlling interest.  Net loss attributable to non-controlling interest was approximately $109,000 for the three months ended March 31, 2014 and $503,000 for same period in 2013.  This represents 12.5% of the gain or loss of our subsidiary, PRC Williston, and 2.5% of the net income or loss attributable to our subsidiary, Eureka Hunter Holdings. 

Dividends on preferred stock. Total dividends on our preferred stock were approximately $14.9 million for the three months endedMarch 31, 2014 compared to $13.5 million for the 2013 period.

The Series C Preferred Stock had a stated value of $100.0 million at March 31, 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 March 31, 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 March 31, 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 $206.5 million and $200.6 million as of March 31, 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 MHR Senior Revolving Credit Facility, 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 MHR Senior Revolving Credit Facility, 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 MHR Senior Revolving Credit Facility 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 and increasing our proved reserves. 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.

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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, 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.

We utilize our credit agreements to fund a portion of our operating and capital needs. The Company had $226.0 million of outstanding debt under our MHR Senior Revolving Credit Facility at March 31, 2014, with available borrowing capacity at that date of $6.3 million.  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 million.

We define liquidity as funds available under our MHR Senior Revolving Credit Facility plus cash and cash equivalents, excluding amounts held by our subsidiaries that are designated as unrestricted subsidiaries under this facility. At March 31, 2014, liquidity for the Company, excluding Eureka Hunter Holdings and its subsidiaries, was $68.6 million, comprised of $6.3 million of available borrowing capacity under the MHR Senior Revolving Credit Facility and $62.3 million in available cash. The increase in borrowing capacity described above will provide us additional liquidity of approximately $90 million, net of fees.

While we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities, available borrowing capacity under the MHR Senior Revolving Credit Facility and anticipated proceeds from our planned sales of non-core assets 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 non-core 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 2014 include the anticipated receipt of proceeds from the planned divestitures of our southern Appalachian Basin operations and our Canadian operations, the payment to Penn Virginia in settlement of the final purchase price adjustments relating to our sale to Penn Virginia of Eagle Ford Hunter in 2013, 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.

We intend to fund the remainder of our 2014 capital expenditures, excluding any acquisitions, from a combination of internally-generated cash flows, borrowings under our MHR Senior Revolving Credit Facility, Eureka Hunter Pipeline’s new senior secured revolving credit facility, proceeds from non-core asset sales and proceeds from capital markets transactions, to the extent we access such capital markets at opportune times.

Impact of the Eagle Ford Final Working Capital Adjustment on Liquidity

As discussed in "Note 2 - Divestitures and Discontinued Operations", as of March 31, 2014 we estimated that the final working capital adjustment related to the sale of Eagle Ford Hunter to Penn Virginia is a reduction to the preliminary gain recognized in 2013 ranging from $22 million to $33 million, net of tax.  We expect that the working capital adjustment will be finalized by the end of the second quarter of 2014. We will be required to settle the final adjustment amount to Penn Virginia shortly after finalization. Our estimate of the final working capital adjustment has been recorded as a liability and is reflected as in increase to our net working capital deficit as of March 31, 2014. Although it is not anticipated, the actual final working capital adjustment could be greater than management's estimate.

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Liquidity Position

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

	As of March 31, 2014						As of December 31, 2013
	(in thousands)
	Magnum Hunter			Eureka Hunter			Magnum Hunter			Eureka Hunter
Borrowing base under MHR senior revolving credit facility	$	232,500		$	—		$	242,500		$	—
Eureka Hunter Pipeline second lien term loan	—			—			—			50,000
Eureka Hunter Pipeline Credit Agreement	—			58,701			—			—
Cash and cash equivalents	62,291			2,161			33,669			8,044
Borrowings under MHR Senior Revolving Credit Facility	(226,000		)	—			(218,000		)	—
Letters of credit issued	(225		)	—			(7,225		)	—
Borrowings under Eureka Hunter Pipeline second lien term loan	—			—			—			(50,000		)
Borrowings under Eureka Hunter Pipeline Credit Agreement	—			(55,000		)	—			—
Liquidity	$	68,566		$	5,862		$	50,944		$	8,044

Upon the consummation of the sale of Shale Hunter's assets in January 2014, the borrowing base under the MHR Senior Revolving Credit Facility was adjusted down by $10.0 million to $232.5 million. The Company had $226.0 million outstanding under this facility and $225,000 in available letters of credit at March 31, 2014, with available borrowing capacity at that date of $6.3 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 March 31, 2014, liquidity for Eureka Hunter Pipeline was $5.9 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 March 31, 2014, Eureka Hunter Pipeline could borrow up to $58.7 million and still maintain compliance with financial ratios. Additionally, at that date, capital funding commitments from the Company and ArcLight, Eureka Hunter Holdings' minority interest holder, were approximately $20.5 million.

On May 6, 2014 we entered into the First Amendment to the Third Amended and Restated Credit Agreement (also referenced as the MHR Senior Revolving Credit Facility) with the Bank of Montreal, as administrative agent for the lenders under the agreement. Under the terms of this amendment, our borrowing base was increased from $232.5 million to $325 million with retroactive effect given in the determination of our compliance with certain debt covenants and others were modified as of March 31, 2014. This increase in borrowing capacity will provide us additional liquidity of approximately $90 million, net of fees. 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 "Amendments to Credit Facilities" section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

As of March 31, 2014, we were in compliance with all of our covenants, as amended, contained in our credit agreements.

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 non-core assets, and (iv) reducing our non-essential general and administrative costs. During the first quarter of 2014, and through May 8, 2014, we closed on or entered into definitive agreements to sell assets and raised cash through a private offering of common stock for aggregate proceeds of approximately $130.0 million, as follows:

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

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

• entry into a definitive agreement to sell oil and natural gas assets in Alberta, Canada to BDJ Energy, for CAD $9.5 million (or US $8.7 million), subject to customary adjustments, which closed on April 10, 2014; and

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• entry into a definitive agreement to sell our 100% interest in Williston Hunter Canada Inc. ("WHI Canada"), a wholly-owned subsidiary for CAD $75.0 million (or US $67.5 million), subject to customary adjustments, which we expect to close on or about May 12, 2014.

Upon closing of the sale of WHI Canada, our borrowing base under the MHR Senior Revolving Credit Facility will decrease by $27.5 million. Additionally, until certain Canadian tax filing and related approval requirements are fulfilled, 25% of the CAD $75.0 million purchase price will be restricted and held in escrow. We expect that such filings and approval will be obtained by June 30, 2014.

The expected 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 non-core 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.

We also continue to actively market our interests in MHP and expect that a purchase and sales agreement will be executed by the end of the second quarter of 2014.

Sources of Cash

For the three months ended March 31, 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.

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

	Three Months Ended March 31,
	2014			2013
	(In thousands)
Cash flows provided by operating activities	$	3,877		$	77,621
Cash flows provided by (used in) investing activities	(22,819		)	(144,437		)
Cash flows provided by (used in) financing activities	41,656			100,390
Effect of foreign currency exchange rates	25			(21		)
Net increase (decrease) in cash and cash equivalents	$	22,739		$	33,553

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 $3.9 million for the three months ended March 31, 2014, compared to $77.6 million for the three months ended March 31, 2013, a decrease of $73.7 million or 95.0%.  Although we had increased oil and natural gas sales from the recent success in our drilling programs in the Marcellus Shale and Utica Shale, cash flows from sales in the first quarter of 2014 were offset by higher lease operating expenses of $12.3 million, and a decrease of $13.4 million in income from discontinued operations, compared to the same period in 2013. Cash provided by operating activities for the three months ended March 31, 2014 includes cash flows from discontinued operations of $2.7 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 three months ended March 31, 2014, was $22.8 million, principally from drilling activities, and partially offset by the cash proceeds from the sale of assets of $16.4 million.  See "Note 2 - Divestitures and Discontinued Operations" for additional information.

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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, activities we continue to acquire leasehold acreage in our core areas and select other exploratory areas we believe are prospective for hydrocarbons.

Our cash used in investing activities for the three months ended March 31, 2013 was $144.4 million, principally from drilling activities. We used $49.5 million for capital programs in the Williston Basin region, $26.0 million in the Appalachian region, $26.0 million in the Eagle Ford region, and $34.2 million of cash for capital expenditures by Eureka Hunter Holdings, and $8.7 million invested in a new drilling rig for Alpha Hunter Drilling. One hundred percent of our capital invested in the Eagle Ford region from January 1, 2013 up to the time of the sale of our Eagle Ford Hunter subsidiary on April 24, 2013 was credited back to us as an upward adjustment to the purchase price for the sale or as cash received from Penn Virginia subsequent to the sale.

Non-Cash Investing Items

In connection with the sale of certain assets by Shale Hunter LLC (“Shale Hunter”), we acquired 65,650,000 common shares of New Standard Energy Limited, 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 three months ended March 31, 2014, was $41.7 million mainly from borrowings under the MHR Senior Revolving Credit Facility and the new Eureka Hunter Pipeline Credit Agreement, as well as from proceeds from the issuance of shares of common stock. Our majority owned subsidiary, Eureka Hunter Pipeline, paid in full and terminated its term loan with Pennant Park and borrowed $55.0 million from the new Eureka Hunter Pipeline Credit Agreement executed in March 2014 (see "Note 10 - Debt"). In addition to debt financing arrangements, we raised $28.9 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through a private offering of 4,300,000 of our common stock. See "Note 12 - Shareholders' Equity" for additional information.

Our cash flows from financing activities for the three months ended March 31, 2013 were $100.4 million, mainly from borrowings under the MHR Senior Revolving Credit Facility. The Company also raised $10.3 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 $663,000. In the 2013 period, we paid preferred dividends of $9.7 million and incurred $445,000 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, we may be limited in our ability to access the public markets to raise debt or equity capital, which could prevent us from pursuing transactions or implementing business strategies that would be beneficial to our business. Until we have timely filed all our required SEC reports for a period of twelve months (which period will expire in August 2014, assuming we remain timely in the filing of our SEC reports for that period), we will be ineligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. Further, during such period, we will be unable to use our existing shelf registration statement on Form S-3 or 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. We may use a Form S-1 Registration Statement to register a sale of our securities to raise capital or complete acquisitions, but doing so would likely increase transaction costs and adversely impact our ability to raise capital or complete acquisitions in an expeditious manner.

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) anticipated sales of non-core 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.

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2014 Capital Expenditures

The following table summarizes our estimated capital expenditures (excluding acquisitions) 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 and, as necessary, borrowings under our MHR Senior Revolving Credit Facility.   

	Capital Expenditures Incurred (2)		Capital Expenditure Budget
	Three Months Ended March 31, 2014		For the Year ending December 31, 2014
	(In thousands)
Upstream Operations
Appalachian Basin drilling	$	35,869	$	260,000
Williston Basin drilling	$	11,592	50,000
Midstream and Marketing Operations
Eureka Hunter Holdings (1)	$	30,634	90,000
Total capital expenditures	$	78,095	$	400,000

________________________________

(1) Expected to be financed through equity and debt facilities that are non-recourse to the Company, and Company capital contributions.

(2) Capital expenditures of $4.2 million incurred in other regions, leasehold acquisitions of approximately $10.4 million, and expenditures on other property, plant, and equipment of approximately $5.3 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.

New Credit Facilities

On March 28, 2014, Eureka Hunter Pipeline, a wholly-owned subsidiary of Eureka Hunter, a majority-owned subsidiary of the Company, entered into a credit agreement (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, LLC, 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 0.5% 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.

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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 1.00%, or (iii) the federal funds rate, plus 0.5% per annum), and (B) a margin of 1.00% to 2.50% per annum; or

• on Eurodollar Loans (as defined in the Credit Agreement), at the per annum rate equal to the sum of (A) the Eurodollar Rate adjusted for certain statutory reserve requirements for Eurocurrency liabilities, and (B) a margin of 2.00% 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:

• 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 March 31, 2014 the maximum amount available under the credit agreement was $58.7 million, and the Company had $55.0 million in borrowings outstanding. The borrowing capacity is subject to certain upward or downward reductions during the term of the credit agreement.

Amendments to Credit Facilities

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. 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.

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In connection with the borrowing base increase, the Company and the other parties to the Credit Agreement entered into the First Amendment to Third Amended and Restated Credit Agreement, dated as of May 6, 2014 (the "Amendment"). The Amendment increases the borrowing base to $325.0 million and 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 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 ending 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 more 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 ended December 31, 2014 and for each fiscal quarter ending thereafter; and

(iii) beginning with the fiscal quarter ending 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 attached hereto as Exhibit 10.1 and incorporated herein by reference.

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Related Party Transactions

The following table sets forth the related party transaction activities for the three months ended March 31, 2014 and 2013, respectively:

		Three Months Ended   March 31,
		2014		2013
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	322	$	856
	Equipment rental (1)	122		—
	Office space rental (1)	22		—
	Interest Income from Note Receivable (2)	45		55
	Dividends received from Series C shares	55		—
	Loss on investments (2)	235		526
Pilatus Hunter, LLC
	Airplane rental expenses (3)	70		47

__________________________________

(1) GreenHunter is an entity of which Gary C. Evans, our Chairman and CEO, is the Chairman, a major shareholder and interim CEO; of which David Krueger, our former Chief Accounting Officer and Senior Vice President, is the former Chief Financial Officer; and of which Ronald D. Ormand, our former Chief Financial Officer and Executive Vice President, is a former director. Eagle Ford Hunter received, and Triad Hunter and Virco, 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 $35,000, and $79,000 at March 31, 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 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. 

Mr. Evans, our Chairman and Chief Executive Officer, holds 27,641 Class A Common Units of Eureka Hunter Holdings.

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Contractual Obligations

The following table presents our contractual obligations as of March 31, 2014:

Contractual Obligations	Total		2014		2015 -2016		2017 - 2018		After 2018
Long-term debt (1)	$	906,609	$	4,354	$	244,537	$	57,718	$	600,000
Interest on long-term debt (2)	394,849		70,538		132,870		120,428		71,013
Gas transportation and compression contracts	27,567		3,249		7,691		5,905		10,722
Asset retirement obligations (3)	16,607		61		254		6,143		10,149
Commodity derivative liabilities (4)	5,276		5,276		—		—		—
Operating lease obligations	1,441		444		696		248		53
Drilling rig installments	263		263		—		—		—
Total	$	1,352,612	$	84,185	$	386,048	$	190,442	$	691,937

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 March 31, 2014 on the debt facilities in place as of March 31, 2014. This results in a weighted average interest rate of 7.81%.

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

(4) 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 March 31, 2014, the off-balance sheet arrangements and transactions that we have entered into include operating lease agreements.  We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

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".

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. In addition, foreign currency exchange-rate risk exists due to the our investment in our wholly owned subsidiary Williston Hunter Canada, Inc., whose functional currency is the Canadian dollar. These risks can affect revenues and cash flow from operating, investing, and financing activities.

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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".

Commodity Price Risk

The Company's most significant market risk relates to prices for natural gas, crude oil, and NGL's. 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 March 31, 2014, the Company had derivative instruments in place to reduce the price risk associated with future production of 17.2 Bcf of natural gas and 1.4 MMBbls of crude oil, representing a gross asset of $2.5 million and a gross liability of $7.5 million; or a net liability of $5.0 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 March 31, 2014:

	As of March 31, 2014
	Fair Value As Reported			Fair Value: 10% Price Increase			Fair Value: 10 % Price Decrease
	(in thousands)
Gas	$	(2,161	)	$	(8,631	)	$	4,338
Crude	(2,825		)	(12,189		)	3,058
Total Fair Value	$	(4,986	)	$	(20,820	)	$	7,396
Change in Fair Value				(15,834		)	12,382

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

At March 31, 2014, we had the following commodity derivative positions outstanding:

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Collars (1)	April 2014- Dec 2014	5,000	$4.00 - $5.25
Swaps	April 2014 - Dec 2014	31,000	$4.23
	Jan 2015 - Dec 2015	20,000	$4.18
Ceilings purchased (call)	April 2014 - Dec 2014	16,000	$5.91
Ceilings sold (call)	April 2014 - Dec 2014	16,000	$5.91
			Weighted Average
Crude Oil	Period	Bbls/day	Price per Bbl
Collars (1)	April 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collars (2)	April 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)	April 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.

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At March 31, 2014, the fair value of our open commodity derivative contracts was a liability of $5.0 million.

The following table summarizes the gains and losses on settled and open derivative contracts for the three months ended March 31, 2014 and 2013:

	Three Months Ended   March 31,
	2014			2013
	(in thousands)
Gain (loss) on settled transactions	$	(2,284	)	$	956
Gain (loss) on open transactions	(3,261		)	(8,132		)
Total gain (loss)	$	(5,545	)	$	(7,176	)

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 $188,000.

Financial Instrument Price Risk

We have investments in publicly and privately issued 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 $1.1 million.

Eureka Hunter Pipeline, 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 option 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 Pipeline and the implied volatility of the instruments. As of March 31, 2014, the fair value of the liability associated with these embedded features was $72.3 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 March 31, 2014:

	As of March 31, 2014
	Fair Value: Increase of 5%	Fair Value: Decrease of 5%
	(in thousands)
Total enterprise value	81,028	63,943
Volatility	80,155	64,151

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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 March 31, 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 March 31, 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 (1992 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 March 31, 2014, management continues to implement and execute upon its remediation plan with respect to the material identified in our Annual Report on Form 10-K as of December 31, 2013.

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

61

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 in the first quarter of 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.

None.

Item 3.         Defaults upon Senior Securities

None.

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: May 9, 2014		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman and Chief Executive Officer
Date: May 9, 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 January 21, 2013, among Shale Hunter, LLC, Magnum Hunter Resources Corporation, Magnum Hunter Production, Inc. and Energy Hunter Partners 2012-A Drilling & Production Fund, Ltd., New Standard Energy Texas LLC and New Standard Energy Limited (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 23, 2014).+
2.1.1	Transition Services Agreement, dated January 28, 2014, between Shale Hunter, LLC and New Standard Energy Texas LLC (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 30, 2014).+
2.2	Purchase and Sale Agreement, dated March 31, 2014, between Williston Hunter Canada, Inc. and BDJ Energy Inc.#+
2.3	Share Purchase Agreement, dated April 21, 2014, between Magnum Hunter Resources Corporation and Steppe Resources Inc.#+
10.1	Omnibus Settlement Agreement and Release, dated as of January 9, 2014, by and among Magnum Hunter Resources Corporation, a Delaware corporation, Magnum Hunter Production, Inc., a Kentucky corporation, formerly known as NGAS Production Co., which in turn was formerly known as Daugherty Petroleum, Inc., Eureka Hunter Pipeline, LLC, a Delaware limited liability company, Seminole Energy Services, L.L.C., an Oklahoma limited liability company, Seminole Gas Company, L.L.C., an Oklahoma limited liability company, Seminole Murphy Liquids Terminal, L.L.C., a Tennessee limited liability company, NGAS Gathering II, LLC, a Kentucky limited liability company, and NGAS Gathering, LLC, a Kentucky limited liability company (incorporated by reference from the Registrant’s current report on Form 8-K filed on January 14, 2014).
10.2	Securities Purchase Agreement, dated as of March 20, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant’s registration statement on Form S-1 filed on March 31, 2014).
10.3	Registration Rights Agreement, dated as of March 20, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant’s registration statement on Form S-1 filed on March 31, 2014).
10.4	Credit Agreement, dated March 28, 2014, by and among Eureka Hunter Pipeline, LLC, as borrower, ABN AMRO Capital USA, LLC, as lender and administrative agent, and the other lenders party thereto.#
10.5	First Amendment to Third Amended and Restated Credit Agreement, dated as of May 6, 2014, among the Registrant, Bank of Montreal, as Administrative Agent, and the lenders party thereto.#
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.^

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

65