Magnum Hunter Resources 10-Q 2014 Q2 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

For the quarterly period ended June 30, 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 August 7, 2014, there were 199,397,350 shares of the registrant’s common stock ($0.01 par value) outstanding.

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED June 30, 2014

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited):
Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	3
Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2014 and 2013	4
Consolidated Statement of Shareholders’ Equity for the Six Months Ended June 30, 2014	5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	6
Notes to Consolidated Financial Statements	7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	45
Item 3. Quantitative and Qualitative Disclosures About Market Risk	70
Item 4. Controls and Procedures	73
Part II. OTHER INFORMATION	74
Item 1. Legal Proceedings	74
Item 1A. Risk Factors	74
Item 3. Defaults Upon Senior Securities	75
Item 5. Other Information	75
Item 6. Exhibits	75
SIGNATURES	76

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

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

(unaudited)

	June 30, 2014		December 31, 2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	9,120	$	41,713
Restricted cash	5,000		5,000
Accounts receivable:
Oil and natural gas sales	47,723		25,099
Joint interests and other, net of allowance for doubtful accounts of $252 at June 30, 2014 and $196 at December 31, 2013	40,160		30,582
Derivative assets	317		608
Inventory	3,830		7,158
Investments	10,771		2,262
Prepaid expenses and other assets	3,054		2,938
Assets held for sale	1,638		5,366
Total current assets	121,613		120,726
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting, net	1,328,701		1,224,659
Gas transportation, gathering and processing equipment and other, net	369,324		289,420
Total property, plant and equipment, net	1,698,025		1,514,079
OTHER ASSETS
Deferred financing costs, net of amortization of $12,195 at June 30, 2014 and $9,735 at December 31, 2013	18,358		20,008
Derivative assets, long-term	123		25
Intangible assets, net	5,527		6,530
Goodwill	30,602		30,602
Assets held for sale	84,935		162,687
Other assets	4,174		1,994
Total assets	$	1,963,357	$	1,856,651

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

1

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS (Continued)

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

(unaudited)

	June 30, 2014			December 31, 2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Current portion of notes payable	$	5,431		$	3,804
Accounts payable	128,356			107,837
Accounts payable to related parties	690			23
Accrued liabilities	55,636			44,629
Revenue payable	10,039			6,313
Derivative liabilities	5,709			1,903
Liabilities associated with assets held for sale	17,961			12,865
Other liabilities	2,374			6,491
Total current liabilities	226,196			183,865
NONCURRENT LIABILITIES
Long-term debt	839,009			876,106
Asset retirement obligations	16,568			16,163
Derivative liabilities, long-term	115,727			76,310
Other long-term liabilities	2,163			2,279
Long-term liabilities associated with assets held for sale	11,310			14,523
Total liabilities	1,210,973			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 June 30, 2014 and December 31, 2013, with a liquidation preference of $25.00 per share	100,000			100,000
Series A Convertible Preferred Units of Eureka Hunter Holdings, LLC (the "Eureka Hunter Holdings Series A Preferred Units"), cumulative distribution rate of 8.0% per annum, 10,592,540 and 9,885,048 issued and outstanding as of June 30, 2014 and December 31, 2013, respectively, with a liquidation preference of $214,776 and $200,620 as of June 30, 2014 and December 31, 2013, respectively	149,379			136,675
	249,379			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 June 30, 2014 and December 31, 2013, with a liquidation preference of $50.00 per share	221,244			221,244
Series E Cumulative Convertible Preferred Stock ("Series E Preferred Stock"), cumulative dividend rate 8.0% per annum, 12,000 authorized, 3,803 issued and 3,722 outstanding as of June 30, 2014 and December 31, 2013, with a liquidation preference of $25,000 per share	95,069			95,069
Common stock, $0.01 par value per share, 350,000,000 shares authorized, and 200,299,799 and 172,409,023 issued, and 199,384,847 and 171,494,071 outstanding as of June 30, 2014 and December 31, 2013, respectively	2,003			1,724
Additional paid in capital	924,185			733,753
Accumulated deficit	(742,830		)	(586,365		)
Accumulated other comprehensive loss	(983		)	(19,901		)
Treasury Stock, at cost:
Series E Preferred Stock, 81 shares as of June 30, 2014 and December 31, 2013	(2,030		)	(2,030		)
Common stock, 914,952 shares as of June 30, 2014 and December 31, 2013	(1,914		)	(1,914		)
Total Magnum Hunter Resources Corporation shareholders’ equity	494,744			441,580
Non-controlling interest	8,261			9,150
Total shareholders’ equity	503,005			450,730
Total liabilities and shareholders’ equity	$	1,963,357		$	1,856,651

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

2

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2014			2013			2014			2013
REVENUES AND OTHER
Oil and natural gas sales	$	78,190		$	49,583		$	148,362		$	84,224
Natural gas transportation, gathering, processing, and marketing	48,363			13,974			80,012			29,870
Oilfield services	5,954			3,612			11,575			7,305
Other revenue	9			739			11			743
Total revenue	132,516			67,908			239,960			122,142
OPERATING EXPENSES
Lease operating expenses	14,836			15,213			34,792			22,881
Severance taxes and marketing	6,627			4,016			12,201			6,848
Exploration	9,187			3,546			23,216			33,279
Impairment of proved oil and gas properties	158			9,968			158			9,968
Natural gas transportation, gathering, processing, and marketing	44,754			13,414			74,753			26,845
Oilfield services	4,089			4,066			8,036			7,401
Depletion, depreciation, amortization and accretion	35,953			26,375			65,361			43,663
Loss (gain) on sale of assets, net	(687		)	1,183			2,772			1,164
General and administrative	18,738			16,364			34,010			36,341
Total operating expenses	133,655			94,145			255,299			188,390
OPERATING LOSS	(1,139		)	(26,237		)	(15,339		)	(66,248		)
OTHER INCOME (EXPENSE)
Interest income	41			81			86			138
Interest expense	(20,434		)	(18,793		)	(44,283		)	(37,494		)
Gain (loss) on derivative contracts, net	(42,836		)	6,400			(42,489		)	(1,091		)
Other expense (income)	264			(465		)	20			(681		)
Total other expense, net	(62,965		)	(12,777		)	(86,666		)	(39,128		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(64,104		)	(39,014		)	(102,005		)	(105,376		)
Income tax benefit	—			39,300			—			44,199
INCOME (LOSS) FROM CONTINUING OPERATIONS, NET OF TAX	(64,104		)	286			(102,005		)	(61,177		)
Income (loss) from discontinued operations, net of tax	3,889			(7,684		)	7,251			9,079
Gain (loss) on disposal of discontinued operations, net of tax	(5,212		)	172,452			(32,374		)	172,452
NET INCOME (LOSS)	(65,427		)	165,054			(127,128		)	120,354
Net loss attributed to non-controlling interests	780			386			889			889
INCOME (LOSS) ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	(64,647		)	165,440			(126,239		)	121,243
Dividends on preferred stock	(15,330		)	(14,129		)	(30,226		)	(27,617		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(79,977	)	$	151,311		$	(156,465	)	$	93,626
Weighted average number of common shares outstanding, basic and diluted	184,479,312			169,690,633			178,346,940			169,657,806
Loss from continuing operations per share, basic and diluted	$	(0.42	)	$	(0.08	)	$	(0.74	)	$	(0.52	)
Income (loss) from discontinued operations per share, basic and diluted	(0.01		)	0.97			(0.14		)	1.07
NET INCOME (LOSS) PER COMMON SHARE, BASIC AND DILUTED	$	(0.43	)	$	0.89		$	(0.88	)	$	0.55
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
Income (loss) from continuing operations, net of tax	$	(63,324	)	$	672		$	(101,116	)	$	(60,288	)
Income (loss) from discontinued operations, net of tax	(1,323		)	164,768			(25,123		)	181,531
Net income (loss)	$	(64,647	)	$	165,440		$	(126,239	)	$	121,243

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

3

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)

(in thousands)

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2014			2013			2014			2013
NET INCOME (LOSS)	$	(65,427	)	$	165,054		$	(127,128	)	$	120,354
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation gain (loss)	1,130			(7,070		)	(1,218		)	(11,799		)
Unrealized gain (loss) on available for sale investments	(549		)	4,466			(605		)	4,449
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	20,741			—			20,741			—
Total other comprehensive income (loss)	21,322			(2,604		)	18,918			(7,350		)
COMPREHENSIVE INCOME (LOSS)	(44,105		)	162,450			(108,210		)	113,004
Comprehensive loss attributable to non-controlling interests	780			386			889			889
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	$	(43,325	)	$	162,836		$	(107,321	)	$	113,893

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

4

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENT OFSHAREHOLDERS' EQUITY

(unaudited)

(in thousands)

	Number of Shares
	Series D Preferred Stock	Series E Preferred Stock	Common Stock	Series D Preferred Stock		Series E Preferred Stock		Common Stock		Additional Paid in Capital		Accumulated Deficit			Accumulated Other Comprehensive Income (loss)			Treasury Stock			Non - controlling Interest			Total Shareholders’ Equity
BALANCE, January 1, 2014	4,425	4	172,409	$	221,244	$	95,069	$	1,724	$	733,753	$	(586,365	)	$	(19,901	)	$	(3,944	)	$	9,150		$	450,730
Share-based compensation	—	—	47	—		—		1		3,374		—			—			—			—			3,375
Sale of common stock	—	—	25,729	—		—		257		178,318		—			—			—			—			178,575
Dividends on preferred stock	—	—	—	—		—		—		—		(30,226		)	—			—			—			(30,226		)
Shares of common stock issued upon exercise of common stock options	—	—	2,115	—		—		21		8,740		—			—			—			—			8,761
Net loss	—	—	—	—		—		—		—		(126,239		)	—			—			(889		)	(127,128		)
Foreign currency translation	—	—	—	—		—		—		—		—			(1,218		)	—			—			(1,218		)
Unrealized loss on available for sale securities, net	—	—	—	—		—		—		—		—			(605		)	—			—			(605		)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	—	—	—	—		—		—		—		—			20,741			—			—			20,741
BALANCE, June 30, 2014	4,425	4	200,300	$	221,244	$	95,069	$	2,003	$	924,185	$	(742,830	)	$	(983	)	$	(3,944	)	$	8,261		$	503,005

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

5

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)

	Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(127,128	)	$	120,354
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	65,361			73,078
Exploration	22,489			34,168
Impairment of proved oil and gas properties	158			16,034
Impairment of other operating assets	616			263
Share-based compensation	3,375			8,699
Cash paid for plugging wells	(27		)	—
Loss (gain) on sale of assets	35,761			(206,082		)
Unrealized loss on derivative contracts	37,938			786
Unrealized loss on investments	403			1,152
Amortization and write-off of deferred financing costs and discount on Senior Notes included in interest expense	7,740			2,758
Deferred tax benefit	—			(6,475		)
Changes in operating assets and liabilities:
Accounts receivable, net	(15,588		)	7,760
Inventory	3,475			(459		)
Prepaid expenses and other current assets	(1,147		)	(802		)
Accounts payable	(23,817		)	24,099
Revenue payable	5,204			(1,204		)
Accrued liabilities	3,934			(261		)
Net cash provided by operating activities	18,747			73,868
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and advances	(257,469		)	(277,492		)
Change in restricted cash	—			1,500
Change in deposits and other long-term assets	(2,406		)	154
Proceeds from sales of assets	74,503			380,036
Net cash provided by (used in) investing activities	(185,372		)	104,198
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from sale of common shares	178,575			—
Net proceeds from sale of preferred shares	—			10,181
Equity issuance costs	—			(109		)
Proceeds from sale of Eureka Hunter Holdings Series A Preferred Units	11,956			19,600
Proceeds from exercise of warrants and options	8,761			—
Preferred stock dividend	(23,646		)	(10,424		)
Repayments of debt	(197,216		)	(327,076		)
Proceeds from borrowings on debt	161,616			105,991
Deferred financing costs	(6,042		)	(701		)
Change in other long-term liabilities	(13		)	(52		)
Net cash provided by financing activities	133,991			(202,590		)
Effect of changes in exchange rate on cash	41			(357		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(32,593		)	(24,881		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	41,713			57,623
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	9,120		$	32,742

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

6

MAGNUM HUNTER RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1 - GENERAL

Organization and Nature of Operations

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

Presentation of Consolidated Financial Statements

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

In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair statement of the financial position and the results of operations for the interim periods presented have been reflected herein.  The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.  The year-end balance sheet data were derived from audited financial statements, but do not include all disclosures required by GAAP. 

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

Non-Controlling Interest in Consolidated Subsidiaries

The Company has consolidated Eureka Hunter Holdings, LLC ("Eureka Hunter Holdings") in which it owned 56.5% as of June 30, 2014 and 56.4% as of December 31, 2013. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), TransTex Hunter, LLC ("TransTex Hunter"), and Eureka Hunter Land, LLC. On December 30, 2013, the Company's majority-owned subsidiary, PRC Williston, LLC ("PRC Williston"), in which the Company owned 87.5% as of June 30, 2014 and December 31, 2013, 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 managed drilling 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. As of June 30, 2014 and December 31, 2013, Energy Hunter Securities, Inc. had net capital of $84,919 and $77,953, respectively, and aggregate indebtedness of $7,289 and $16,657, respectively.

7

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 and six months ended June 30, 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 $274,827 and $445,899, respectively. During the three and six months ended June 30, 2013, the Company had no revenues related to Sentra Corporation's regulated operations.

Energy Hunter Securities, Inc. and Sentra Corporation are included in discontinued operations.

Recently Issued Accounting Standards

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

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

In July 2013, the 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 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.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: identify the contract(s) with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from

8

contracts with customers. This amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

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

NOTE 2 - DIVESTITURES AND DISCONTINUED OPERATIONS

Discontinued Operations

In September 2013, the Company adopted a plan to divest all of its interests in (i) 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.

Planned Divestiture of Magnum Hunter Production

The Company is marketing its interests in MHP and its subsidiaries, and anticipates entering into a purchase and sale agreement for MHP by the end of 2014. The Company has classified the associated assets and liabilities of MHP 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 $18.5 million to record MHP at the estimated selling price less costs to sell. Based upon additional information on estimated selling prices obtained through active marketing of the assets, the Company recorded an additional impairment expense as of March 31, 2014 of $18.6 million to reflect the net assets at their estimated selling prices, less costs to sell, which is recorded in gain (loss) on disposal of discontinued operations for the six months ended June 30, 2014.

Williston Hunter Canada Asset Sale

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

Sale of Williston Hunter Canada

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

9

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

	June 30, 2014		December 31, 2013
	(in thousands)
Accounts receivable	$	927	$	4,362
Other current assets	711		1,004
Oil and natural gas properties, net	71,935		150,770
Gas transportation, gathering, and processing equipment and other, net	12,972		11,721
Other long-term assets	28		196
Total assets held for sale	$	86,573	$	168,053
Accounts payable	$	7,659	$	7,292
Accrued liabilities and other liabilities	10,302		5,573
Asset retirement obligations	6,975		8,678
Other long-term liabilities	4,335		5,845
Total liabilities held for sale	$	29,271	$	27,388

Sale of Eagle Ford Hunter

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

In the months that followed closing, the Company and Penn Virginia were unable to agree upon the final settlement of the working capital adjustments as called for in the purchase and sale agreement and the disagreement was subsequently submitted to arbitration. The determination by the arbitrator was received by the Company on July 25, 2014 and resulted in a downward adjustment of the cash portion of the purchase price of $33.7 million plus accrued interest of $1.3 million. The Company had previously reserved and recognized substantially all of this obligation in its financial statements as of December 31, 2013. For the three and six months ended June 30, 2014, the Company recorded a downward adjustment to the gain on sale of Eagle Ford Hunter of $2.7 million and $7.0 million, respectively. See "Note 20 - Subsequent Events" for additional information.

The Company included the results of operations of MHP for all periods presented, WHI Canada through May 12, 2014, and Eagle Ford Hunter through April 24, 2013, in discontinued operations as follows:

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2014			2013			2014			2013
	(in thousands)
Revenues	$	8,234		$	24,623		$	20,517		$	68,413
Expenses	(4,345		)	(30,013		)	(13,178		)	(58,238		)
Other income (expense)	—			1,893			(88		)	3,136
Income tax expense	—			(4,187		)	—			(4,232		)
Income (loss) from discontinued operations, net of tax	3,889			(7,684		)	7,251			9,079
Income (loss) on sale of discontinued operations, net of taxes	(5,212		)	172,452			(32,374		)	172,452
Income (loss) from discontinued operations, net of taxes	$	(1,323	)	$	164,768		$	(25,123	)	$	181,531

10

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, of which four were operated by the Company. The effective date of the sale was December 1, 2013. As consideration for the assets sold, the Company received aggregate purchase price consideration of $15.5 million in cash, after customary purchase price adjustments, and 65,650,000 ordinary shares of NSE with a fair value of approximately $9.4 million at January 28, 2014 (based on the closing market price of $0.14 per share on January 28, 2014). These investment holdings 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. The Company recognized a loss on the sale of the Shale Hunter 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 ending on July 28, 2015 unless otherwise extended or modified, Shale Hunter will provide NSE Texas with certain transitional services relating to the assets sold for which it is receiving a monthly fee.

Upon, and as a result of, the closing of the sale on January 28, 2014, the borrowing base under the Company’s asset-based, senior secured revolving credit facility was automatically reduced by $10.0 million to $232.5 million as of the closing date, but prior to the increase in the borrowing base discussed in "Note 10 - Debt".

NOTE 3 - OIL & NATURAL GAS SALES

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

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2014		2013		2014		2013
	(in thousands)
Oil	$	39,839	$	33,122	$	74,111	$	58,694
Natural gas	25,453		12,810		49,583		21,263
NGLs	12,898		3,651		24,668		4,267
Total oil and natural gas sales	$	78,190	$	49,583	$	148,362	$	84,224

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:

	June 30, 2014			December 31, 2013
	(in thousands)
Mineral interests in properties:
Unproved leasehold costs	$	538,872		$	469,337
Proved leasehold costs	334,918			336,357
Wells and related equipment and facilities	615,998			536,023
Advances to operators for wells in progress	20,740			13,571
Total costs	1,510,528			1,355,288
Less accumulated depletion, depreciation, and amortization	(181,827		)	(130,629		)
Net capitalized costs	$	1,328,701		$	1,224,659

11

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis bi-annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. Impairments of proved property of $0.2 million and $10.0 million were recorded during each of the three and six months ended June 30, 2014 and 2013, respectively.

Depletion, depreciation, and amortization expense for proved oil and natural gas properties was $30.1 million and $53.9 million for the three and six months ended June 30, 2014 and $21.5 million and $34.4 million for the three and six months ended June 30, 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 and six months ended June 30, 2014 and 2013, the Company recognized exploration expense as follows:

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2014		2013		2014		2013
	(in thousands)
Leasehold impairments	$	8,834	$	3,272	$	22,489	$	32,625
Geological and geophysical	353		274		727		654
Total exploration expense	$	9,187	$	3,546	$	23,216	$	33,279

Leasehold impairment expense recorded by the Company during the three and six months ended June 30, 2014 consisted of $8.8 million and $19.9 million, respectively, in the U.S. upstream segment related to leases in the Williston Basin and $2.6 million during the six months ended June 30, 2014 in the U.S. upstream segment related to leases in the Appalachian Basin. Leasehold impairment expense of $3.3 million and $32.6 million during the three and six months ended June 30, 2013 primarily related to leases in the Williston Basin. Impairments of leases in the Williston and Appalachian Basins for all periods presented related to leases that expired undrilled during the period or are expected to expire and that the Company does not plan to develop or extend.

Capitalized Costs Greater Than a Year

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

Gas Transportation, Gathering, and Processing Equipment and Other

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

	June 30, 2014			December 31, 2013
	(in thousands)
Gas transportation, gathering and processing equipment and other	$	405,320		$	315,642
Less accumulated depreciation	(35,996		)	(26,222		)
Net capitalized costs	$	369,324		$	289,420

12

Depreciation expense for gas transportation, gathering, and processing equipment and other property was $5.0 million and $9.6 million for the three and six months ended June 30, 2014, respectively, and $3.6 million and $6.8 million for the three and six months ended June 30, 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 June 30, 2014 had a net carrying value of $11.9 million, and the terms of such leases provide for future lease payments to the Company extending up to August 2016.  As of June 30, 2014, primarily all the leases to third parties were non-cancelable, with future minimum aggregate base rentals payable to the Company of $3.4 million over the twelve months ending June 30, 2015 and $0.7 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 June 30, 2014 and December 31, 2013:

	June 30,			December 31,
	2014			2013
	(in thousands)
Customer relationships	$	5,434		$	5,434
Trademark	859			859
Existing contracts	4,199			4,199
Total intangible assets	10,492			10,492
Less: accumulated amortization	(4,965		)	(3,962		)
Intangible assets, net of accumulated amortization	$	5,527		$	6,530

Amortization expense for intangible assets was $502,000 and $1.0 million for the three and six months ended June 30, 2014 and $200,000 and $1.4 million for the three and six months ended June 30, 2013, respectively.

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

NOTE 6 - INVENTORY

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

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

	June 30, 2014		December 31, 2013
	(in thousands)
Materials and supplies	$	3,440	$	6,790
Commodities	390		368
Inventory	$	3,830	$	7,158

13

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

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

	June 30, 2014			December 31, 2013
	(in thousands)
Asset retirement obligation at beginning of period	$	16,216		$	30,680
Assumed in acquisitions	—			17
Liabilities incurred	216			253
Liabilities settled	(21		)	(98		)
Liabilities sold	(523		)	(7,614		)
Accretion expense	751			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	16,639			16,216
Less: current portion (included in other liabilities)	(71		)	(53		)
Asset retirement obligation at end of period	$	16,568		$	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. 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 June 30, 2014.

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

Level 1 Classification:

Available for Sale Securities

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

14

Level 2 Classification:

Commodity Derivative Instruments

The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting.  The estimated fair value amounts of the Company’s commodity derivative instruments have been determined at discrete points in time based on relevant market information which resulted in the Company classifying such derivatives as Level 2.  Although the Company’s commodity derivative instruments are valued using public indices, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange. Although the Company is exposed to credit risk to the extent of nonperformance by the counterparties to these derivative contracts, the Company does not anticipate such nonperformance and monitors the credit worthiness of its counterparties on an ongoing basis.

Level 3 Classification:

Preferred Stock Embedded Derivative

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

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

	June 30, 2014
Volatility	24		%
Credit spread	10.5		%
Expected term	1-2 years
Total enterprise value (in millions)	$	608.0

The selection of assumptions for expected term and total enterprise value were made based on a weighting of possible outcomes. The term of the conversion feature, which is linked to the terms of the Eureka Hunter Holdings Amended and Restated Limited Liability Company Agreement ("the Eureka Hunter Holdings LLC Agreement"), could range from zero to 6 years. The total enterprise value of Eureka Hunter Holdings is based upon a weighting of valuations ranging from $406 million to $1 billion based upon multiples of earnings before interest, taxes, depreciation, and amortization of comparable companies and precedent market transactions.

The fair value calculation is sensitive to movements in volatility, estimated remaining term, and the total enterprise value of Eureka Hunter Holdings. A decrease in the estimated term of the conversion feature results in a higher fair value of the conversion feature. During the three-month period ended June 30, 2014, the Company changed the estimated term to 1-2 years due to changes in the Company's intention with respect to the Eureka Hunter Holdings Series A Preferred Units. 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.

15

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

	June 30, 2014
Life	2.6 years
Risk-free interest rate	0.85		%
Estimated volatility	40		%
Dividend	—
GreenHunter stock price at end of period	$	1.99

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
	June 30, 2014
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	10,661	$	—	$	—
Commodity derivative assets	—		123		—
Convertible security derivative assets	—		—		317
Total assets at fair value	$	10,661	$	123	$	317
Liabilities
Commodity derivative liabilities	$	—	$	6,129	$	—
Convertible preferred stock derivative liabilities	—		—		115,307
Total liabilities at fair value	$	—	$	6,129	$	115,307

	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 six-month period ended June 30, 2014:

	Preferred Stock Embedded Derivative Liability			Convertible Security Embedded Derivative Asset
	(in thousands)
Fair value as of December 31, 2013	$	(75,934	)	$	79
Issuance of redeemable preferred stock	(5,479		)	—
Increase in fair value recognized in gain (loss) on derivative contracts, net	(33,894		)	238
Fair value as of June 30, 2014	$	(115,307	)	$	317

16

As of June 30, 2014, the valuation of the conversion feature embedded in the Eureka Hunter Holdings Series A Preferred Units increased the fair value of the embedded derivative liability by approximately $33.9 million as a result of changes in the total enterprise value of Eureka Hunter Holdings and the Company's estimate of the expected remaining term of the conversion feature. Management's estimate of the expected remaining term of the conversion option as of June 30, 2014 shortened the time horizon previously estimated by management, resulting in higher fair value of the conversion feature. Management's estimates are based upon several factors, including an estimate of the likelihood of each of the possible settlement options, which include redemption through a call or put option, or a liquidity event that triggers conversion to Class A Common Units of Eureka Hunter Holdings.

Other Fair Value Measurements

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

		June 30, 2014				December 31, 2013
	Fair Value Hierarchy	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
		(in thousands)
Senior Notes	Level 2	$	597,279	$	666,000	$	597,230	$	651,300
MHR Senior Revolving Credit Facility	Level 3	$	164,500	$	164,500	$	218,000	$	218,000
Eureka Hunter Pipeline second lien term loan	Level 3	$	—	$	—	$	50,000	$	58,921
Eureka Hunter Pipeline Credit Agreement	Level 3	$	65,000	$	65,000	$	—	$	—
Equipment Notes Payable	Level 3	$	24,395	$	24,303	$	18,615	$	17,676

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

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

The fair value of Eureka Hunter Pipeline's second lien term loan as of December 31, 2013 is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate.  The credit spread is the Company’s default or repayment risk.  The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt.

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.

17

NOTE 9 - FINANCIAL INSTRUMENTS AND DERIVATIVES

Investment Holdings

Below is a summary of changes in investments for the six months ended June 30, 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)	—			(403		)
Change in fair value recognized in other comprehensive loss	(605		)	—
Carrying value as of June 30, 2014	$	10,661		$	537

⁽¹⁾ Available for sale securities includes $123,000 that has been classified as held for sale associated with the classification of MHP as a discontinued operation.

⁽²⁾ Equity method investments includes $304,000 classified as long-term other assets.

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

	Available for Sale Securities		Equity Method Investments		Total
Investments - Current	$	10,538	$	233	$	10,771
Investments - Long-Term	—		304		304
Investments - Held for Sale	123		—		123
Carrying value as of June 30,2014	$	10,661	$	537	$	11,198

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

	June 30, 2014
	(in thousands)
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
Securities available for sale, carried at fair value:
Equity securities	$	9,875	$	—	$	(1,404	)	$	8,471
Equity securities - related party (see "Note 15 - Related Party Transactions")	2,200		—		(10		)	2,190
Total Securities available for sale	$	12,075	$	—	$	(1,414	)	$	10,661

	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

18

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

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

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

Commodity and Financial Derivative Instruments

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

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

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

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Collars (1)	July 2014- Dec 2014	15,000	$4.27 - $5.23
Swaps	July 2014 - Dec 2014	31,000	$4.23
	Jan 2015 - Dec 2015	20,000	$4.18
Ceilings purchased (call)	July 2014 - Dec 2014	16,000	$5.91
Ceilings sold (call)	July 2014 - Dec 2014	16,000	$5.91
			Weighted Average
Crude Oil	Period	Bbl/day	Price per Bbl
Collars (1)	July 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collars (2)	July 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)	July 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.

19

At June 30, 2014, the Company had preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of its Eureka Hunter Holdings Series A Preferred Units. See "Note 8 - Fair Value of Financial Instruments" and "Note 13 - Redeemable Preferred Stock".

At June 30, 2014, the Company also had a convertible security embedded derivative asset primarily due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. See "Note 8 - Fair Value of Financial Instruments," "Note 2 - Divestitures and Discontinued Operations," and "Note 15 - Related Party Transactions".

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	June 30, 2014		December 31, 2013		June 30, 2014			December 31, 2013
		(in thousands)
Commodity
	Derivative assets	$	—	$	529	$	—		$	—
	Derivative assets - long-term	123		25		—			—
	Derivative liabilities	—		—		(5,709		)	(1,903		)
	Derivative liabilities - long-term	—		—		(420		)	(376		)
Total commodity		$	123	$	554	$	(6,129	)	$	(2,279	)
Financial
	Derivative assets	$	317	$	79	$	—		$	—
	Derivative liabilities - long-term	—		—		(115,307		)	(75,934		)
Total financial		$	317	$	79	$	(115,307	)	$	(75,934	)
Total derivatives		$	440	$	633	$	(121,436	)	$	(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:

	June 30, 2014
	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset on the Consolidated Balance Sheet		Net Amount
	(in thousands)
Current assets:  Fair value of derivative contracts	$	565		565		$	—
Long-term assets:  Fair value of derivative contracts	239			116		123
Current liabilities:  Fair value of derivative contracts	(6,274		)	(565	)	(5,709		)
Long-term liabilities:  Fair value of derivative contracts	(536		)	(116	)	(420		)
	$	(6,006	)	—		$	(6,006	)

20

	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	)

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

	Three Months Ended June 30,						Six Months Ended   June 30,
	2014			2013			2014			2013
	(in thousands)
Gain (loss) on settled transactions	$	(2,267	)	$	(1,261	)	$	(4,551	)	$	(305	)
Gain (loss) on open contracts	(40,569		)	7,661			(37,938		)	(786		)
Total gain (loss)	$	(42,836	)	$	6,400		$	(42,489	)	$	(1,091	)

NOTE 10 - DEBT

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

	June 30, 2014			December 31, 2013
	(in thousands)
Senior Notes payable due May 15, 2020, interest rate of 9.75%, net of unamortized net discount of $2.7 million at June 30, 2014 and December 31, 2013	$	597,279		$	597,230
Various equipment and real estate notes payable with maturity dates January 2015 - April 2021, interest rates of 4.25% - 7.94%(1)	24,395			18,615
Eureka Hunter Pipeline Credit Agreement due March 28, 2018, interest rate of 3.66%	65,000			—
Eureka Hunter Pipeline second lien term loan due August 16, 2018, interest rate of 12.5%	—			50,000
MHR Senior Revolving Credit Facility due April 13, 2016, interest rate of 3.57% at June 30, 2014 and 3.56% at December 31, 2013	164,500			218,000
	851,174			883,845
Less: current portion	(10,005		)	(3,967		)
Total long-term debt obligations, net of current portion	$	841,169		$	879,878

 _________________________________

⁽¹⁾   Includes notes classified as liabilities associated with assets held for sale of which $4.6 million is current and $2.2 million is long-term at June 30, 2014, and $0.2 million is current and $3.8 million is long-term at December 31, 2013.

21

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

	(in thousands)
2014	$	3,142
2015	9,989
2016	173,047
2017	2,358
2018	65,360
Thereafter	600,000
Total	$	853,896

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.

On May 6, 2014, the Company and the other parties to the Credit Agreement entered into the First Amendment to Third Amended and Restated Credit Agreement (the "Amendment"). The Amendment increased the borrowing base from $232.5 million to $325.0 million in connection with the regular semi-annual redetermination of the Company's borrowing base derived from the Company's proved crude oil and natural gas reserves. The borrowing base may be increased or decreased in connection with such redeterminations up to a maximum commitment level of $750.0 million. The Amendment provides that such increased borrowing base shall be reduced (i) by the lesser of $25.0 million or 50% of the net proceeds from issuances by the Company of common equity on or before July 1, 2014 (other than common equity issued pursuant to any stock incentive or stock option plan or any other compensatory arrangements); (ii) by certain specified reductions in connection with certain proposed asset dispositions; (iii) on July 1, 2014 by $25.0 million less any prior adjustment of the borrowing base due to an equity issuance as contemplated by clause (i); and (iv) by $0.25 for each $1.00 of any additional Senior Notes issued by the Company. The Amendment further provides that from May 6, 2014 through July 1, 2014 the Applicable Margin (as defined in the Credit Agreement) component of the interest charged on revolving borrowings under the Credit Agreement shall be 2.75% for ABR Loans (as defined in the Credit Agreement) and 3.75% for Eurodollar Loans (as defined in the Credit Agreement). From and after July 1, 2014 through the date of the Company’s delivery of a certificate for the quarter ended June 30, 2014, with respect to, among other things, the Company’s compliance with the covenants in the Credit Agreement (the "Compliance Certificate"), the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement will range from 1.50% to 2.25% for ABR Loans and from 2.50% to 3.25% for Eurodollar Loans. From and after the Company’s delivery of the Compliance Certificate, the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement will range from 1.00% to 1.75% for ABR Loans and from 2.00% to 2.75% for Eurodollar Loans.

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

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

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

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

The Amendment also (i) amends the definition of EBITDAX and provides that certain acquisitions and dispositions be given pro forma effect in the calculation of EBITDAX; (ii) increases the letter of credit commitment from $10.0 million to $50.0 million

22

and provides that outstanding letter of credit exposure not be included in certain determinations of Debt; (iii) requires the total value of the Company’s oil and gas properties included in the reserve reports for the borrowing base determinations in which the lenders under the Credit Agreement have perfected liens be increased from 80% to 90%; and (iv) modifies certain covenants in the Credit Agreement with respect to permitted investments by the Company to increase flexibility.

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

As of June 30, 2014, the borrowing base under this facility was $272.5 million, and $164.5 million of borrowings were outstanding ($218.0 million outstanding as of December 31, 2013). The borrowing base as of June 30, 2014 reflects reductions in the borrowing base of $25 million and $27.5 million related to the issuance of equity and the sale of our 100% equity interest in WHI Canada, respectively, both of which closed in May 2014. The borrowing base is subject to further automatic reductions upon the issuance of additional Senior Notes and in certain other circumstances.

At June 30, 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.

23

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 June 30, 2014 the maximum amount available under the credit agreement was $72.2 million, and the Company had $65.0 million in borrowings outstanding. The borrowing capacity is subject to certain upward or downward reductions during the term of the credit agreement.

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

Eureka Hunter Pipeline Credit Facilities

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

Equipment Note Payable

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

24

Interest Expense

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

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2014		2013		2014		2013
	(in thousands)
Interest expense incurred on debt, net of amounts capitalized	$	16,412	$	17,100	$	36,640	$	34,944
Amortization and write-off of deferred financing costs	4,022		1,693		7,643		2,550
Total Interest Expense	$	20,434	$	18,793	$	44,283	$	37,494

The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. The Company capitalized interest on its Eureka Hunter Gas Gathering System of $219,000 and $830,000 during the three and six months ended June 30, 2014, respectively, and $573,000 and $1.4 million during the three and six months ended June 30, 2013, respectively.

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

NOTE 11 - SHARE-BASED COMPENSATION

Under the Company's Amended and Restated Stock Incentive Plan, the Company may grant unrestricted common stock, restricted common stock, common stock options, and stock appreciation rights to directors, officers, employees and other persons who contribute to the success of Magnum Hunter.  Currently, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 9,610,873 shares had been issued under the plan as of June 30, 2014.

The Company recognized share-based compensation expense of $2.3 million and $3.4 million for the three and six months ended June 30, 2014, respectively, and $2.4 million and $8.7 million for the three and six months ended June 30, 2013, respectively.

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

	Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands of shares)				Weighted Average Exercise Price per Share
Outstanding at beginning of period	16,891		14,847		$	5.69	$	6.01
Granted	—		4,363		$	—	$	4.16
Exercised	(2,115	)	—		$	4.14	$	—
Forfeited	(932	)	(413	)	$	6.32	$	6.61
Outstanding at end of period	13,844		18,797		$	5.88	$	5.56
Exercisable at end of period	9,478		11,139		$	6.20	$	5.72

25

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

	Six Months Ended June 30,
	2014		2013
	(in thousands of shares)
Non-vested at beginning of period	6,908		6,163
Granted	—		4,363
Vested	(1,801	)	(2,677	)
Forfeited	(741	)	(191	)
Non-vested at end of period	4,366		7,658

Total unrecognized compensation cost related to the non-vested common stock options was $6.3 million and $14.3 million as of June 30, 2014 and 2013, respectively.  The unrecognized compensation cost at June 30, 2014 is expected to be recognized over a weighted-average period of 1.3 years. At June 30, 2014, the weighted average remaining contract life of outstanding options was 5.8 years.

During the six months ended June 30, 2014, the Company granted 1,352,575 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 $10.8 million based on the stock price on grant date and estimated forfeiture rate of 3.4%.

Total unrecognized compensation cost related to non-vested, restricted shares amounted to $8.3 million and $165,000 as of June 30, 2014 and 2013, respectively.  The unrecognized cost at June 30, 2014, is expected to be recognized over a weighted-average period of 2.4 years.

Eureka Hunter Holdings, LLC Management Incentive Compensation Plan

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

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

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

If an Award Recipient’s employment is terminated under any other circumstances, all unvested Class B Common Units and Incentive Plan Units will be forfeited immediately upon the Award Recipient’s termination of employment. In addition, vested Class B Common Units will be forfeited if an Award Recipient’s employment is terminated prior to the occurrence of a liquidity event by Eureka Hunter Holdings or an affiliate for cause or due to the Award Recipient’s resignation. If, following a termination of his or her employment by Eureka Hunter Holdings or an affiliate without cause or due to the Award Recipient’s death or disability, an

26

Award Recipient retains vested Class B Common Units, Eureka Hunter Holdings will have the right, but not the obligation, to repurchase such vested Class B Common Units at fair market value.

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

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

NOTE 12 - SHAREHOLDERS' EQUITY

Common Stock

During the six months ended June 30, 2014, the Company:

i) issued 47,426 shares of the Company’s common stock in connection with share-based compensation which had fully vested to senior management and directors of the Company;

ii) issued 2,115,000 shares of the Company’s common stock upon exercise of fully vested stock options.

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

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

Common Stock Warrants

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

27

Preferred Dividends Incurred

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Dividend on Eureka Hunter Holdings Series A Preferred Units	$	4,253	$	3,556	$	8,281	$	6,670
Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	2,229		1,696		4,277		3,164
Dividend on Series C Preferred Stock	2,562		2,562		5,124		5,124
Dividend on Series D Preferred Stock	4,425		4,425		8,849		8,807
Dividend on Series E Preferred Stock	1,861		1,890		3,695		3,852
Total dividends on Preferred Stock	$	15,330	$	14,129	$	30,226	$	27,617

Net Income or Loss per Share Data

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

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

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

	June 30,
	2014	2013
	(in thousands of shares)
Series E Preferred Stock	10,946	11,169
Warrants	19,214	13,376
Unvested restricted shares	1,475	—
Common stock options and stock appreciation rights	13,844	18,797
Total	45,479	43,342

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 $200.0 million had been purchased as of June 30, 2014.

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

28

Units outstanding at June 30, 2014 represented 41.8% of the ownership of Eureka Hunter Holdings on a basis as converted to Class A Common Units of Eureka Hunter Holdings.

During the six months ended June 30, 2014, Eureka Hunter Holdings issued 97,492 Eureka Hunter Holdings Series A Preferred Units as payment of $1.9 million in distributions paid-in-kind to holders of the Series A Preferred Units. The fair value of the embedded derivative feature of the outstanding Eureka Hunter Holdings Series A Preferred Units was determined to be $115.3 million at June 30, 2014.

Dividend expense included accretion of the Eureka Hunter Holdings Series A Preferred Units of $2.2 million and $4.3 million for the three and six months ended June 30, 2014, and $1.7 million and $3.2 million for the three and six months ended June 30, 2013, respectively.

NOTE 14 - TAXES

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

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2014		2013		2014		2013
	(in thousands)
Deferred	$	—	$	39,300	$	—	$	44,199
Income tax benefit	$	—	$	39,300	$	—	$	44,199

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

29

NOTE 15 - RELATED PARTY TRANSACTIONS

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

	June 30, 2014		December 31, 2013
	(in thousands)
Green Hunter (1)
Accounts payable - net	$	690	$	23
Derivative assets (2)	$	317	$	79
Investments (2)	$	2,423	$	2,262
Notes receivable (2)	$	1,496	$	1,768
Prepaid expenses	$	—	$	9

The Company holds investments in a related party consisting of 1,846,722 shares of common stock of GreenHunter with a carrying value of $232,896 as of June 30, 2014 and 88,000 shares of Series C preferred stock of GreenHunter with a carrying value of $2.2 million as of June 30, 2014.

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

		Three Months Ended   June 30,					Six Months Ended   June 30,
		2014		2013			2014		2013
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	613	$	590		$	935	$	1,446
	Equipment rental (1)	19		98			141		73
	Gas gathering-trucking (1)	400		—			400		—
	MAG tank panels (1)	800		—			800		—
	Office space rental	13		—			36		—
	Interest income from note receivable (2)	38		53			83		108
	Dividends earned from Series C shares	55		37			110		92
	Unrealized gain/(loss) on investments (2)	396		(151		)	161		(677		)
Pilatus Hunter, LLC
	Airplane rental expenses (3)	88		20			158		67

_________________________________

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

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

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

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

30

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 by Dux Petroleum, LLC ("Dux")asserting certain claims relating to the acreage covered by the asset purchase agreement with MNW. As a result of the litigation, no purchases were made during the first quarter of 2014. On May 28, 2014, the litigation was settled. As part of the settlement, the Company and Triad Hunter agreed to collectively pay Dux the aggregate amount of $500,000. Subsequent to the settlement of the lawsuit, Triad Hunter resumed closings of lease acquisitions from MNW. On June 5, 2014, Triad Hunter closed on the acquisition of 11,128 net leasehold acres for $45.9 million from MNW. To date, under the asset purchase agreement, Triad Hunter has now acquired a total of approximately 17,000 net leasehold acres from MNW, or approximately 53% of the approximately 32,000 total net leasehold acres anticipated under the asset purchase agreement.

Ormet Asset Acquisition

On June 18, 2014, the Company entered into an Asset Purchase Agreement ("Ormet Asset Purchase Agreement) with Ormet Corporation for the purchase of certain mineral interests in approximately 1,700 net acres, consisting of 1,375 net acres in Monroe County, Ohio and 325 net acres in Wetzel County, West Virginia. Prior to the execution of the Ormet Asset Purchase Agreement, the Company held leasehold interests in a portion of the subject acreage, which only included leasehold rights to the Marcellus zone, and carried a 12.5% royalty on production to Ormet Corporation. On July 24, 2014, the Company closed on the purchase of the sub-surface mineral interests, including any royalty interests, in the underlying acreage, giving the Company 100% ownership of and rights to oil, natural gas, and other minerals located in or under and that may be produced from the property, at any depth. The total purchase price for this transaction was approximately $22.7 million, for which the Company had previously made a deposit of $2.5 million as of June 30, 2014.

Takeover Bid

On June 20, 2014, the Company lodged a Bidder’s Statement with the Australian Securities and Investments Commission, through its wholly owned subsidiary, Outback Shale Hunter Pty Ltd, an Australian company, to commence an off-market takeover offer (the "Offer") for Ambassador Oil and Gas Limited, an Australian company listed on the Australian Securities Exchange ("ASX") (ASX: AQO) ("Ambassador").  Pursuant to the Offer, the Company is offering one share of its common stock, par value $0.01 per share, for every 23.6 ordinary (or common) shares of Ambassador. Based on the closing price of the Company’s common stock on the New York Stock Exchange of $8.20 on June 30, 2014 (and the Australian dollar/U.S. dollar exchange rate on that date), the implied value under the Offer was A$0.369 per Ambassador ordinary share.  If the Company acquires all of the Ambassador ordinary shares under the Offer, and if all of the Ambassador shareholders elect to receive shares of Company common stock, the Company will issue approximately 6,019,427 shares of its common stock at an aggregate implied value of approximately $49.4 million based on the closing price of the Company’s common stock on June 30, 2014. The Company's Offer is subject to a competing offer for Ambassador made by an Australian company listed on ASX.

Settlement Agreement with Seminole Energy Services

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

31

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

The Company and Seminole also agreed to modify the natural gas processing rates the Company will pay for processing at the Rogersville Plant, the Company's allocation of 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.

Drilling Rig Purchase

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

Legal Proceedings

Securities Cases

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

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

32

to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the stockholder derivative case maintained by Joseph Vitellone and entered a final judgment of dismissal. The court held that Mr. Vitellone failed to plead particularized facts demonstrating that pre-suit demand on the Company’s board was excused. In addition, on December 13, 2013, the 151st Judicial District Court of Harris County, Texas dismissed the lawsuit filed by Steven Handshu for want of prosecution after the plaintiff failed to serve any defendant in that matter. On January 21, 2014, the Hanft complaint was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the United States District Judge for the District of Delaware granted the Company’s supplemental motion to dismiss the Derivative Case filed by Mark Respler. All of the Derivative Cases have now been dismissed, except the Derivative Case filed by Richard Harveth, for which the Company is presently seeking dismissal. It is possible that additional stockholder derivative suits could be filed over these events.

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

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

Any potential liability from these claims cannot currently be estimated.

Twin Hickory Matter

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

In mid-February 2014, the estate of one of the deceased third-party contractor employees sued Eureka Hunter Pipeline and certain other parties in Karen S. Phipps v. Eureka Hunter Pipeline, LLC et al., Civil Action No. 14-C-41, in the Circuit Court of Ohio County, West Virginia. In April 2014, the estate of the other deceased third-party contractor employee sued the Company, Eureka Hunter Pipeline and certain other parties in Antoinette M. Miller v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-111, in the Circuit Court of Ohio County, West Virginia. The plaintiffs allege that Eureka Hunter Pipeline and the other defendants engaged in certain negligent and reckless conduct which resulted in the wrongful death of the third-party contractor employees. The plaintiffs have demanded judgment for an unspecified amount of compensatory, general and punitive damages. Various cross-claims have been asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter Resources Corporation and certain other parties in Jonathan Wisenhunt v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-135, in the Circuit Court of Ohio County, West Virginia. Investigation regarding the incident is ongoing. It is not possible to predict at this juncture the extent to which, if at all, Eureka Hunter Pipeline or any related entities will incur liability or damages because of this incident. However, the Company believes that its insurance coverage will be sufficient to cover any losses or liabilities it may incur as a result of this incident.

PRC Williston Matter

On December 16, 2013, Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. (together, the "Plaintiffs") filed suit against PRC Williston in the Court of Chancery of the State of Delaware. PRC Williston and the Plaintiffs entered into Participation Agreements in February 2007 in connection with the Plaintiffs extending credit to PRC Williston pursuant to a credit agreement entitling the Plaintiffs to a 12.5% collective interest in any distributions in respect of the equity interests of the members of PRC Williston. Plaintiffs claim that they are entitled to compensation for 12.5% of alleged past distributions on equity from PRC Williston to Magnum Hunter and 12.5% of any transfers of funds to Magnum Hunter from the proceeds of the December 30, 2013 sale of PRC Williston’s assets. On December 23, 2013,

33

the Chancery Court entered a temporary restraining order prohibiting PRC Williston from transferring, assigning, removing, distributing or otherwise displacing to Magnum Hunter, Magnum Hunter’s creditors, or any other person or entity, $5.0 million of the proceeds received by PRC Williston in connection with the sale of its assets. On March 18, 2014, the Court granted Plaintiffs’ motion for a preliminary injunction, extending the relief granted by the temporary restraining order until after a full trial on the merits. On July 24, 2014, the Company, PRC Williston, and the Plaintiffs settled this lawsuit. Pursuant to the settlement, PRC Williston paid approximately $2.9 million to the Plaintiffs. See "Note 20 - Subsequent Events" for additional information.

General

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

NOTE 17 - SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended June 30,
	2014		2013
	(in thousands)
Cash paid for interest	$	35,679	$	34,448
Non-cash transactions
Non-cash consideration received from sale of assets	$	9,447	$	42,300
Change in accrued capital expenditures	$	41,270	$	42,774
Non-cash additions to asset retirement obligation	$	13	$	1,896
Eureka Hunter Holdings Series A Preferred Unit dividends paid in kind	$	1,950	$	2,253

NOTE 18 - SEGMENT REPORTING

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

34

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

	As of and for the Three Months Ended June 30, 2014
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	78,191		$	—		$	52,117		$	7,795		$	—		$	(5,587	)	$	132,516
Depletion, depreciation, amortization and accretion	31,187			—			3,929			837			—			—			35,953
Loss on sale of assets, net	(316		)	—			—			(371		)	—			—			(687		)
Other operating expenses	37,692			—			46,700			6,361			13,054			(5,418		)	98,389
Other income (expense)	201			—			(40,457		)	(211		)	(22,498		)	—			(62,965		)
Income (loss) from continuing operations before income tax	9,829			—			(38,969		)	757			(35,552		)	(169		)	(64,104		)
Total income (loss) from discontinued operations, net of tax 1	(177		)	11,461			—			—			(12,776		)	169			(1,323		)
Net income (loss)	$	9,652		$	11,461		$	(38,969	)	$	757		$	(48,328	)	$	—		$	(65,427	)
Total assets	$	1,485,120		$	—		$	380,108		$	44,682		$	61,180		$	(7,733	)	$	1,963,357
Total capital expenditures	$	150,143		$	(3	)	$	51,993		$	2,257		$	83		$	—		$	204,473

_________________________________

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

	As of and for the Three Months Ended June 30, 2013
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	50,321		$	—		$	16,151		$	3,694		$	—		$	(2,258	)	$	67,908
Depletion, depreciation, amortization and accretion	22,573			—			3,281			521			—			—			26,375
(Gain) loss on sale of assets, net	1,179			—			—			4			—			—			1,183
Other operating expenses	37,638			—			15,468			4,254			11,485			(2,258		)	66,587
Other income (expense)	(2,589		)	—			(6,594		)	(142		)	(3,390		)	(62		)	(12,777		)
Loss from continuing operations before income tax	(13,658		)	—			(9,192		)	(1,227		)	(14,875		)	(62		)	(39,014		)
Income tax benefit (expense)	(1,674		)	(926		)	—			—			41,900			—			39,300
Total income (loss) from discontinued operations, net of tax	174,724			(1,565		)	—			—			(8,453		)	62			164,768
Net income (loss)	$	159,392		$	(2,491	)	$	(9,192	)	$	(1,227	)	$	18,572		$	—		$	165,054
Total assets	$	1,413,298		$	248,908		$	248,965		$	34,287		$	98,469		$	(8,007	)	$	2,035,920
Total capital expenditures	$	60,847		$	1,880		$	12,790		$	6,165		$	252		$	—		$	81,934

35

	As of and for the Six Months Ended June 30, 2014
	U.S. Upstream			Canadian Upstream		Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	148,365		$	—	$	86,852		$	15,706		$	—		$	(10,963	)	$	239,960
Depletion, depreciation, amortization and accretion	56,126			—		7,607			1,628			—			—			65,361
Loss on sale of assets, net	3,141			—		—			(369		)	—			—			2,772
Other operating expenses	82,421			—		78,770			13,074			23,542			(10,641		)	187,166
Other income (expense)	(77		)	—		(40,427		)	(420		)	(45,742		)	—			(86,666		)
Income (loss) from continuing operations before income tax	6,600			—		(39,952		)	953			(69,284		)	(322		)	(102,005		)
Total income (loss) from discontinued operations, net of tax 1	(23,305		)	10,636		—			—			(12,776		)	322			(25,123		)
Net income (loss)	$	(16,705	)	$	10,636	$	(39,952	)	$	953		$	(82,060	)	$	—		$	(127,128	)
Total assets	$	1,485,120		$	—	$	380,108		$	44,682		$	61,180		$	(7,733	)	$	1,963,357
Total capital expenditures	$	216,454		$	305	$	82,627		$	2,947		$	106		$	—		$	302,439

_________________________________

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

	As of and for the Six Months Ended June 30, 2013
	U.S. Upstream			Canadian Upstream			Midstream and Marketing			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	84,966		$	—		$	33,453		$	7,425		$	—		$	(3,702	)	$	122,142
Depletion, depreciation, amortization and accretion	36,836			—			5,968			859			—			—			43,663
(Gain) loss on sale of assets, net	1,160			—			—			4			—			—			1,164
Other operating expenses	81,701			—			30,136			7,953			27,475			(3,702		)	143,563
Other income (expense)	(4,712		)	—			(7,689		)	(231		)	(26,516		)	20			(39,128		)
Loss from continuing operations before income tax	(39,443		)	—			(10,340		)	(1,622		)	(53,991		)	20			(105,376		)
Income tax benefit	3,180			(926		)	—			—			41,945			—			44,199
Total income from discontinued operations, net of tax	191,213			(1,209		)	—			—			(8,453		)	(20		)	181,531
Net income (loss)	$	154,950		$	(2,135	)	$	(10,340	)	$	(1,622	)	$	(20,499	)	$	—		$	120,354
Total assets	$	1,413,298		$	248,908		$	248,965		$	34,287		$	98,469		$	(8,007	)	$	2,035,920
Total capital expenditures	$	173,191		$	14,136		$	35,085		$	14,121		$	423		$	—		$	236,956

36

NOTE 19 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS

Guarantor Subsidiaries

Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, 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. The Guarantor Subsidiaries also may guarantee any debt of the Company issued pursuant to the Form S-3 Registration Statement filed by the Company with the SEC on August 5, 2014 (see "Note 20 - Subsequent Events").

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

Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (the "Non Guarantor Subsidiaries") as of June 30, 2014 and December 31, 2013, and for the three and six months ended June 30, 2014 and 2013, are as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of June 30, 2014
	Magnum Hunter Resources Corporation		100% Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	37,995	$	75,812	$	15,539		$	(7,733	)	$	121,613
Intercompany accounts receivable	1,083,102		—		—			(1,083,102		)	—
Property and equipment (using successful efforts method of accounting)	5,939		1,381,891		310,195			—			1,698,025
Investment in subsidiaries	279,116		101,485		—			(380,601		)	—
Assets held for sale and other	17,246		88,394		38,079			—			143,719
Total Assets	$	1,423,398	$	1,647,582	$	363,813		$	(1,471,436	)	$	1,963,357
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	63,583	$	118,934	$	51,453		$	(7,774	)	$	226,196
Intercompany accounts payable	—		1,036,163		46,901			(1,083,064		)	—
Long-term liabilities	765,072		39,346		180,359			—			984,777
Redeemable preferred stock	100,000		—		149,379			—			249,379
Shareholders' equity (deficit)	494,743		453,139		(64,279		)	(380,598		)	503,005
Total Liabilities and Shareholders' Equity	$	1,423,398	$	1,647,582	$	363,813		$	(1,471,436	)	$	1,963,357

37

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

38

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Three Months Ended June 30, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	6		$	125,536		$	12,560		$	(5,586	)	$	132,516
Expenses	36,512			112,757			52,768			(5,417		)	196,620
Income (loss) from continuing operations before equity in net income of subsidiaries	(36,506		)	12,779			(40,208		)	(169		)	(64,104		)
Equity in net income of subsidiaries	(19,314		)	(984		)	—			20,298			—
Income (loss) from continuing operations before income tax	(55,820		)	11,795			(40,208		)	20,129			(64,104		)
Income tax benefit (expense)	—			—			—			—			—
Income (loss) from continuing operations	(55,820		)	11,795			(40,208		)	20,129			(64,104		)
Income from discontinued operations, net of tax	—			2,376			1,342			171			3,889
Gain on sale of discontinued operations, net of tax	(15,480		)	—			10,268			—			(5,212		)
Net income (loss)	(71,300		)	14,171			(28,598		)	20,300			(65,427		)
Net income attributable to non-controlling interest	—			—			—			780			780
Net income (loss) attributable to Magnum Hunter Resources Corporation	(71,300		)	14,171			(28,598		)	21,080			(64,647		)
Dividends on preferred stock	(8,848		)	—			(6,482		)	—			(15,330		)
Net income (loss) attributable to common shareholders	$	(80,148	)	$	14,171		$	(35,080	)	$	21,080		$	(79,977	)
	Three Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	12		$	62,065		$	8,090		$	(2,259	)	$	67,908
Expenses	16,577			74,612			17,930			(2,197		)	106,922
Income (loss) from continuing operations before equity in net income of subsidiaries	(16,565		)	(12,547		)	(9,840		)	(62		)	(39,014		)
Equity in net income of subsidiaries	(29,060		)	(113		)	(1,582		)	30,755			—
Income (loss) from continuing operations before income tax	(45,625		)	(12,660		)	(11,422		)	30,693			(39,014		)
Income tax benefit (expense)	41,900			(1,654		)	(946		)	—			39,300
Income (loss) from continuing operations	(3,725		)	(14,314		)	(12,368		)	30,693			286
Income (loss) from discontinued operations, net of tax	(8,453		)	18,903			(18,196		)	62			(7,684		)
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			172,452
Net income (loss)	160,274			4,589			(30,564		)	30,755			165,054
Net income attributable to non-controlling interest	—			—			—			386			386
Net income (loss) attributable to Magnum Hunter Resources Corporation	160,274			4,589			(30,564		)	31,141			165,440
Dividends on preferred stock	(8,877		)	—			(5,252		)	—			(14,129		)
Net income (loss) attributable to common shareholders	$	151,397		$	4,589		$	(35,816	)	$	31,141		$	151,311

39

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Six Months Ended June 30, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	114		$	229,550		$	21,258		$	(10,962	)	$	239,960
Expenses	71,305			219,841			61,460			(10,641		)	341,965
Income (loss) from continuing operations before equity in net income of subsidiaries	(71,191		)	9,709			(40,202		)	(321		)	(102,005		)
Equity in net income of subsidiaries	(48,129		)	(829		)	—			48,958			—
Income (loss) from continuing operations before income tax	(119,320		)	8,880			(40,202		)	48,637			(102,005		)
Income tax benefit (expense)	—			—			—			—			—
Income (loss) from continuing operations	(119,320		)	8,880			(40,202		)	48,637			(102,005		)
Income from discontinued operations, net of tax	—			2,259			4,669			323			7,251
Gain (loss) on sale of discontinued operations, net of tax	(19,799		)	(18,649		)	6,074			—			(32,374		)
Net income (loss)	(139,119		)	(7,510		)	(29,459		)	48,960			(127,128		)
Net income attributable to non-controlling interest	—			—			—			889			889
Net income (loss) attributable to Magnum Hunter Resources Corporation	(139,119		)	(7,510		)	(29,459		)	49,849			(126,239		)
Dividends on preferred stock	(17,668		)	—			(12,558		)	—			(30,226		)
Net income (loss) attributable to common shareholders	$	(156,787	)	$	(7,510	)	$	(42,017	)	$	49,849		$	(156,465	)
	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	(163	)	$	109,427		$	16,581		$	(3,703	)	$	122,142
Expenses	56,209			146,285			28,747			(3,723		)	227,518
Income (loss) from continuing operations before equity in net income of subsidiaries	(56,372		)	(36,858		)	(12,166		)	20			(105,376		)
Equity in net income of subsidiaries	(38,143		)	(642		)	(9,387		)	48,172			—
Income (loss) from continuing operations before income tax	(94,515		)	(37,500		)	(21,553		)	48,192			(105,376		)
Income tax benefit (expense)	41,945			3,200			(946		)	—			44,199
Income (loss) from continuing operations	(52,570		)	(34,300		)	(22,499		)	48,192			(61,177		)
Income (loss) from discontinued operations, net of tax	(8,453		)	18,794			(1,242		)	(20		)	9,079
Gain on sale of discontinued operations, net of tax	172,452			—			—			—			172,452
Net income (loss)	111,429			(15,506		)	(23,741		)	48,172			120,354
Net income attributable to non-controlling interest	—			—			—			889			889
Net income (loss) attributable to Magnum Hunter Resources Corporation	111,429			(15,506		)	(23,741		)	49,061			121,243
Dividends on preferred stock	(17,783		)	—			(9,834		)	—			(27,617		)
Net income (loss) attributable to common shareholders	$	93,646		$	(15,506	)	$	(33,575	)	$	49,061		$	93,626

40

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended June 30, 2014
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(71,300	)	$	14,171		$	(28,598	)	$	20,300	$	(65,427	)
Foreign currency translation gain	—			—			1,130			—		1,130
Unrealized loss on available for sale securities	—			(549		)	—			—		(549		)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	20,741			—			—			—		20,741
Comprehensive income (loss)	(50,559		)	13,622			(27,468		)	20,300		(44,105		)
Comprehensive income attributable to non-controlling interest	—			—			—			780		780
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(50,559	)	$	13,622		$	(27,468	)	$	21,080	$	(43,325	)

	Three Months Ended June 30, 2013
	Magnum  Hunter Resources Corporation		100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	160,274	$	4,589		$	(30,564	)	$	30,755	$	165,054
Foreign currency translation loss	—		—			(7,070		)	—		(7,070		)
Unrealized gain (loss) on available for sale securities	4,700		(234		)	—			—		4,466
Comprehensive income (loss)	164,974		4,355			(37,634		)	30,755		162,450
Comprehensive income attributable to non-controlling interest	—		—			—			386		386
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	164,974	$	4,355		$	(37,634	)	$	31,141	$	162,836

41

	Six Months Ended June 30, 2014
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(139,119	)	$	(7,510	)	$	(29,459	)	$	48,960	$	(127,128	)
Foreign currency translation loss	—			—			(1,218		)	—		(1,218		)
Unrealized loss on available for sale securities	—			(605		)	—			—		(605		)
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	20,741			—			—			—		20,741
Comprehensive income (loss)	(118,378		)	(8,115		)	(30,677		)	48,960		(108,210		)
Comprehensive income attributable to non-controlling interest	—			—			—			889		889
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(118,378	)	$	(8,115	)	$	(30,677	)	$	49,849	$	(107,321	)

	Six Months Ended June 30, 2013
	Magnum  Hunter Resources Corporation		100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	111,429	$	(15,506	)	$	(23,741	)	$	48,172	$	120,354
Foreign currency translation loss	—		—			(11,799		)	—		(11,799		)
Unrealized gain (loss) on available for sale securities	4,700		(251		)	—			—		4,449
Comprehensive income (loss)	116,129		(15,757		)	(35,540		)	48,172		113,004
Comprehensive income attributable to non-controlling interest	—		—			—			889		889
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	116,129	$	(15,757	)	$	(35,540	)	$	49,061	$	113,893

42

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	Six Months Ended June 30, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(192,121	)	$	182,620		$	28,248		$	—	$	18,747
Cash flow from investing activities	49,572			(177,365		)	(57,579		)	—		(185,372		)
Cash flow from financing activities	111,324			3,038			19,629			—		133,991
Effect of exchange rate changes on cash	—			—			41			—		41
Net increase (decrease) in cash	(31,225		)	8,293			(9,661		)	—		(32,593		)
Cash at beginning of period	47,895			(17,651		)	11,469			—		41,713
Cash at end of period	$	16,670		$	(9,358	)	$	1,808		$	—	$	9,120

	Six Months Ended June 30, 2013
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Cash flow from operating activities	$	(156,721	)	$	146,932		$	83,657		$	—	$	73,868
Cash flow from investing activities	371,970			(152,127		)	(115,645		)	—		104,198
Cash flow from financing activities	(224,493		)	4,051			17,852			—		(202,590		)
Effect of exchange rate changes on cash	—			—			(357		)	—		(357		)
Net increase (decrease) in cash	(9,244		)	(1,144		)	(14,493		)	—		(24,881		)
Cash at beginning of period	26,871			(4,186		)	34,938			—		57,623
Cash at end of period	$	17,627		$	(5,330	)	$	20,445		$	—	$	32,742

43

NOTE 20 - SUBSEQUENT EVENTS

Sale of Class A Common Units of Eureka Hunter Holdings

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

PVA Arbitration Decision

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

PRC Settlement

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

Ormet Asset Acquisition

On July 24, 2014, our wholly owned subsidiary, Triad Hunter LLC, closed on the acquisition of mineral interests from the Ormet Corporation for total cash consideration of approximately $22.7 million, for which Triad Hunter LLC received a credit of $2.5 million for funds previously deposited in escrow in June 2014.

Form S-3 Registration Statement

On August 5, 2014, the Company filed a universal shelf Form S-3 Registration Statement to register the sale by the Company of an unlimited amount of debt and equity securities, and such registration statement became effective automatically upon filing. The guarantor financial information as of and for the three and six months ended June 30, 2014, included in Note 19 - Condensed Consolidated Guarantor Financial Statements, is applicable to any Guarantor Subsidiaries that may guarantee any debt issued by the Company pursuant to the Form S-3 Registration Statement.

44

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

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

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

Cautionary Notice Regarding Forward-looking Statements

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

These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management.  These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors.  Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control.  In addition, management’s assumptions about future events may prove to be inaccurate.  We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur.  Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors detailed below and discussed in our Annual Report on Form 10-K for the year ended December 31, 2013, as amended.  All forward-looking statements speak only as of the date of this report.  We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise.  These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

• global economic and financial market conditions,

• our business strategy,

• estimated quantities of oil and natural gas reserves,

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

• disruption of credit and capital markets,

• our financial position,

• our cash flow and liquidity,

• replacing our oil and natural gas reserves,

• our inability to retain and attract key personnel,

• uncertainty regarding our future operating results,

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

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

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

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

• competition in the oil and natural gas industry,

45

• 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 SEC, including this Quarterly Report on Form 10-Q.

Executive Overview

We are a Houston, Texas based independent oil and natural gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and NGL resources in the 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 second quarter of 2014:

• Oil and natural gas revenues from continuing operations increased by 57.7% to $78.2 million compared to $49.6 million during the same three-month period in 2013.

• We reported a net loss from continuing operations of $64.1 million for the three months ended June 30, 2014, compared to net income from continuing operations of $286,000 for the three months ended June 30, 2013.

• Our estimated total proved oil and natural gas reserves at June 30, 2014 increased by 7.7 million MMBoe or a 10.7% improvement compared to December 31, 2013.

• Our total oil and natural gas production from continuing operations increased to 15,923 Boe/d (17,822 Boe/d including discontinued operations) for the three months ended June 30, 2014, compared to 10,664 Boe/d (15,125 Boe/d including discontinued operations) for the same period in 2013. Average production for the second quarter of 2014 was comprised of 43.7% liquids and 56.3% natural gas.

• As of June 30, 2014, we had approximately 290,007 net leasehold acres in our core operating areas, including (i) approximately 80,289 net acres in the Marcellus Shale, (ii) approximately 118,496 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and (iii) approximately 91,222 net acres in the Williston Basin/Bakken Shale in North Dakota.

• Pipeline throughput in our Midstream Segment increased to an average of 223,573 MMBtu/d for the three months ended June 30, 2014 compared to 82,526 MMBtu/d for the same period in 2013.

• Our capital expenditures of $204.5 million during the second quarter of 2014 increased from the first quarter of 2014 as we focused our efforts on drilling in the Marcellus Shale and Utica Shale.

Recent Developments

MNW Lease Acquisitions

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

46

Triad has now acquired a total of approximately 17,000 net leasehold acres from MNW, or approximately 53% of the approximately 32,000 total net leasehold acres anticipated under the APA.

Ormet Asset Purchase Agreement

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

PRC Settlement

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

Takeover Bid for Australian Company

On June 20, 2014, we lodged a Bidder’s Statement with the Australian Securities and Investments Commission, through our wholly owned subsidiary, Outback Shale Hunter Pty Ltd, an Australian company, to commence an off-market takeover offer (the "Offer") for Ambassador Oil and Gas Limited, an Australian company listed on the Australian Securities Exchange ("ASX") (ASX: AQO) ("Ambassador").  Pursuant to the Offer, we are offering one share of our common stock, par value $0.01 per share, for every 23.6 ordinary (or common) shares of Ambassador.  Based on the closing price of the Company’s common stock on the New York Stock Exchange of $8.20 on June 30, 2014 (and the Australian dollar/U.S. dollar exchange rate on that date), the implied value under the Offer was A$0.369 per Ambassador ordinary share.  If the Company acquires all of the Ambassador ordinary shares under the Offer, and if all of the Ambassador shareholders elect to receive shares of Company common stock, the Company will issue approximately 6,019,427 shares of its common stock at an aggregate implied value of approximately $49.4 million based on the closing price of the Company’s common stock on June 30, 2014. The Company's Offer is subject to a competing offer for Ambassador made by an Australian company listed on ASX.

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, of which four were operated by the Company. We received cash consideration of $15.5 million, after customary purchase price adjustments, and 65,650,000 ordinary shares of NSE, with a fair value of approximately $8.3 million at June 30, 2014. The Company recognized a loss on the sale of these assets of $4.5 million. As a result of the sale, we own approximately 17% of the total outstanding common shares of NSE, and have the right to appoint, and have appointed, two designated representatives to NSE's board of directors.

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.

47

WHI Canada and MHP

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

We continue to market the sale of our 100% equity interest in MHP, and expect that a purchase and sale agreement will be executed before the end of 2014. The assets and liabilities of MHP continue to be classified as assets held for sale in our consolidated balance sheet and as discontinued operations in our consolidated statements of operations.

Equity Financing

During the six-month period ended June 30, 2014, we raised cash in the total amount of $199.4 million in net proceeds after offering discounts, commissions and placement fees, but before other offering expenses. These capital market and equity transactions included:

• $149.7 million in net proceeds from the issuance of 21,428,580 shares of our common stock at a price of $7.00 per share and warrants to purchase up to an aggregate of 2,142,858 shares of common stock at an initial exercise price of $8.50 per share in a private placement;

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

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

• $8.8 million in net proceeds from the issuance of 2,115,000 shares of our common stock upon exercise of stock options.

Amendment to Senior Credit Facility

On May 6, 2014, the Company executed an amendment to the Third Amended and Restated Credit Agreement, dated as of December 13, 2013 (the "Credit Agreement"), by and among the Company, as borrower, the guarantors party thereto, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto. With the execution of the amendment, the Company's borrowing base under the Credit Agreement was increased from $232.5 million to $325.0 million in connection with the regular semi‑annual redetermination of the borrowing base derived from the Company’s proved crude oil and natural gas reserves. The amendment also provided for required reductions in the borrowing base upon sale of certain specified assets, and modified other terms including certain financial covenants. As of June 30, 2014, the borrowing base had been reduced to $272.5 million as a result of the sale of WHI Canada and the issuance of equity, as contemplated in the amendment.

Sale of Class A Common Units of Eureka Hunter Holdings

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

48

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 June 30, 2014, Eureka Hunter Pipeline had borrowed $65.0 million under the Eureka Hunter Pipeline Credit Agreement.

Dismissal of Consolidated Class Action Securities Case

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

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

Seminole Settlement

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

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

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

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

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

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

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

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

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

49

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.

Magnum Hunter Marketing Revenues

As a result of the substantial increase in their production of natural gas and other factors, in June 2014, JayBee Oil & Gas ("Jaybee"), the primary unaffiliated customer of Magnum Hunter Marketing ("MHM"), informed MHM that it would be marketing all of its natural gas production previously marketed by MHM effective July 1, 2014. MHM realized revenues from sales of natural gas purchased from Jaybee for the three and six months ended June 30, 2014 of $37.4 million and $59.0 million, respectively. The gross margin realized through the marketing of Jaybee’s natural gas was approximately $0.9 million and $0.2 million for the three and six months ended June 30, 2014. Realized revenues from sales of natural gas purchased from Jaybee for the three and six months ended June 30, 2013 was $9.4 million and $20.2 million, respectively. The gross margin realized through the marketing of Jaybee’s natural gas was approximately $(1.1) million and $(0.9) million for the three and six months ended June 30, 2013. Absent new marketing agreements, MHM’s revenues from unaffiliated customers, and related costs, will be substantially lower beginning in the third quarter of 2014.

Natural Gas Prices

During the second quarter of 2014, natural gas prices continued to decline due to mild summer weather and increases in overall production from the shale plays. The basis differential in Appalachia has weakened against NYMEX, with deliveries into TETCO M2 pricing at approximately $1.50 under most forward curves. During the second quarter of 2014, the price realized per MMBtu by MHM through its marketing activities decreased by 28% compared to the prior quarter. If prices continue to decline as a result of increased supply without sufficient takeaway capacity for this region, this could impact the level of natural gas that companies are willing to produce until additional takeaway capacity becomes available.

Operational Update - Second Quarter 2014

During the three-month period ended June 30, 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 second quarter of 2014.

U.S. Upstream

Operated Properties

Marcellus Shale

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

The WVDNR #1410, #1411, #1412 and #1413 (~100% working interest) will be drilled horizontally with an expected true vertical depth of 7,500 feet. The anticipated lateral lengths are 3,930 feet, 4,630 feet, 5,325 feet and 5,840 feet, respectfully. A rig was on location the first week of July 2014 to begin operations.

Ormet Pad - Following the drilling and completion of the Ormet 1-9H, 2-9H, and 3-9H wells (~100% working interest) during the first quarter of 2014, these three wells located in Monroe County, Ohio began flowing to sales through the Eureka Hunter Pipeline gathering system during the second week of May 2014 and had a 7-day average daily production (net) of approximately 1,800 BOE (10,800 MCF) at June 30, 2014. These wells were drilled and cased to an average vertical depth of 5,900 feet with a 3,900 foot average horizontal lateral.

50

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

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. These wells are currently being fracture stimulated simultaneously.

Utica Shale

Stewart Winland Pad - The Stewart Winland #1300 was drilled to a true vertical depth of 11,050 feet. The Stewart Winland #1300 well’s targeted Utica/Point Pleasant formation is approximately 350 feet deeper than that same formation to which the Company’s first Utica Shale dry gas well, the Stalder #3UH in Monroe County, Ohio, was drilled. The wireline logging data has confirmed the Point Pleasant target formation from the Stewart Winland #1300 pad location contains hydrocarbons and appears to possibly have even more bottom hole pressure than the Stalder #3UH. We drilled and cased a 5,500 foot lateral on the Stewart Winland #1300, which has approximately 22 frac stages. Initial production from these wells is expected in mid-September 2014.

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

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

Well	Measured Depth	Lateral Length
	(in feet)
Stalder #6UH	16,800	5,900
Stalder #7UH	17,100	6,000
Stalder #8UH	18,100	6,500

A drilling rig commenced drilling the Stalder #8UH on May 21, 2014. Intermediate 9 5/8" casing was set to a measured depth of 9,685 feet. The drilling rig was then skid over to the Stalder #7UH and is currently drilling the vertical 12 ¼" intermediate section on air. Each well will initially be drilled to intermediate casing point with the casing set and cemented before the curve and lateral sections are drilled.

Ormet 15 Pad - We plan to drill 5 down-dip Marcellus and 4 down-dip Utica laterals on our second Ormet Pad location in Monroe County, Ohio. Initial plans are to drill the four Utica laterals: Ormet #7-15UH, #8-15UH, #9-15UH and #10-15UH (~100% working interest) this year. The estimated true vertical depth for the Utica laterals is 11,100 feet. The proposed measured depth and lateral lengths for each well are as follows:

Well	Measured Depth	Lateral Length
	(in feet)
Ormet #7-15UH	16,200	4,700
Ormet #8-15UH	15,800	4,600
Ormet #9-15UH	16,300	4,700
Ormet #10-15UH	16,900	4,800

Alpha Hunter commenced drilling the Ormet #10-15UH on June 20, 2014.

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

51

vertical depth of 7,914 feet with a 5,400 foot horizontal lateral. These two new wells are still awaiting completion operations pending pipeline completion. We have redeployed our resources towards the Stalder and Stewart Winland wells, and expect to begin fracture stimulation of the new Utica wells, the Farley #1306H and #1304H, in 2015.

Non-operated Properties

Mills Wetzel - As of June 30, 2014, Stone Energy, which owns a 50% working interest, was building out the production facility on Pad 3 that includes 8 Marcellus laterals. Triad has a 50% working interest in the Mills Wetzel wells.

Merlin Unit - The Merlin #10PPH Utica lateral is being drilled and operated by EdgeMarc Energy. Triad Hunter owns a 13.56% working interest in the Merlin #10PPH. The Merlin #10PPH is located in Washington County, Ohio, approximately 5.1 miles southeast of Triad Hunter’s Farley Pad. The Merlin #10PPH has an estimated true vertical depth of 8,050 feet and estimated lateral length of 7,200 feet. The estimated measured depth (MD) is 15,800’. The Helmerich & Payne (HP) Rig #521 commenced drilling this well on June 21, 2014.

Williston Basin/Bakken Shale

During the first six months of 2014, we participated in the spudding of 17 gross (3.1 net) wells and the completion of 19 gross (5.3 net) wells in Divide County, North Dakota. Seven of the completed wells utilized plug and perforation technology.

A third-party has been engaged to gather and transport oil from certain of our non-operated wells in Divide County to the Colt Hub in Epping, North Dakota to eliminate trucking costs and minimize downtime during spring break-up. We expect that approximately 51 existing wells and 18 wells scheduled to be drilled under the operator’s 2014 drilling program will be connected to the gathering system, which is expected to be fully operational by 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. The Bonneville pad was connected in May and construction has commenced on the north gathering pipeline. Construction is expected to begin on the south gathering pipeline mid-July. The engineering and design of the truck terminal has been initiated.

As of June 30, 2014, our operators in Divide County have electrified approximately 113 gross wells and tied in approximately 183 gross wells into the Oneok, Inc. gas gathering system in Divide County and production and revenues from the gathering of associated gas from the tied-in wells are growing monthly. Approvals from both the Canadian National Energy Board and the U.S. Federal Energy Regulatory Commission have been obtained for the cross-border Tableland Gas gathering project being constructed by the Company and the buyer of WHI Canada and project start-up is expected during the third quarter of 2014. The completion of the project is expected to bring ~ 600 Mcf/d of associated gas to our account, which would be applied towards our Oneok gas sales volume commitment.

U.S. Upstream Drilling and Capital Expenditures

In addition to the drilling and completion activities on our non-operated properties in the Williston Basin and Bakken Shale discussed above, during the three-month period ended June 30, 2014, the Company drilled a total of 4 wells in which we own a 100% interest, and completed 5 gross (2.1 net) wells in the Appalachian Basin.

During the second quarter of 2014, we acquired specific oil and gas leasehold acreage covering a total of approximately 19,425 gross (15,228 net) leasehold acres located in various areas including Washington, Noble and Monroe Counties, Ohio and Tyler, Ritchie and Wetzel Counties, West Virginia, for an aggregate purchase price of approximately $66.2 million (approximately $4,347 average per net leasehold acre). These acquisitions include leasehold acreage acquired from MNW Energy, LLC ("MNW") pursuant to the Asset Purchase Agreement entered into in August 2013, which acquisitions were resumed in June 2014 following the settlement of certain litigation filed against us and MNW.

During the second quarter of 2014, we incurred related capital expenditures of $137.4 million comprised of $77.5 million in proved property additions, and $59.9 million in leasehold acquisitions.

52

Midstream

Eureka Hunter Pipeline

Eureka Hunter Pipeline recently achieved a peak throughput rate of 268,361 MMBtu per day in July 2014. During the second quarter of 2014, Eureka Hunter’s gas gathering pipeline system averaged 223,573 MMBtu per day. During June 2014, Triad Hunter, LLC ("Triad"), our wholly-owned subsidiary, produced approximately 38% of the volumes that flowed through the Eureka Hunter Pipeline system.

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

Eureka Hunter Pipeline expects to add significant throughput volumes from a combination of Triad's new wells mentioned above and other third parties' production during the remainder of 2014. Throughput volumes are expected to reach 400,000 MMBtu per day by the end of 2014. Much of the added throughput will be dry gas from the Utica shale being delivered into various interstate pipeline connections planned in or near Monroe County, Ohio, which includes Dominion, REX and TETCO. The initiation of dry gas from the Utica shale will mark a significant milestone for Eureka Hunter Pipeline as the system will be flowing dry gas north and will continue to move wet gas from the Marcellus shale east to Mobley.

Eureka Hunter Pipeline has plans to add an interconnect into Natrium (Blue Racer Midstream) to increase its Marcellus shale wet deliveries on the system to 500 MMcf/d plus, expected to be completed by year-end.

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

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

Midstream Capital Expenditures

During the three-month period ended June 30, 2014, our midstream segment incurred capital expenditures of $52.0 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.

As of June 30, 2014, four of the Schramm T200XD drilling rigs were under contract to EQT in the Appalachian Basin area for the top-hole drilling of multiple wells through December 2015; one Schramm T200XD drilling rig was under contract through October 2014 to Eclipse in the Appalachian Basin, and will also be utilized by us for our top-hole drilling program; and our largest Schramm T500XD drilling rig was under contract to Triad, one of our subsidiaries, for our Utica Shale drilling program. All these contracts are term contracts. Rigs deployed under contracts with non-affiliated companies were running on contracted daily rates of $12,500.

The mud systems for four of the drilling rigs are in the yard being reworked with two new mud pumps. Delivery should occur in August 2014, and will go out for EQT. Additionally, in June 2014, we executed a contact to purchase a new Schramm T500XD. We have made a down payment under this contract and expect the total price of the rig and related equipment to be approximately $17 million with delivery in the first quarter of 2015. We plan to use this rig in our drilling operations in the Utica Shale.

53

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 and six months ended June 30, 2014 and 2013, respectively. 

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2014		2013		2014		2013
Oil and natural gas revenue and production
Revenues (in thousands, U.S. Dollars)
Oil	$	39,839	$	33,122	$	74,111	$	58,694
Natural gas	25,453		12,810		49,583		21,263
NGL	12,898		3,651		24,668		4,267
Total oil and natural gas sales	$	78,190	$	49,583	$	148,362	$	84,224
Production
Oil (MBbl)	411		392		824		686
Natural gas (MMcf)	4,898		2,988		9,205		5,084
NGL (MBoe)	222		81		422		96
Total (MBoe)	1,449		970		2,781		1,629
Boe/d	15,923		10,664		15,363		9,002
Average prices (U.S. Dollars)
Oil (per Bbl)	$	97.02	$	84.57	$	89.93	$	85.52
Natural gas (per Mcf)	$	5.20	$	4.29	$	5.39	$	4.18
NGL (per Boe)	$	58.08	$	45.18	$	58.40	$	44.60
Total average price (per Boe)	$	53.96	$	51.10	$	53.35	$	51.70
Costs and expenses (per Boe)
Lease operating expense	$	10.24	$	15.68	$	12.51	$	14.05
Severance tax and marketing	$	4.57	$	4.14	$	4.39	$	4.20
Exploration expense	$	6.34	$	3.65	$	8.35	$	20.43
Impairment of proved oil and natural gas property	$	0.11	$	10.27	$	0.06	$	6.12
General and administrative expense (1)	$	12.93	$	16.86	$	12.23	$	22.31
Depletion, depreciation and accretion	$	24.81	$	27.18	$	23.50	$	26.80
Other segments (in thousands)
Natural gas transportation, gathering, processing and marketing revenues	$	48,363	$	13,974	$	80,012	$	29,870
Natural gas transportation, gathering, processing and marketing expenses	$	44,754	$	13,414	$	74,753	$	26,845
Oilfield services revenues	$	5,954	$	3,612	$	11,575	$	7,305
Oilfield services expenses	$	4,089	$	4,066	$	8,036	$	7,401

_________________________________

(1) General and administrative expense includes: (i) transaction and professional services expenses of $7.0 million ($4.81 Boe) for the three months ended June 30, 2014 and $4.8 million ($4.95 Boe) for the three months ended June 30, 2013, (ii) transaction and professional services expenses of $13.7 million ($4.92 Boe) for the six months ended June 30, 2014 and $11.9 million ($7.31 Boe) the six months ended June 30, 2013, (iii) non-cash stock compensation of $2.3 million ($1.60 Boe) for the three months ended June 30, 2014 and $2.4 million ($2.52 Boe) for the three months ended June 30, 2013, and (iv) non-cash stock compensation of $3.4 million ($1.21 Boe) for the six months ended June 30, 2014 and $8.7 million ($5.34 Boe) for the six months ended June 30, 2013.

54

Three Months Ended June 30, 2014 and 2013

Oil and natural gas production. Production increased by 49.3%, or 479 MBoe, to 1,449 MBoe for the three months endedJune 30, 2014 compared to the three months endedJune 30, 2013. Our average daily production was 15,923 Boe/d during the 2014 period, representing an overall increase of 49.3%, or 5,259 Boe/d, compared to 10,664 Boe/d for the 2013 period. Oil and NGL production for the three months ended June 30, 2014 was 633 MBoe versus 473 MBoe for the three months ended June 30, 2013, an increase of 33.8%. 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 Williston Basin/Bakken fields. Specifically, natural gas production from the Appalachian Basin alone, increased from 2,806 MMcf for the three months ended June 30, 2013 to 4,622 MMcf for the three months ended June 30, 2014; an increase of 64.7%.

Further, the Williston/Bakken fields contributed an additional 16 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 June 30, 2014, on a Boe basis, was 43.7% oil and NGL and 56.3% natural gas compared to 48.7% oil and NGL and 51.3% natural gas for the same period in 2013.

Oil and natural gas sales. Oil and natural gas sales increased 57.7%, or $28.6 million, for the three months endedJune 30, 2014 to $78.2 million from $49.6 million for the three months endedJune 30, 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 oil, natural gas, and NGL of 14.7%, 21.2% and 28.6%, respectively. Our natural gas sales in 2014 benefited from increased production from natural gas flowing to sales from our Collins, Ormet, and WVDNR wells, which were not on production during 2013. Of the total increase in oil and natural gas sales for the 2014 period, $12.4 million was attributable to the increase in prices received and $16.2 million was attributable to our increase in production. The prices we receive for our products are generally tied to commodity index prices.

Natural gas transportation, gathering, processing and marketing revenues. Revenue from midstream operations (which consist of Eureka Hunter Pipeline, TransTex Hunter, and Magnum Hunter Marketing operations) increased by $34.4 million, or 246.1%, for the three months endedJune 30, 2014 to $48.4 million from $14.0 million for the three months endedJune 30, 2013. TransTex Hunter revenues decreased by $0.2 million. Eureka Hunter Pipeline revenues increased by $4.4 million as a result of new growth in third party customer contracts as well as increased volumes of natural gas product gathered from its pipeline gathering system from existing customers. Eureka Hunter Pipeline increased throughput volumes by 170.8% or 12.8 million MMBtu to 20.3 million MMBtu for the three months ended June 30, 2014 from 7.5 million MMBtu for the three months ended June 30, 2013. Magnum Hunter Marketing revenues increased by $30.2 million to $39.6 million during the three months ended June 30, 2014 from $9.4 million during the three months ended June 30, 2013. Magnum Hunter Marketing revenues increased as a result of new customers, growth from existing customers, and increased gas and NGL revenues from the Markwest Mobley processing plant.

Oilfield services revenue. Drilling services revenue increased by 64.8%, or $2.3 million, for the three months endedJune 30, 2014 to $6.0 million from $3.6 million for the three months endedJune 30, 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 June 30, 2014, our drilling rig revenue days increased from 201 to 355 as compared to the three months ended June 30, 2013, primarily as a result of the addition of 2 rigs to our fleet and full utilization of 2 existing rigs.

Gain (loss) on sale of assets. We recorded a gain on sale of assets in operating expenses of $0.7 million for the three months ended June 30, 2014, which included a gain of $1.4 million related to the sale of certain oil and natural gas properties in Lewis County, West Virginia, partially offset by post-closing adjustments related to the sales of certain oil and natural gas properties during the latter part of 2013 and early part of 2014.

Lease operating expense. Our lease operating expenses ("LOE"), decreased$0.4 million, or 2.5%, for the three months endedJune 30, 2014 to $14.8 million ($10.24 Boe) from $15.2 million ($15.68 Boe) for the three months endedJune 30, 2013. The fluctuation in LOE was comprised of an increase of $7.5 million attributable to increased production volumes, offset by a decrease of $7.9 million attributable to lower LOE/Boe costs. Of the decrease in LOE/Boe costs, $3.4 million was due to lower Appalachian Basin third party gas transportation charges, $1.4 million was due to lower recurring costs primarily in the Williston Basin, and $3.1 million was due to lower non-recurring work-over expenses in the Williston Basin for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013.

Severance taxes.  Our severance taxes increased$2.6 million, or 65.0%, for the three months endedJune 30, 2014, to $6.6 million from $4.0 million for the three months endedJune 30, 2013.  The increase in severance taxes was attributable primarily to the increase in our production and sales.  

55

Exploration. We record exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. We recorded $9.2 million of exploration expense for the three months endedJune 30, 2014, compared to $3.5 million for the three months ended June 30, 2013. During the 2014 period, the Company's exploration expense was primarily attributable to $8.8 million of leasehold impairments relating to leases in the Williston Basin region that expired undrilled during the three months ended June 30, 2014 or are expected to expire and that the Company does not plan to develop. The Company's exploration expense during the three months ended June 30, 2013 of $3.3 million primarily related to leases in the Williston Basin.

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

During the three months endedJune 30, 2014, changes in production estimates and lease operating costs provided indications of possible impairment on two legacy fields that are unrelated to our current drilling and development plan. As a result of our assessment, we recorded impairment of proved oil and natural gas properties in continuing operations of $0.2 million during the three months endedJune 30, 2014 to reduce the carrying value of these properties to their estimated fair values. During the three months endedJune 30, 2013, we recorded impairment of proved oil and natural gas properties in the Williston and Appalachian Basins of $10.0 million. We calculated the estimated fair values using a discounted cash flow model. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Natural gas transportation, gathering, processing and marketing expenses. Expenses from the midstream operations increased by $31.3 million, or 233.6%, for the three months endedJune 30, 2014 to $44.8 million from $13.4 million for the three months endedJune 30, 2013 due to increased cost of gas marketed by Magnum Hunter Marketing along with Magnum Hunter Marketing's increased activities.

Oilfield services expenses.  Oilfield services expenses remained consistent at approximately $4.1 million for the three months endedJune 30, 2014 and the three months endedJune 30, 2013.

Depletion, depreciation, amortization, and accretion. Our depletion, depreciation, amortization and accretion expense ("DD&A"), increased $9.6 million, or 36.3%, to $36.0 million for the three months endedJune 30, 2014, from $26.4 million for the three months endedJune 30, 2013, due to increases in accumulated costs from our capital expenditure and acquisition programs during 2013 and 2014, and increased production in 2014. Our DD&A/Boe decreased by $2.37, or 8.7%, to $24.81 Boe for the three months endedJune 30, 2014, compared to $27.18 Boe for the three months endedJune 30, 2013. The decrease in DD&A/Boe was primarily attributable to an increase in natural gas production from continuing operations. Natural gas wells generally have a lower rate on a Boe basis than oil and NGL. The Company's natural gas production increased significantly due to its drilling in the Appalachian Basin.

General and administrative. Our general and administrative expenses ("G&A"), increased $2.4 million, or 14.5%, to $18.7 million or $12.93 Boe for the three months endedJune 30, 2014 from $16.4 million or $16.86 Boe for the three months endedJune 30, 2013. G&A expenses increased overall from 2013 mainly due to higher transaction and professional services expenses. Non-cash stock compensation expense decreased by $0.1 million, to approximately $2.3 million or $1.60 Boe for the three months endedJune 30, 2014 from $2.4 million or $2.52 Boe for the three months endedJune 30, 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 9.0%, to $20.4 million from $18.7 million for the three months endedJune 30, 2014, compared to the three months endedJune 30, 2013. Higher amortization and write-off of deferred financing costs accounted for $2.3 million of the increase, which was partially offset by $0.7 million due to a lower average debt level in the second quarter of 2014 compared to the 2013 period. Interest expense was offset by capitalized interest of $0.2 million and $0.6 million during the three months endedJune 30, 2014 and 2013, respectively. We capitalize interest on projects lasting six months or longer.

56

Commodity and financial derivative activities. Our commodity and financial derivative activity resulted in net loss of $42.8 million for the quarter ended June 30, 2014, compared to a net gain of $6.4 million for the quarter ended June 30, 2013. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:

	Three Months Ended   June 30,
	2014			2013
	(in thousands)
Commodity derivatives
Realized gain (loss) on settled transactions	$	(2,267	)	$	(1,261	)
Unrealized gain (loss) on open contracts	(1,021		)	12,997
Total commodity derivatives	(3,288		)	11,736
Financial derivatives
Unrealized gain (loss) on open contracts	(39,548		)	(5,336		)
Net gain (loss)	$	(42,836	)	$	6,400

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

At June 30, 2014, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Eureka Hunter Holdings Series A Preferred Units. This embedded derivative instrument resulted in unrealized losses of $39.8 million and $5.2 million in the three months endedJune 30, 2014 and 2013, respectively. The change in unrealized loss was driven primarily by increases in total enterprise value and a reduction in the expected term of the conversion feature.

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

Also at June 30, 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. An unrealized gain of $282,000 and an unrealized loss of $167,000 are recorded for this embedded derivative instrument in the three months endedJune 30, 2014 and 2013, respectively. Both derivative instruments originated in 2012 and the derivative instruments have resulted in no cash outlays as of June 30, 2014.

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

Income tax benefit.  We were in a net operating loss position as of June 30, 2014, and have a full valuation allowance on all deferred tax assets. As a result, we did not recognize an income tax benefit on our June 30, 2014 net loss, whereas we recognized a benefit of $39.3 million for the three months ended June 30, 2013 due to the gain on sale of discontinued operations which allowed us to utilize a portion of the deferred tax asset otherwise reserved against.

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

Income (loss) from discontinued operations was income of $3.9 million and loss of $7.7 million for the three months ended June 30, 2014 and 2013, respectively. The following table summarizes the income (loss) from discontinued operations for the periods indicated:

57

	Three months ended June 30,
	2014		2013
	(in thousands)
Eagle Ford Hunter	$	—	$	80
Magnum Hunter Production	2,697		(3,919		)
Williston Hunter Canada	1,192		(3,845		)
	$	3,889	$	(7,684	)

Gain (loss) on disposal of discontinued operations, net of tax. Loss on disposal of discontinued operations was $5.2 million for the three months ended June 30, 2014 and gain on disposal of discontinued operations was $172.5 million for the three months ended June 30, 2013. The following table summarizes the gain (loss) on disposal of discontinued operations for the periods indicated:

	Three months ended June 30,
	2014			2013
	(in thousands)
Eagle Ford Hunter	$	(2,705	)	$	172,452
Williston Hunter Canada	(2,507		)	—
	$	(5,212	)	$	172,452

During the three-months ended September 30, 2013, we estimated that the final working capital adjustment on the sale of Eagle Ford Hunter would be approximately $32.9 million. We accrued a liability of $32.9 million and recorded a corresponding downward adjustment to the $172.5 million preliminary gain recognized as of June 30, 2013. As of June 30, 2014 we estimated that the final working capital adjustment related to the Eagle Ford Hunter sale would be a reduction to the preliminary gain recognized of $33.7 million, plus accrued interest of $1.3 million.  The Company has recorded a liability for its revised estimate of the final adjustment.

Net income attributable to non-controlling interest.  Net loss attributable to non-controlling interest was approximately $780,000 for the three months ended June 30, 2014 and $386,000 for same period in 2013.  This represents 12.5% of the gain or loss of our majority-owned subsidiary, PRC Williston, and 1.7% of the net income or loss attributable to our majority-owned subsidiary, Eureka Hunter Holdings. 

Dividends on preferred stock. Total dividends on our preferred stock were approximately $15.3 million for the three months endedJune 30, 2014 compared to $14.1 million for the 2013 period.

The Series C Preferred Stock had a stated value of $100.0 million at June 30, 2014 and December 31, 2013, and carries a cumulative dividend rate of 10.25% per annum. The Series D Preferred Stock had a stated value of $221.2 million and $221.2 million at June 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million and $95.1 million as of June 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Eureka Hunter Holdings Series A Preferred Units had a liquidation preference of $214.8 million and $200.6 million as of June 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum.

Six Months Ended June 30, 2014 and 2013

Oil and natural gas production.  Production increased by 70.7%, or 1,152 MBoe, to 2,781 MBoe for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Oil and NGL production for the six months ended June 30, 2014 was 1,246 MBoe versus 782 MBoe for the six months ended June 30, 2013, a increase of 59.3%. 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 Williston Basin/Bakken fields. Specifically, natural gas production from the Appalachian Basin alone, increased from 4,724 MMcf for the six months ended June 30, 2013 to 8,662 MMcf for the six months ended June 30, 2014, an increase of 83.4%.

Further, the Williston/Bakken fields contributed an additional 148 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 six months ended June 30, 2014, on a Boe basis, was 44.8% oil and NGL and 55.2% natural gas compared to 48.0% oil and 52.0% natural gas for the same period in 2013. 

58

Oil and natural gas sales.  Oil and natural gas sales increased$64.1 million, or 76.2% for the six months ended June 30, 2014, to $148.4 million from $84.2 million for the six months ended June 30, 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 oil, natural gas, and NGL of 5.2%, 28.9%, and 30.9%, respectively. Our natural gas sales benefited from increased production and higher demand due to a longer and colder winter in the northeastern United States.  In addition, natural gas sales increased due to sales from our Collins, Ormet, and WVDNR wells in 2014, which were not on production until April and May of 2013. Of the total increase in oil and natural gas sales for the 2014 period, $20.6 million, was attributable to increases in prices received and $43.5 million was attributable our increase in production.  The prices we receive for our products are generally tied to commodity index prices. 

Natural gas transportation, gathering, processing and marketing revenues.  Revenue from midstream operations, (which consist of Eureka Hunter Pipeline, TransTex Hunter, and Magnum Hunter Marketing operations) increased by $50.1 million, or 167.9%, for the six months ended June 30, 2014 to $80.0 million from $29.9 million for the six months ended June 30, 2013.  TransTex Hunter revenues decreased by $1.6 million primarily as the result of inventory sales during the first quarter of 2013. Eureka Hunter Pipeline revenues increased by $6.3 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 181.0% or 22.0 million MMBtu to 34.1 MMBtu for the six months ended June 30, 2014 from 12.1 million MMBtu for the six months ended June 30, 2013. Magnum Hunter Marketing revenues increased by $45.4 million to $65.6 million during the six months ended June 30, 2014 from $20.2 million during the six months ended June 30, 2013. Magnum Hunter Marketing revenues increased as a result of new customers, growth from existing customers, and increased gas and NGL revenues from the Markwest processing plant.

Oilfield services revenue.  Drilling services revenue increased by $4.3 million, or 58.5%, for the six months ended June 30, 2014 to $11.6 million from $7.3 million for the six months ended June 30, 2013. This increase was primarily attributable to a combination of additional rigs in service and higher utilization of the existing fleet. During the six months ended June 30, 2014, our drilling rig revenue days increased from 378 to 818 as compared to the six months ended June 30, 2013, primarily as a result of the addition of 2 rigs to our fleet and full utilization of 2 existing rigs. For the six months ended June 30, 2014, the total effective equipment performance of our drilling rigs was 93%, and our rigs were 100% utilized.

Loss on sale of assets.  We recorded a net loss on sale of assets in operating expenses of $2.8 million for the six months ended June 30, 2014, which included a loss of $4.3 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 LOE increased $11.9 million, or 52.1% for the six months ended June 30, 2014, to $34.8 million ($12.51 Boe) from $22.9 million ($14.05 Boe) for the six months ended June 30, 2013.  The increase in LOE was comprised of $16.2 million attributable to increased production volumes and $4.3 million attributable to lower LOE/Boe costs. Of the decrease in LOE/Boe costs, $4.8 million was due to lower recurring costs primarily in the Williston Basin and $2.1 million was due to lower non-recurring work-over expenses in the Williston Basin, partially offset by a $2.6 million increase in third party transportation charges in the Appalachian Basin for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013.

Severance taxes.  Our severance taxes increased$5.4 million, or 78.2%, for the six months ended June 30, 2014, to $12.2 million from $6.8 million for the six months ended June 30, 2013.  The increase in severance taxes was attributable primarily to the increase in our production and sales.  

Exploration.  We record exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. We recorded $23.2 million of exploration expense for the six months ended June 30, 2014, compared to $33.3 million for the six months ended June 30, 2013.  During the 2014 period, the Company's exploration expense was primarily attributable to $19.9 million of leasehold impairments relating to leases in the Williston Basin region that expired undrilled during the six months ended June 30, 2014 or are expected to retire and 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 six months ended June 30, 2013 of $33.3 million primarily related to leases in the Williston Basin.

Impairment of proved oil and natural gas properties.  Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis bi-annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and

59

natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows.

During the six months ended June 30, 2014, changes in production estimates and lease operating costs provided indications of possible impairment on two legacy fields that are unrelated to our current drilling and development plan. As a result of our assessment, we recorded impairment of proved oil and natural gas properties in continuing operations of $0.2 million for the six months ended June 30, 2014 to reduce the carrying value of these properties to their estimated fair values. During the six months ended June 30, 2013, we recorded impairments on our proved oil and natural gas properties in the Williston and Appalachian Basins of $10.0 million. We calculated the estimated fair values using a discounted cash flow model. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Natural gas transportation, gathering, processing and marketing expenses. Expenses from the midstream operations increased by $47.9 million, or 178.5% for the six months ended June 30, 2014, to $74.8 million from $26.8 million for the six months ended June 30, 2013 due to increased cost of gas marketed by Magnum Hunter Marketing along with Magnum Hunter Marketing's increased activities.

Oilfield services expenses.  Oilfield services expenses increased by $0.6 million, or 8.6%, for the six months ended June 30, 2014 to $8.0 million from $7.4 million for the six months ended June 30, 2013, due to the addition of 2 rigs to our fleet and full utilization of 2 existing rigs. 

Depletion, depreciation, amortization, and accretion.  Our DD&A increased $21.7 million, or 49.7%, to $65.4 million for the six months ended June 30, 2014, from $43.7 million for the six months ended June 30, 2013, due to increases in accumulated costs from our capital expenditure and acquisition programs during 2013 and 2014, and increased production in 2014. Our DD&A/Boe decreased by $3.30, or 12.3%, to $23.50 Boe for the six months ended June 30, 2014, compared to $26.80 Boe for the six months ended June 30, 2013. The decrease in DD&A/Boe was primarily attributable to an increase in natural gas production from continuing operations. Natural gas wells generally have a lower rate on a Boe basis than oil and NGL. The Company's natural gas production increased significantly due to its drilling in the Appalachian Basin.

General and administrative.  Our G&A decreased$2.3 million, or 6.4%, to $34.0 million ($12.23 Boe) for the six months ended June 30, 2014, from $36.3 million ($22.31 Boe) for the six months ended June 30, 2013.  G&A expenses decreased overall during 2014 mainly due to lower stock compensation expense. Non-cash stock compensation expense decreased by $5.3 million, to approximately $3.4 million ($1.21 Boe) for the six months ended June 30, 2014, from $8.7 million ($5.34 Boe) for the six months ended June 30, 2013 as a result of a grant during the first quarter of 2013 of which 25% vested immediately.

Interest expense, net.  Our interest expense, net of interest income, increased by 18.3%, to $44.2 million for the six months ended June 30, 2014, from $37.4 million for the six months ended June 30, 2013.  Our higher average debt level in the six months ended June 30, 2014 compared to the same period in 2013 accounted for $1.7 million of the increase, and higher amortization and write-off of deferred financing costs accounted for $5.1 million of the increase. We also incurred a $2.2 million prepayment penalty through the early termination of credit agreements of Eureka Hunter Pipeline. Interest expense was offset by capitalized interest of $0.8 million and $1.4 million during the six months ended June 30, 2014 and 2013, respectively. We capitalize interest on projects lasting six months or longer.

Commodity and financial derivative activities.  Our commodity and financial derivative activity resulted in net losses of $42.5 million and $1.1 million for the six month periods ended June 30, 2014 and 2013, respectively. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:

60

	Six Months Ended   June 30,
	2014			2013
	(in thousands)
Commodity derivatives
Realized gain (loss) on settled transactions	$	(4,551	)	$	(305	)
Unrealized gain (loss) on open contracts	(4,282		)	4,865
Total commodity derivatives	(8,833		)	4,560
Financial derivatives
Unrealized gain (loss) on open contracts	(33,656		)	(5,651		)
Net gain (loss)	$	(42,489	)	$	(1,091	)

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

At June 30, 2014, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Eureka Hunter Holdings Series A Preferred Units. This embedded derivative instrument resulted in unrealized losses of $33.9 million and $5.4 million in the six months ended June 30, 2014 and 2013, respectively. The change in unrealized loss was driven primarily by increases in total enterprise value and a reduction in the expected term of the conversion feature.

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

Also at June 30, 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. This embedded derivative instrument resulted in an unrealized gain of $238,000 in the six months ended June 30, 2014 and an unrealized loss of $211,000 in the six months ended June 30, 2013. Both derivative instruments originated in 2012 and the derivative instruments have resulted in no cash outlays as of June 30, 2014.

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

Income tax benefit.  We were in a net operating loss position as of June 30, 2014, and have a full valuation allowance on all deferred tax assets. As a result, we did not recognize a tax befit on our June 30, 2014 net loss, whereas we recognized a benefit of $44.2 million for the six months ended June 30, 2013.

Net income attributable to non-controlling interest.  Net income attributable to non-controlling interest was $0.9 million for the six months ended June 30, 2014 and 2013.  This represented 12.5% of the gain or loss incurred by our majority-owned subsidiary, PRC Williston, and 1.7% of the gain or loss incurred by our majority-owned subsidiary, Eureka Hunter Holdings. 

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 to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented.

Income from discontinued operations was $7.3 million and $9.1 million for the six months ended June 30, 2014 and 2013, respectively. The following table summarizes the income from discontinued operations for the periods indicated:

61

	Six months ended June 30,
	2014		2013
	(in thousands)
Eagle Ford Hunter	$	—	$	16,691
Hunter Disposal	—		—
Magnum Hunter Production	2,690		(4,040		)
Williston Hunter Canada	4,561		(3,572		)
	$	7,251	$	9,079

Gain (loss) on disposal of discontinued operations, net of tax. The Company recognized a loss on disposal of discontinued operations of $32.4 million for the six months ended June 30, 2014 and a gain on disposal of discontinued operations of $172.5 million for the six months ended June 30, 2013. The following table summarizes the gain (loss) on disposal of discontinued operations for the periods indicated:

	Six months ended June 30,
	2014			2013
	(in thousands)
Eagle Ford Hunter	$	(7,024	)	$	172,452
Hunter Disposal	—			—
Magnum Hunter Production	(18,649		)	—
Williston Hunter Canada	(6,701		)	—
	$	(32,374	)	$	172,452

During the three-months ended September 30, 2013, we estimated that the final working capital adjustment on the sale of Eagle Ford Hunter would be approximately $32.9 million. We accrued a liability of $32.9 million and recorded a corresponding downward adjustment to the $172.5 million preliminary gain recognized as of June 30, 2013. As of June 30, 2014, we estimated that the final working capital adjustment related to the Eagle Ford Hunter sale would be a reduction to the preliminary gain recognized of $33.7 million, plus accrued interest of $1.3 million.  The Company has recorded a liability for its revised estimate of the final adjustment.

Dividends on preferred stock.  Total dividends on our preferred stock were approximately $30.2 million for the six months ended June 30, 2014, and $27.6 million for the six months ended June 30, 2013. 

The Series C Preferred Stock had a stated value of $100.0 million at both June 30, 2014 and December 31, 2013, and carries a cumulative dividend rate of 10.25% per annum.  The Series D Preferred Stock had a stated value of $221.2 million and $221.2 million at June 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million and $95.1 million at June 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum. The Series A Preferred Units of Eureka Hunter Holdings had a liquidation preference of $214.8 million and $200.6 million at June 30, 2014 and December 31, 2013, respectively, and carries a cumulative dividend rate of 8.0% per annum.

Liquidity and Capital Resources

Overview

We generally rely on cash generated from operations, borrowings under our 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.

62

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

Our cash flow from operations is driven by commodity prices and production volumes and the effect of commodity derivatives. Prices for oil and natural gas are primarily affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. 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.  On May 6, 2014, we entered into the First Amendment to the Third Amended and Restated Credit Agreement which increased our borrowing base under the MHR Senior Revolving Credit Facility from $232.5 million to $325.0 million. As called for under the terms of the First Amendment to the Third Amended and Restated Credit Agreement, the borrowing base was reduced by $25.0 million upon the issuance of common equity in a private placement and was reduced by $27.5 million upon the sale of Williston Hunter Canada, Inc. ("WHI Canada"), a wholly-owned subsidiary. 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. The Company had $164.5 million of outstanding debt under our MHR Senior Revolving Credit Facility at June 30, 2014, with available borrowing capacity at that date of $106.5 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 June 30, 2014, liquidity for the Company, excluding Eureka Hunter Holdings and its subsidiaries, was $114.0 million, comprised of $106.5 million of available borrowing capacity under the MHR Senior Revolving Credit Facility and $7.5 million in available cash.

While we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities, available borrowing capacity under the MHR Senior Revolving Credit Facility, anticipated proceeds from our planned sales of non-core assets and proceeds from capital market transactions, to the extent that we access such capital markets at opportune times, will be adequate to execute our corporate strategies and to meet debt service obligations, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. Significant reductions in our borrowing capacity as a result of a redetermination of our borrowing base could have an adverse impact on our capital resources and liquidity.  In addition, the ability of the Company to continue to execute on 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 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", on July 25, 2014, the Company received the ruling of the arbitrator related to the working capital adjustment on the sale of our Eagle Ford Hunter assets to Penn Virginia, resulting in an amount due Penn Virginia of $33.7 million, plus accrued interest of $1.3 million. We have reflected this amount as a current liability in our consolidated balance sheet as of June 30, 2014. This liability was settled in cash on July 31, 2014.

63

Liquidity Position

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

	As of June 30, 2014						As of December 31, 2013
	(in thousands)
	Magnum Hunter			Eureka Hunter			Magnum Hunter			Eureka Hunter
Borrowing base under MHR senior revolving credit facility	$	272,500		$	—		$	242,500		$	—
Eureka Hunter Pipeline second lien term loan	—			—			—			50,000
Eureka Hunter Pipeline Credit Agreement	—			72,200			—			—
Cash and cash equivalents	7,477			1,643			33,669			8,044
Borrowings under MHR Senior Revolving Credit Facility	(164,500		)	—			(218,000		)	—
Letters of credit issued	(1,525		)	—			(7,225		)	—
Borrowings under Eureka Hunter Pipeline second lien term loan	—			—			—			(50,000		)
Borrowings under Eureka Hunter Pipeline Credit Agreement	—			(65,000		)	—			—
Liquidity	$	113,952		$	8,843		$	50,944		$	8,044

The Company had $164.5 million outstanding under the MHR Senior Revolving Credit Facility and $1.5 million in issued letters of credit at June 30, 2014, with available borrowing capacity at that date of $106.5 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 June 30, 2014, liquidity for Eureka Hunter Pipeline was $8.8 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 June 30, 2014, Eureka Hunter Pipeline could borrow up to $72.2 million and still maintain compliance with financial ratios. Additionally, at that date, all capital funding commitments from the Company and ArcLight, Eureka Hunter Holdings' minority interest holder, had been fulfilled.

As of June 30, 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 six months of 2014, and through August 8, 2014, we closed on sales of non-core assets and raised cash through private offerings of common stock for aggregate proceeds of approximately $281.0 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 $178.6 million from the private placements of 25,728,580 shares of our common stock at a price of $7.00 per share;

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

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

On July 24, 2014, the Company closed on the Ormet asset acquisition with $22.7 million drawn from cash on hand and borrowing capacity under the MHR Senior Revolving Credit Facility.

Upon closing of the sale of WHI Canada, our borrowing base under the MHR Senior Revolving Credit Facility decreased by $27.5 million. Additionally, until certain Canadian tax filing and related approval requirements were fulfilled, 25% of the CAD $75.0 million purchase price was restricted and held in escrow at June 30, 2014, pending release by the Canadian Revenue Authority. This cash was received by the Company subsequent to June 30, 2014.

64

The closing of the sale of the Company’s remaining Canadian properties represents a further step that we have taken in our strategy to identify and monetize 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 market our interests in MHP and expect that a purchase and sales agreement will be executed by the end of 2014.

Sources of Cash

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

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

	Six Months Ended June 30,
	2014			2013
	(In thousands)
Cash flows provided by operating activities	$	18,747		$	73,868
Cash flows provided by (used in) investing activities	(185,372		)	104,198
Cash flows provided by (used in) financing activities	133,991			(202,590		)
Effect of foreign currency exchange rates	41			(357		)
Net decrease in cash and cash equivalents	$	(32,593	)	$	(24,881	)

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 $18.7 million for the six months ended June 30, 2014, compared to $73.9 million for the six months ended June 30, 2013, a decrease of $55.1 million or 74.6%.  Although we had significantly increased oil and natural gas sales from the recent success in our drilling programs in the Marcellus Shale and Utica Shale, higher receivables resulted in decreased cash available. Cash used in paying down working capital increased compared to the same period in 2013. Cash provided by operating activities for the six months ended June 30, 2014 includes cash flows used by discontinued operations of $8.5 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 six months ended June 30, 2014, was $185.4 million, principally from drilling activities, and partially offset by the cash proceeds from the sale of assets of $74.5 million. 

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

Our cash provided by investing activities for the six months ended June 30, 2013 was $104.2 million, principally from the cash proceeds from the sale of Eagle Ford Hunter of $379.8 million, partially offset by capital expenditures of $277.5 million.

65

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 six months ended June 30, 2014 was $134.0 million mainly from proceeds from the issuance of shares of common stock. We raised $178.6 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through private offerings of 25,728,580 shares of our common stock. See "Note 12 - Shareholders' Equity" for additional information. Our majority owned subsidiary, Eureka Hunter Pipeline, paid in full and terminated its term loan with Pennant Park and borrowed $65.0 million from the new Eureka Hunter Pipeline Credit Agreement executed in March 2014 (see "Note 10 - Debt"). These increases were partially offset by debt pay-down under the MHR Senior Revolving Credit Facility and other debt agreements of approximately $100.6 million. In addition, we paid preferred dividends of $23.6 million and paid deferred finance costs on loans of $6.0 million during the six months ended June 30, 2014.

Our cash used in financing activities for the six months ended June 30, 2013 were $202.6 million, mainly from debt pay-down under the MHR Senior Revolving Credit Facility and other debt agreements of $327.1 million, partially offset by borrowings of $106.0 million. The Company also raised $10.2 million in proceeds from the issuance of shares of our 8.0% Series D Cumulative Perpetual Preferred Stock for cumulative net proceeds of approximately $9.6 million, and issued shares of our 8% Series E Cumulative Convertible Preferred Stock for cumulative net proceeds to the Company of $590,000. In the 2013 period, we paid preferred dividends of $10.4 million and incurred $701,000 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, for the past 12 months we were limited in our ability to access the public markets to raise debt or equity capital. We have now timely filed all our required SEC reports for a period of twelve months, and we are now eligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. We are now able to use a shelf registration statement on Form S-3 to conduct ATM offerings of our equity securities, which ATM offerings we had conducted on a regular basis with respect to our preferred stock prior to our delinquent SEC filings. On August 5, 2014, we filed a universal shelf Form S-3 Registration Statement to register the sale of an unlimited amount of equity and debt securities, and such registration statement became effective automatically upon filing.

We believe the combination of (i) cash on hand, (ii) cash flow generated from the expected success of prior capital development projects, (iii) capital market related funding, (iv) borrowing capacity available under our credit facilities, and (v) 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.

66

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, borrowings under our MHR Senior Revolving Credit Facility and, when market conditions are favorable, proceeds from the sale of securities in the capital markets.   

	Capital Expenditures Incurred (2)		Capital Expenditure Budget
	Six Months Ended June 30, 2014		For the Year ending December 31, 2014
	(In thousands)
Upstream Operations
Appalachian Basin drilling	$	80,138	$	260,000
Williston Basin drilling	44,807		50,000
Midstream and Marketing Operations
Eureka Hunter Holdings, gross of contributed expenditures (1)	82,627		150,000
Total capital expenditures	$	207,572	$	460,000

________________________________

(1) The Company's share of the Midstream and Marketing capital budget is $90.0 million, net of contributed expenditures. The expenditures are expected to be financed through equity and debt facilities that are non-recourse to the Company, and Company, and, possibly, Ridgeline, capital contributions.

(2) Capital expenditures of $6.7 million incurred in other regions, leasehold acquisitions of approximately $70.3 million, and expenditures on other property, plant, and equipment of approximately $17.9 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.

Amendment to Credit Facility

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

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

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

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

67

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

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

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

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

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

Related Party Transactions

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

		Three Months Ended   June 30,					Six Months Ended   June 30,
		2014		2013			2014		2013
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	613	$	590		$	935	$	1,446
	Equipment rental (1)	19		98			141		73
	Office space rental	13		—			36		—
	Gas gathering-trucking (1)	400		—			400		—
	MAG tank panels (1)	800		—			800		—
	Interest income from note receivable (2)	38		53			83		108
	Dividends received from Series C shares	55		37			110		92
	Unrealized gain/(loss) on investments (2)	396		(151		)	161		(677		)
Pilatus Hunter, LLC
	Airplane rental expenses (3)	88		20			158		67

__________________________________

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

(2) On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water.  The Company recognized an embedded derivative asset resulting from the conversion option under the convertible promissory note it received as partial consideration for the sale. The fair market value of the derivative was $317,000, and $79,000 at June 30, 2014 and December 31, 2013, respectively.  See "Note 8 - Fair Value of Financial Instruments" for additional information. The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long-term assets and an available for sale investment in GreenHunter included in investments. 

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

68

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

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

Contractual Obligations

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

Contractual Obligations	Total		2014		2015 -2016		2017 - 2018		After 2018
Long-term debt (1)	$	853,896	$	3,142	$	183,036	$	67,718	$	600,000
Interest on long-term debt (2)	371,247		67,962		128,015		119,045		56,225
Gas transportation and compression contracts	29,238		2,706		9,851		5,959		10,722
Asset retirement obligations (3)	16,639		71		260		5,796		10,512
Commodity derivative liabilities (4)	6,006		5,709		297		—		—
Operating lease obligations	1,256		259		696		248		53
Drilling rig installments	6,500		1,300		5,200		—		—
Total	$	1,284,782	$	81,149	$	327,355	$	198,766	$	677,512

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 June 30, 2014 on the debt facilities in place as of June 30, 2014. This results in a weighted average interest rate of 7.96%.

(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 June 30, 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" to the consolidated financial statements included in Part I, Item 1 (Financial Statements (unaudited)) of this Quarterly Report on Form 10-Q.

69

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

Commodity Price Risk

The Company's most significant market risk relates to prices for natural gas, crude oil, and NGLs. 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 June 30, 2014, the Company had derivative instruments in place to reduce the price risk associated with future production of 15.8 Bcf of natural gas and 1.0 MMBbls of crude oil, representing a gross asset of $0.8 million and a gross liability of $6.8 million; or a net liability of $6.0 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 June 30, 2014:

	As of June 30, 2014
	Fair Value As Reported			Fair Value: 10% Price Increase			Fair Value: 10 % Price Decrease
	(in thousands)
Gas	$	(1,379	)	$	(6,924	)	$	4,288
Crude oil	(4,627		)	(13,452		)	43
Total Fair Value	$	(6,006	)	$	(20,376	)	$	4,332
Change in Fair Value				$	(14,370	)	$	10,338

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

70

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

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Collars (1)	July 2014- Dec 2014	15,000	$4.27 - $5.23
Swaps	July 2014 - Dec 2014	31,000	$4.23
	Jan 2015 - Dec 2015	20,000	$4.18
Ceilings purchased (call)	July 2014 - Dec 2014	16,000	$5.91
Ceilings sold (call)	July 2014 - Dec 2014	16,000	$5.91
			Weighted Average
Crude Oil	Period	Bbls/day	Price per Bbl
Collars (1)	July 2014 - Dec 2014	663	$85.00 - $91.25
	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Traditional three-way collars (2)	July 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)	July 2014 - Dec 2014	663	$65.00
	Jan 2015 - Dec 2015	259	$70.00

______________________________

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

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

At June 30, 2014, the fair value of our open commodity derivative contracts was a liability of $6.0 million.

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

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2014			2013			2014			2013
	(in thousands)
Gain (loss) on settled transactions	$	(2,267	)	$	(1,261	)	$	(4,551	)	$	(305	)
Gain (loss) on open transactions	(1,021		)	12,997			(4,282		)	4,865
Total gain (loss)	$	(3,288	)	$	11,736		$	(8,833	)	$	4,560

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 $256,000 and $445,000 for the three and six month periods ended June 30, 2014, respectively.

71

Financial Instrument Price Risk

We have investments in both publicly-traded and non-publicly-traded financial instruments. Our ability to divest of these instruments is a function of overall market liquidity which is impacted by, among other things, the amount of outstanding securities of a particular issuer, trading history of the issuer, overall market conditions, and entity-specific facts and circumstances that impact a particular issuer. As a result, market volatility and overall financial performance and liquidity of the issuer could result in significant fluctuations in the fair value of these instruments, and we may be unable to recover the full cost of these investments. A 10% increase or decrease in market prices for our marketable securities would increase or decrease fair value by $1.1 million.

Eureka Hunter Holdings, a majority owned subsidiary, has issued Eureka Hunter Holdings Series A Preferred Units which have embedded conversion and redemption options to the holder. As a result of these embedded features we recognize, as a liability, the fair value of the conversion and redemption options as a derivative liability in our consolidated financial statements. The fair value of these derivative instruments are impacted primarily by the total enterprise value of Eureka Hunter Holdings and the implied volatility of the instruments. As of June 30, 2014, the fair value of the liability associated with these embedded features was $115.3 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 June 30, 2014:

	As of June 30, 2014
	Fair Value: Increase of 5%		Fair Value: Decrease of 5%
	(in thousands)
Total enterprise value	$	116,860	$	113,213
Volatility	$	115,964	$	114,548

72

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 June 30, 2014. The Company's disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

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

Management's Report on Internal Control over Financial Reporting

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

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

Our management conducts regular periodic evaluations of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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 June 30, 2014, management continues to implement and execute upon its remediation plan with respect to the material weaknesses identified in our Annual Report on Form 10-K for the year ended December 31, 2013, as amended.

Management’s Plan for Remediation of Material Weaknesses

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

Preparation and Review of Account Reconciliations

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

Leasehold Property Costs

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

73

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

Tax

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

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

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

Changes in Internal Control over Financial Reporting

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

PART II.  OTHER INFORMATION

Item 1.        Legal Proceedings.

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

Item 1A. Risk Factors.

If we are successful in our takeover bid for Ambassador, we will be expanding our active operations into Australia, which will subject us to additional regulations and risks from foreign operations, including currency fluctuations, which could impact our financial position and results of operations.

Although we have an investment in NSE, which is an Australian company, we currently do not have any active operations in Australia. If we are successful in our takeover bid for Ambassador, we will be expanding our active operations into Australia, which will expose us to a new regulatory environment and risks from foreign operations. Some of these additional risks include, but are not limited to:

• increases in governmental royalties;

• application of new tax laws (including host-country export, excise and income taxes and U.S. taxes on foreign operations);

• currency restrictions and exchange rate fluctuations;

• legal and governmental regulatory requirements;

• difficulties and costs of staffing and managing international operations;

• funding international operations; and

• cultural differences.

Our Australian operations also may be adversely affected by the laws and policies of the U.S. affecting foreign trade, taxation and investment. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States.

74

If we acquire Ambassador, our failure to successfully integrate Ambassador’s business could negatively impact our future business and financial results.

If successful, our acquisition of Ambassador will represent an expansion of our operations into a new geographic core area in an international market, with operating conditions and a regulatory environment that may not be as familiar to us as our existing core operating areas. Our success in operating an Australian company will depend, in part, on our ability to realize benefits from integrating Ambassador’s business with our existing businesses. The integration process may be complex, costly and time-consuming. To realize such benefits, we must successfully combine the businesses in an efficient and effective manner. If we are not able to achieve these objectives within the anticipated time frame, or at all, any benefits and cost savings related to our acquisition of Ambassador may not be realized fully, or at all, or may take longer to realize than expected.

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.

75

SIGNATURES

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

	MAGNUM HUNTER RESOURCES CORPORATION
Date: August 8, 2014		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman and Chief Executive Officer
Date: August 8, 2014		/s/ Joseph C. Daches
		Joseph C. Daches,
		Senior Vice President and Chief
		Financial Officer

76

INDEX TO EXHIBITS

Exhibit Number	Description
2.1	Share Purchase Agreement, dated April 21, 2014, between Magnum Hunter Resources Corporation and Steppe Resources Inc. (incorporated by reference from the Registrant's quarterly report on Form 10-Q filed on May 9, 2014).+
10.1	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 (incorporated by reference from the Registrant's quarterly report on Form 10-Q for the quarter ended March 31, 2014 filed on May 9, 2014).
10.2	Eureka Hunter Holdings, LLC Management Incentive Compensation Plan (incorporated by reference from the Registrant's current report on Form 8-K filed on May 16, 2014).*
10.3	Form of Eureka Hunter Holdings, LLC Equity Incentive Plan Award Letter (incorporated by reference from the Registrant's current report on Form 8-K filed on May 16, 2014).*
10.4	Form of Eureka Hunter Holdings, LLC Class B Common Unit Agreement (incorporated by reference from the Registrant's current report on Form 8-K filed on May 16, 2014).*
10.5	Securities Purchase Agreement, dated as of May 27, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on May 30, 2014).
10.6	Registration Rights Agreement, dated as of May 27, 2014, by and among the Registrant and investors party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on May 30, 2014).
10.7	Form of Warrant to Purchase Shares of Common Stock of the Registrant (incorporated by reference from the Registrant's current report on Form 8-K filed on May 30, 2014).
10.8	Limited Consent Agreement, dated June 9, 2014, among the Registrant and Bank of Montreal, as Administrative Agent, and the lenders party thereto (incorporated by reference from the Registrant's current report on Form 8-K filed on June 10, 2014).
12.1	Computation of Ratio of Earnings to Fixed Charges.#
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.#
32	Certification of the Chief Executive Officer and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.@
101.INS	XBRL Instance Document.^
101.SCH	XBRL Taxonomy Extension Schema Document.^
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.^
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.^
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.^
101.DEF	XBRL Taxonomy Extension Definition Presentation Linkbase Document.^
*	The referenced exhibit is a management contract, compensatory plan or arrangement.
+	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.

77

^

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.

78