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, 2015

-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.)

909 Lake Carolyn Parkway, Suite 600, Irving, Texas 75039

(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 6, 2015, there were 220,773,920 shares of the registrant's common stock ($0.01 par value) outstanding.

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED JUNE 30, 2015

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited):
Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014	3
Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2015 and 2014	4
Consolidated Statement of Shareholders' Equity for the Six Months Ended June 30, 2015	5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014	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	68
Item 4. Controls and Procedures	70
Part II. OTHER INFORMATION	70
Item 1. Legal Proceedings	70
Item 1A. Risk Factors	70
Item 3. Defaults Upon Senior Securities	70
Item 5. Other Information	71
Item 6. Exhibits	71
SIGNATURES	72

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

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

(unaudited)

	June 30, 2015		December 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	8,818	$	53,180
Accounts receivable:
Oil and natural gas sales	14,561		21,514
Joint interests and other, net of allowance for doubtful accounts of $508 at June 30, 2015 and $308 at December 31, 2014	10,914		23,888
Derivative assets	27		16,586
Inventory	2,491		2,268
Investments	2,447		3,864
Prepaid expenses and other assets	2,106		4,091
Total current assets	41,364		125,391
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting, net	1,049,370		1,098,235
Gas transportation, gathering and processing equipment and other, net	76,031		77,423
Total property, plant and equipment, net	1,125,401		1,175,658
OTHER ASSETS
Deferred financing costs, net of amortization of $16,747 at June 30, 2015 and $15,099 at December 31, 2014	21,252		22,856
Other assets	929		3,928
Assets of discontinued operations	345,318		347,191
Total assets	$	1,534,264	$	1,675,024

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, 2015			December 31, 2014
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	9,854		$	10,770
Accounts payable	95,090			135,697
Accounts payable to related parties	6,154			90
Accrued liabilities	21,588			20,277
Revenue payable	7,428			5,450
Derivative liabilities	490			—
Other liabilities	2,340			1,356
Total current liabilities	142,944			173,640
Long-term debt, net of current portion	938,685			937,963
Asset retirement obligations, net of current portion	25,944			26,229
Other long-term liabilities	5,465			5,337
Total liabilities	1,113,038			1,143,169
COMMITMENTS AND CONTINGENCIES (Note 14)
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, 2015 and December 31, 2014, with a liquidation preference of $25.00 per share	100,000			100,000
SHAREHOLDERS' EQUITY
Preferred stock, 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, 2015 and December 31, 2014, 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, 2015 and December 31, 2014, 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 213,963,234 and 201,420,701 issued, and 213,048,282 and 200,505,749 outstanding as of June 30, 2015 and December 31, 2014, respectively	2,140			2,014
Additional paid in capital	936,323			909,783
Accumulated deficit	(929,836		)	(784,546		)
Accumulated other comprehensive income (loss)	230			(7,765		)
Treasury stock, at cost:
Series E Preferred Stock, 81 shares as of June 30, 2015 and December 31, 2014	(2,030		)	(2,030		)
Common stock, 914,952 shares as of June 30, 2015 and December 31, 2014	(1,914		)	(1,914		)
Total shareholders' equity	321,226			431,855
Total liabilities and shareholders' equity	$	1,534,264		$	1,675,024

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,
	2015			2014			2015			2014
REVENUES AND OTHER
Oil and natural gas sales	$	33,418		$	83,772		$	82,809		$	159,737
Midstream natural gas gathering, processing, and marketing	472			39,646			930			65,757
Oilfield services	5,393			5,954			10,258			11,575
Other revenue	243			276			925			449
Total revenue	39,526			129,648			94,922			237,518
OPERATING EXPENSES
Production costs	9,351			10,186			23,156			23,242
Severance taxes and marketing	1,759			5,729			4,582			10,704
Transportation, processing, and other related costs	10,625			6,835			30,962			18,868
Exploration	1,479			9,186			9,969			25,110
Impairment of proved oil and gas properties	95			158			13,949			16,912
Midstream natural gas gathering, processing, and marketing	184			38,536			678			65,432
Oilfield services	4,678			4,089			8,889			8,036
Depletion, depreciation, amortization and accretion	22,313			32,026			80,063			57,756
Loss (gain) on sale of assets, net	(26,744		)	(687		)	(28,396		)	3,388
General and administrative	11,257			18,776			24,029			32,770
Total operating expenses	34,997			124,834			167,881			262,218
OPERATING INCOME (LOSS)	4,529			4,814			(72,959		)	(24,700		)
OTHER INCOME (EXPENSE)
Interest income	49			41			98			86
Interest expense	(24,102		)	(19,876		)	(47,567		)	(37,891		)
Gain (loss) on derivative contracts, net	(325		)	(3,006		)	2,777			(8,595		)
Loss from equity method investments	(87		)	(135		)	(318		)	(357		)
Other income (expense)	(146		)	471			(7,753		)	427
Total other expense, net	(24,611		)	(22,505		)	(52,763		)	(46,330		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(20,082		)	(17,691		)	(125,722		)	(71,030		)
Income tax	—			—			—			—
LOSS FROM CONTINUING OPERATIONS, NET OF TAX	(20,082		)	(17,691		)	(125,722		)	(71,030		)
Gain on dilution of interest in Eureka Hunter Holdings, LLC, net of tax	—			—			2,390			—
Loss from discontinued operations, net of tax	(1,594		)	(42,524		)	(4,263		)	(42,373		)
Loss on disposal of discontinued operations, net of tax	—			(5,212		)	—			(13,725		)
NET LOSS	(21,676		)	(65,427		)	(127,595		)	(127,128		)
Net loss attributed to non-controlling interests	—			780			—			889
LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	(21,676		)	(64,647		)	(127,595		)	(126,239		)
Dividends on preferred stock	(8,847		)	(8,848		)	(17,695		)	(17,668		)
Dividends on preferred stock of discontinued operations	—			(6,482		)	—			(12,558		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(30,523	)	$	(79,977	)	$	(145,290	)	$	(156,465	)
Weighted average number of common shares outstanding, basic and diluted	208,077,253			184,479,312			204,517,663			178,346,940
Loss from continuing operations per share, basic and diluted	$	(0.14	)	$	(0.14	)	$	(0.70	)	$	(0.49	)
Loss from discontinued operations per share, basic and diluted	(0.01		)	(0.29		)	(0.01		)	(0.39		)
NET LOSS PER COMMON SHARE, BASIC AND DILUTED	$	(0.15	)	$	(0.43	)	$	(0.71	)	$	(0.88	)
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
Loss from continuing operations, net of tax	$	(20,082	)	$	(16,911	)	$	(125,722	)	$	(70,141	)
Loss from discontinued operations, net of tax	(1,594		)	(47,736		)	(1,873		)	(56,098		)
Net loss	$	(21,676	)	$	(64,647	)	$	(127,595	)	$	(126,239	)

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,
	2015			2014			2015			2014
NET LOSS	$	(21,676	)	$	(65,427	)	$	(127,595	)	$	(127,128	)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation gain (loss)	(13		)	1,130			102			(1,218		)
Unrealized gain (loss) on available for sale securities	309			(549		)	(1,099		)	(605		)
Amounts reclassified for other than temporary impairment of available for sale securities	—			—			8,992			—
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	—			20,741			—			20,741
Total other comprehensive income	296			21,322			7,995			18,918
COMPREHENSIVE LOSS	(21,380		)	(44,105		)	(119,600		)	(108,210		)
Comprehensive loss attributable to non-controlling interests	—			780			—			889
COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	$	(21,380	)	$	(43,325	)	$	(119,600	)	$	(107,321	)

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			Total Shareholders' Equity
BALANCE, January 1, 2015	4,425	4	201,421	$	221,244	$	95,069	$	2,014	$	909,783		$	(784,546	)	$	(7,765	)	$	(3,944	)	$	431,855
Share-based compensation	—	—	1,101	—		—		12		5,135			—			—			—			5,147
Shares withheld for taxes	—	—	—	—		—		—		(310		)	—			—			—			(310		)
Sale of common stock	—	—	11,441	—		—		114		21,715			—			—			—			21,829
Dividends on preferred stock	—	—	—	—		—		—		—			(17,695		)	—			—			(17,695		)
Net loss	—	—	—	—		—		—		—			(127,595		)	—			—			(127,595		)
Foreign currency translation	—	—	—	—		—		—		—			—			102			—			102
Unrealized loss on available for sale securities, net	—	—	—	—		—		—		—			—			(1,099		)	—			(1,099		)
Amounts reclassified from accumulated other comprehensive income for other than temporary impairment of available for sale securities	—	—	—	—		—		—		—			—			8,992			—			8,992
BALANCE, June 30, 2015	4,425	4	213,963	$	221,244	$	95,069	$	2,140	$	936,323		$	(929,836	)	$	230		$	(3,944	)	$	321,226

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,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(127,595	)	$	(127,128	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	80,063			65,361
Exploration	8,769			22,489
Impairment of proved oil and gas properties	13,949			158
Impairment of other operating assets	—			616
Share-based compensation	4,837			3,375
Cash paid for plugging wells	—			(27		)
Loss (gain) on sale of assets	(28,396		)	35,761
Loss (gain) on derivative contracts	(2,777		)	42,489
Cash proceeds (payment) on settlement of derivative contracts	19,826			(4,551		)
Gain on dilution of interest in Eureka Hunter Holdings, LLC	(2,390		)	—
Loss from equity method investments	4,581			403
Other than temporary impairment of investment	8,992			—
Amortization and write-off of deferred financing costs and discount on Senior Notes included in interest expense	2,313			7,740
Changes in operating assets and liabilities:
Accounts receivable, net	18,240			(15,588		)
Inventory	(223		)	3,475
Prepaid expenses and other current assets	2,118			(1,147		)
Accounts payable	45,915			(23,817		)
Revenue payable	2,051			5,204
Accrued liabilities	1,687			3,934
Net cash provided by operating activities	51,960			18,747
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and advances	(136,635		)	(257,469		)
Change in deposits and other long-term assets	2,745			(2,406		)
Proceeds from sales of assets	34,186			74,503
Net cash used in investing activities	(99,704		)	(185,372		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from sales of common shares	21,829			178,575
Proceeds from sale of Eureka Hunter Holdings Series A Preferred Units	—			11,956
Proceeds from exercise of warrants and options	—			8,761
Preferred stock dividends	(17,695		)	(23,646		)
Repayments of debt	(5,860		)	(197,216		)
Proceeds from borrowings on debt	5,000			161,616
Deferred financing costs	(44		)	(6,042		)
Change in other long-term liabilities	128			(13		)
Net cash provided by financing activities	3,358			133,991
Effect of changes in exchange rate on cash	24			41
NET DECREASE IN CASH AND CASH EQUIVALENTS	(44,362		)	(32,593		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	53,180			41,713
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	8,818		$	9,120

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 ("Magnum Hunter" or the "Company"), is an Irving, Texas based independent oil and gas company engaged primarily in the exploration for and the exploitation, acquisition, development and production of natural gas and natural gas liquids resources predominantly in shale plays in the United States, along with certain oil field service activities. In addition, the Company has a substantial equity method investment in midstream operations, which is classified as discontinued operations.

Presentation of Consolidated Financial Statements

The accompanying unaudited interim consolidated financial statements of Magnum Hunter have been prepared in accordance with accounting principles generally accepted in the United States of America ("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 unless otherwise indicated) 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, 2014, as amended.

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

Adoption of New Accounting Policy

In April 2014, the Financial Accounting Standards Board ("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, a group of components of an entity, or a business (including equity method investments) 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, group of components of an entity, or a business 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). 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 adoption of ASU 2014-08 required the Company to reclassify the operations of Eureka Hunter Holdings, LLC ("Eureka Hunter Holdings") to discontinued operations for all periods presented. See "Note 2 - Acquisitions, Divestitures, and Discontinued Operations".

Reclassification of Prior-Period Balances

Certain prior period balances have been reclassified to correspond with current-period presentation. As a result of the Company's adoption of a plan in June 2015 to dispose of its equity investment in Eureka Hunter Holdings, operating losses and expenses related to these operations have been classified as discontinued operations and the equity investment has been reclassified to assets of discontinued operations in our consolidated balance sheets for all periods presented. See "Note 2 - Acquisitions, Divestitures, and Discontinued Operations".

7

As a result of the Company's decision in September 2014 to withdraw its plan to divest MHP and cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented, and all assets and liabilities of MHP that were previously reported as assets and liabilities held for sale in our consolidated balance sheet have been reclassified to assets and liabilities held for use effective September 2014. See "Note 2 - Acquisitions, Divestitures, and Discontinued Operations". 

The Company has separately classified transportation and processing expenses incurred to deliver gas to processing plants and/or to selling points, which were previously included as components of lease operating expenses and severance taxes and marketing, in the accompanying consolidated statements of operations for all periods presented. The Company has also renamed lease operating expenses as "Production costs" and presented transportation and processing expenses as "Transportation, processing, and other related costs" in order to provide more meaningful information on costs associated with production and development.

The Company has reclassified approximately $5.2 million of oil and gas transportation, processing and production taxes payables from accounts receivable - oil and natural gas sales to accounts payable as of December 31, 2014.

Non-Controlling Interest in Consolidated Subsidiaries

Prior to July 24, 2014, the Company owned 87.5% of the equity interests in PRC Williston, LLC ("PRC Williston"), which sold substantially all of its assets on December 30, 2013. On July 24, 2014, the Company executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, the Company owns 100% of the equity interests in PRC Williston and has all rights and claims to its remaining assets and liabilities, which are not significant. The net loss attributable to non-controlling interest for PRC Williston is recorded through July 24, 2014.

Regulated Activities

Sentra Corporation, a wholly-owned subsidiary, owns and operates distribution systems for retail sales of natural gas in south central Kentucky. Sentra Corporation's gas distribution billing rates are regulated by the Kentucky Public Service Commission based on recovery of purchased gas costs. The Company accounts for its operations based on the provisions of the FASB Accounting Standards Codification ("ASC") Subtopic 980-605, Regulated Operations-Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. During the three and six months ended June 30, 2015, the Company had gas transmission, compression and processing revenue, which included gas utility sales from Sentra Corporation's regulated operations aggregating $82,969 and $461,230, respectively. During the three and six months ended June 30, 2014, the Company had revenues of $274,827 and $445,899, respectively, related to Sentra Corporation's regulated operations.

Recently Issued Accounting Standards

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

In 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: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. This amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The guidance allows for either a "full retrospective" adoption or a "modified retrospective" adoption, however early application is not permitted. In July 2015, the FASB voted to approve a one-year deferral of the effective date of ASU 2014-09. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures.

8

In April 2015, the FASB issued ASU 2015-03, Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this update. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. As of June 30, 2015, the Company had $21.3 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction from the related debt liability.

In April 2015, the FASB issued ASU 2015-04, Intangibles - Goodwill and Other - Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Agreement. This update provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. This update does not change GAAP for a customer's accounting for service contracts. This amendment is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted for all entities, either prospectively to all arrangements entered into or materially modified after the effective date, or retrospectively. The Company has several cloud computing arrangements and is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

NOTE 2 - ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS

Acquisitions

Agreement to Purchase Utica Shale Acreage

On August 12, 2013, Triad Hunter, LLC ("Triad Hunter"), a wholly-owned subsidiary of the Company, 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 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. The maximum purchase price, if MNW delivers 32,000 acres with acceptable title, would be $142.1 million, excluding title costs. During the six months ended June 30, 2015 and 2014, Triad Hunter purchased 2,665 and 11,128 net leasehold acres, respectively, from MNW for an aggregate purchase price of $12.0 million and $45.9 million, respectively. As of June 30, 2015, Triad Hunter had purchased a total of 25,044 net leasehold acres from MNW for an aggregate purchase price of $103.9 million.

The Company believes that MNW may not be able to provide Triad Hunter with satisfactory title to all of the remaining net leasehold acres subject to purchase under the asset purchase agreement, and therefore the Company anticipates that most of the remaining net leasehold acres will not be ultimately acquired by Triad Hunter.

Divestitures

Sale of Certain West Virginia Assets

On May 22, 2015, Triad Hunter entered into a Purchase and Sale Agreement with Antero Resources Corporation ("Antero") pursuant to which Triad Hunter agreed to sell to Antero all of Triad Hunter's right, title and interest in certain undeveloped and unproven leasehold acreage located in Tyler County, West Virginia. The sale transaction closed on June 18, 2015 and Triad Hunter received cash consideration of $33.6 million, subject to post-closing adjustments for any title defects and for remediation of asserted title defects. The properties sold consisted of ownership interests in approximately 5,210 net leasehold acres.

Pursuant to the Purchase and Sale Agreement, as amended, Antero had the right, up to the close of business on June 30, 2015, to assert or waive any title defects associated with the leasehold acres sold. Triad Hunter has the right, on or before August 19, 2015, to cure or remove any or all such title defects asserted by Antero, following which cure or removal the affected properties will be conveyed to Antero and Triad Hunter will receive additional consideration therefor. As of August 6, 2015, the Company received an additional $4.0 million of additional consideration for title defects cured or removed subsequent to June 30, 2015.

The Company recognized a preliminary gain on the sale of $26.2 million during the three and six month periods ended June 30, 2015.

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Discontinued Operations

MHP and Williston Hunter Canada, Inc.

In September 2013, the Company adopted a plan to divest all of its interests in (i) MHP, whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of Williston Hunter Canada, Inc. ("WHI Canada"), which was a wholly-owned subsidiary of the Company. The Company closed on the sale of its interests in WHI Canada during the second quarter of 2014. Effective September 2014, the Company withdrew its plan to divest MHP. Consequently, the assets and liabilities of MHP are presented as held for use effective September 2014 and the results of MHP's operations are presented in continuing operations for all periods presented in these interim consolidated financial statements.

Eureka Hunter Holdings

In June 2015, the Company adopted a plan to divest of its entire equity ownership interest in Eureka Hunter Holdings in order to improve its liquidity position. Based on early indications of interest, the Company believes that it could complete the divestiture within the next 60 to 90 days. Prior to December 18, 2014, Eureka Hunter Holdings was a consolidated subsidiary of the Company and its operations were included in the Midstream and Marketing operating segment. Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company determined it no longer held a controlling financial interest in Eureka Hunter Holdings. However, the Company exercises significant influence through its retained equity interest and through representation on Eureka Hunter Holdings' board of managers and owned 45.53% of the outstanding membership interest of Eureka Hunter Holdings as of June 30, 2015. As a result, the Company uses the equity method to account for its retained interest in Eureka Hunter Holdings. The Company has reclassified its equity method investment in Eureka Hunter Holdings to assets of discontinued operations as of June 30, 2015 and December 31, 2014. All operations related to periods prior to December 18, 2014, and all subsequent equity method losses, are reflected as discontinued operations.

On November 18, 2014, the Company entered into a letter agreement (the "November 2014 Letter Agreement") with Eureka Hunter Holdings and MSIP II Buffalo Holdings, LLC ("MSI"), an affiliate of Morgan Stanley Infrastructure II Inc. Pursuant to the November 2014 Letter Agreement, the parties agreed that, among other things, the Company would make a $13.3 million capital contribution (the "MHR 2015 Contribution") in cash to Eureka Hunter Holdings on or before March 31, 2015, in exchange for additional Series A-1 Units in Eureka Hunter Holdings.

On March 30, 2015, the Company, Eureka Hunter Holdings and MSI entered into an additional letter agreement (the "March 2015 Letter Agreement"), pursuant to which the parties agreed that, among other things, (i) the Company is no longer required to make the MHR 2015 Contribution and (ii) MSI would make certain additional capital contributions to Eureka Hunter Holdings in exchange for additional Series A-2 Units. Pursuant to the March 2015 Letter Agreement, MSI purchased additional Series A-2 Units of Eureka Hunter Holdings as follows:

i. On March 31, 2015, MSI made a capital contribution in cash to Eureka Hunter Holdings of approximately $27.2 million (the "2015 Growth CapEx Projects Contribution") in exchange for additional Series A-2 Units in Eureka Hunter Holdings with the proceeds of such capital contribution to be used to fund certain of Eureka Hunter Pipeline's 2015 capital expenditures. The 2015 Growth CapEx Projects Contribution is subject to the Company's right to make an MHR Catch-Up Contribution (as defined in the Second Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings (the "LLC Agreement")).

ii. On March 31, 2015, MSI made an additional capital contribution in cash to Eureka Hunter Holdings of approximately $37.8 million (the "Additional Contribution") in exchange for additional Series A-2 Units in Eureka Hunter Holdings with the proceeds of such Additional Contribution to be used to fund certain of Eureka Hunter Pipeline's additional capital expenditures and for certain other uses.

Immediately after giving effect to these transactions, the Company and MSI owned 45.53% and 53.00%, respectively, of the equity interests of Eureka Hunter Holdings, with the Company's equity ownership consisting of Series A-1 Units and MSI's equity ownership consisting of Series A-2 Units.

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Pursuant to the March 2015 Letter Agreement, the parties further agreed that the Company had the right, in its discretion, to fund as a capital contribution to Eureka Hunter Holdings, all or a portion (in specified minimum amounts) of its pro-rata share of the Additional Contribution, which pro-rata share equals approximately $18.7 million (the "MHR Additional Contribution Component"), before June 30, 2015 (the "MHR Contribution Deadline"), in exchange for additional Series A-1 Units in Eureka Hunter Holdings (the "MHR 2015 Make-up Contribution").  On July 27, 2015, the Company entered into an additional letter agreement (the "July 2015 Letter Agreement") with Eureka Hunter Holdings and MSI pursuant to which the parties memorialized an agreement in principle which had been reached prior to June 30, 2015, to extend the MHR Contribution Deadline to the earlier of (i) September 30, 2015 or (ii) the day immediately preceding the date on which the Company disposes, in a sale transaction or otherwise, its equity ownership interest in Eureka Hunter Holdings. If the Company funds the full MHR Additional Contribution Component on or prior to the MHR Contribution Deadline, (but excluding any other capital contributions that may be made by the Company or MSI pursuant to the LLC Agreement), the Company and MSI will own 46.44% and 52.11%, respectively, of the Class A Common Units of Eureka Hunter Holdings.

If the Company does not fund the full MHR Additional Contribution Component by the MHR Contribution Deadline, as amended by the July 2015 Letter Agreement, the Company's Series A-1 Units in Eureka Hunter Holdings will be adjusted downward by an amount equivalent to the unfunded portion of the MHR Additional Contribution Component divided by the purchase price per unit paid by MSI in connection with the 2015 Growth CapEx Projects Contribution and the Additional Contribution. If the Company does not fund any of the MHR Additional Contribution Component on or prior to the MHR Contribution Deadline, the Company and MSI will own 44.53% and 53.98%, respectively, of the Class A Common Units of Eureka Hunter Holdings. If the Company does not fund all or a portion of the MHR Additional Contribution, a downward adjustment of its capital account, as described above, could result in the Company recognizing a loss on its investment in Eureka Hunter Holdings. If the Company funds a portion (in specified minimum amounts), but not all of the MHR Additional Contribution Component, on or prior to the MHR Contribution Deadline, then the ownership percentages of the Company and MSI will be adjusted in a manner consistent with the first sentence of this paragraph but with the downward adjustment for the Company being proportionally reduced.

Pursuant to the July 2015 Letter Agreement, the Company agreed that neither the Company nor any of its affiliates will use, directly or indirectly, any proceeds received from the disposal of the Company's equity ownership interest in Eureka Hunter Holdings to fund the MHR Additional Contribution Component. In addition, pursuant to the July 2015 Letter Agreement, the Company will not have the right to fund the MHR Additional Contribution Component unless, at the time the Company would otherwise make such contribution, the Company (including any relevant affiliate of the Company) is current in respect of all of its payment obligations under all gas gathering agreements to which the Company (or any affiliate of the Company), on the one hand, and Eureka Hunter Holdings (or any subsidiary thereof), on the other hand, are party to or otherwise subject to.

After the earlier to occur of (a) the Company having made contributions equal to the MHR Additional Contribution Component or (b) the MHR Contribution Deadline, the Company may make MHR Catch-Up Contributions (as defined in the LLC Agreement) in accordance with the LLC Agreement (as modified by the November 2014 Letter Agreement as to the applicable time and amount limitations) in respect of any MHR Shortfall Amounts (as defined in the LLC Agreement) that are eligible to be funded by the Company under the LLC Agreement.

The Company accounted for the March 31, 2015 MSI capital contributions and the issuance of additional Series A-2 Units by Eureka Hunter Holdings in accordance with the subsequent measurement provision of ASC Topic 323, Investments - Equity Method and Joint Ventures, which requires the Company to recognize a gain or loss on the dilution of its equity interest as if the Company had sold a proportionate interest in Eureka Hunter Holdings. The Company recognized a pre-tax gain of $2.4 million based on the difference between the carrying value of the Company's Series A-1 Units and the proceeds received by Eureka Hunter Holdings for the issuance of additional Series A-2 Units to MSI which resulted in permanent dilution of the Company's equity interest in Eureka Hunter Holdings. The gain included the Company's proportionate decrease in its equity method basis difference which was reduced by $3.9 million based on the change in the Company's ownership in the net assets of Eureka Hunter Holdings after giving effect to the dilution of the Company's interest as a result of the unit issuance.

As of June 30, 2015, the Company and MSI owned 45.53% and 53.00%, respectively, of the Class A Common Units of Eureka Hunter Holdings. The Company recorded its retained interest in Eureka Hunter Holdings initially at a fair value of $347.3 million in December 2014. The carrying value of the Company's equity interest in Eureka Hunter Holdings was $345.3 million and $347.2 million at June 30, 2015 and December 31, 2014, respectively.

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The recognition of the Company's retained interest in Eureka Hunter Holdings at fair value upon deconsolidation resulted in a basis difference between the carrying value of the Company's investment in Eureka Hunter Holdings and its proportionate share in net assets of Eureka Hunter Holdings. The basis difference was accounted for using the acquisition method of accounting, which requires that the basis difference be allocated to the identifiable assets of Eureka Hunter Holdings at fair value and based upon the Company's proportionate ownership.  Determining the fair value of assets and liabilities is judgmental in nature and involves the use of significant estimates and assumptions. The Company recognized a basis difference of $201.8 million upon deconsolidation related to its investment in Eureka Hunter Holdings which has been allocated to the following identifiable assets of Eureka Hunter Holdings:

	Identifiable Assets
	Ending Basis December 31, 2014		Basis Amortization			Basis Reduction			Ending Basis June 30, 2015
	(in thousands)
Fixed assets	$	5,088	$	(128	)	$	(98	)	$	4,862
Intangible assets	155,189		(3,750		)	(2,705		)	148,734
Goodwill	41,597		—			(1,104		)	40,493
Total basis difference	$	201,874	$	(3,878	)	$	(3,907	)	$	194,089

The components of the Company's basis difference, excluding goodwill, are being amortized over their estimated useful lives ranging from 3 to 39 years.

The Company has completed its valuation of the identifiable assets to which the basis difference is attributable to and has recorded amortization based on this valuation for the period ended June 30, 2015.  

Summarized income information for Eureka Hunter Holdings for the three and six months ended June 30, 2015 is as follows:

	Three Months Ended   June 30, 2015			Six Months Ended   June 30, 2015
	(in thousands)
Operating revenues	$	17,409		$	31,124
Operating income (loss)	$	1,790		$	1,318
Net income (loss)	$	736		$	(846	)
Magnum Hunter's interest in Eureka Hunter Holdings net income (loss)	$	384		$	(385	)
Basis difference amortization	$	(1,978	)	$	(3,878	)
Magnum Hunter's equity in earnings, net	$	(1,594	)	$	(4,263	)

As of June 30, 2015 and December 31, 2014, the Company had assets of discontinued operations of $345.3 million and $347.2 million, respectively, consisting of its equity method investment in Eureka Hunter Holdings.

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The Company included the results of operations related to Eureka Hunter Holdings for all periods presented, and the results of operations of WHI Canada through May 12, 2014, the date of sale, in discontinued operations. The following presents the results of our discontinued operations for the three and six months ended June 30, 2014 and June 30, 2015.

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(in thousands)
Revenues	$	—		$	11,103		$	—		$	22,960
Depreciation, depletion, amortization and accretion	—			(3,929		)	—			(7,607		)
Other operating expenses	—			(9,238		)	—			(17,302		)
Interest expense	—			(605		)	—			(6,487		)
Loss on derivative contracts, net	—			(39,830		)	—			(33,894		)
Loss from equity method investments	(1,594		)	—			(4,263		)	—
Other expense	—			(25		)	—			(43		)
Loss from discontinued operations, net of tax	(1,594		)	(42,524		)	(4,263		)	(42,373		)
Gain on dilution of interest in Eureka Hunter Holdings, net of tax	—			—			2,390			—
Loss on disposal of discontinued operations, net of taxes of $0	—			(5,212		)	—			(13,725		)
Loss from discontinued operations, net of taxes	$	(1,594	)	$	(47,736	)	$	(1,873	)	$	(56,098	)

Total operating cash inflows related to Eureka Hunter Holdings for the three and six month periods ended June 30, 2014 were $31.6 million and $38.4 million, respectively, and total investing cash outflows related to Eureka Hunter Holdings for the three and six month periods ended June 30, 2014 were $46.0 million and $64.4 million, respectively.

NOTE 3 - OIL & NATURAL GAS SALES

During the three and six months ended June 30, 2015 and 2014, 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,
	2015		2014		2015		2014
	(in thousands)
Oil	$	15,087	$	41,506	$	24,631	$	76,859
Natural gas	13,023		28,264		44,883		55,784
NGLs	5,308		14,002		13,295		27,094
Total oil and natural gas sales	$	33,418	$	83,772	$	82,809	$	159,737

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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, 2015			December 31, 2014
	(in thousands)
Mineral interests in properties:
Unproved leasehold costs	$	444,692		$	481,643
Proved leasehold costs	284,185			257,185
Wells and related equipment and facilities	642,420			606,406
Advances to operators for wells in progress	1,283			1,411
Total costs	1,372,580			1,346,645
Less accumulated depletion, depreciation, and amortization	(323,210		)	(248,410		)
Net capitalized costs	$	1,049,370		$	1,098,235

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 properties of $0.1 million and $13.9 million were recorded during the three and six months ended June 30, 2015, primarily related to Appalachian Basin properties. Impairments of proved properties of $0.2 million and $16.9 million were recorded for the three and six months ended June 30, 2014, which were comprised primarily of impairments recorded on MHP's proved oil and natural gas properties.

Depletion, depreciation, and amortization expense for proved oil and natural gas properties was $19.6 million and $74.9 million for the three and six months ended June 30, 2015, respectively, and $30.1 million and $53.9 million for the three and six months ended June 30, 2014, respectively.

Exploration

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

During the three and six months ended June 30, 2015 and 2014, the Company recognized exploration expense as follows:

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
	(in thousands)
Leasehold impairments	$	931	$	8,833	$	8,769	$	24,383
Geological and geophysical	548		353		1,200		727
Total exploration expense	$	1,479	$	9,186	$	9,969	$	25,110

Leasehold impairment expense recorded by the Company during the three and six months ended June 30, 2015 consisted of $0.9 million and $1.2 million, respectively, in the U.S. upstream segment related to leases in the Appalachian Basin and $7.6 million during the six months ended June 30, 2015 related to leases in the Williston Basin. Leasehold impairment expense during the three and six months ended June 30, 2014 consisted of $8.8 million and $19.9 million, respectively, related to leases in the Williston Basin and $2.6 million during the six months ended June 30, 2014 related to leases in the Appalachian Basin. Impairments of leases in the Williston and Appalachian Basins for all periods presented related to leases that expired undrilled during the period or are expected to expire and that the Company does not plan to develop or extend.

The Company also recognized $0.0 million and $1.9 million in leasehold impairment expense related to fair value write-downs of MHP for the three and six months ended June 30, 2014.

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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, 2015 and December 31, 2014 is summarized as follows:

	June 30, 2015			December 31, 2014
	(in thousands)
Gas transportation, gathering and processing equipment and other	$	102,817		$	100,436
Less accumulated depreciation	(26,786		)	(23,013		)
Net capitalized costs	$	76,031		$	77,423

Depreciation expense for gas transportation, gathering, and processing equipment and other property was $2.1 million and $3.9 million for the three and six months ended June 30, 2015, respectively, and $1.6 million and $3.1 million for the three and six months ended June 30, 2014, respectively.

NOTE 5 - ASSET RETIREMENT OBLIGATIONS

The following table summarizes the Company's asset retirement obligation ("ARO") activities during the six-month period ended June 30, 2015 and for the year ended December 31, 2014:

	June 30, 2015			December 31, 2014
	(in thousands)
Asset retirement obligations at beginning of period	$	26,524		$	16,216
Assumed in acquisitions	92			—
Liabilities incurred	2			218
Liabilities settled	(55		)	(107		)
Liabilities sold	(74		)	(2,598		)
Accretion expense	1,281			1,478
Revisions in estimated liabilities (1)	(859		)	3,208
Reclassified from liabilities associated with assets of MHP	—			8,109
Asset retirement obligation at end of period	26,911			26,524
Less: current portion (included in other liabilities)	(967		)	(295		)
Asset retirement obligations at end of period	$	25,944		$	26,229

________________________________

 ⁽¹⁾ Revisions in estimated liabilities during 2014 relate to a change in assumptions used with respect to certain wells in the Appalachian Basin in Ohio and West Virginia.

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

GAAP defines 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.  GAAP also establishes 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

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Transfers between levels of the fair value hierarchy 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 the six month periods ended June 30, 2015 and 2014.

The Company used the following fair value measurements for certain of the Company's assets and liabilities at June 30, 2015 and December 31, 2014:

Level 1 Classification:

Available for Sale Securities

At June 30, 2015 and December 31, 2014, the Company held common and preferred stock of publicly traded companies with quoted prices in an active market.  Accordingly, the fair market value measurements of these securities have been classified as Level 1.

Level 2 Classification:

Commodity Derivative Instruments

At June 30, 2015 and December 31, 2014, the Company had commodity derivative financial instruments in place. The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting.  Changes in fair value of derivative instruments subsequent to the initial measurement are recorded as gain (loss) on derivative contracts, in other income (expense). 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.

As of June 30, 2015 and December 31, 2014, the Company's derivative contracts were with financial institutions, many of which were either senior lenders to the Company or affiliates of such senior lenders, and some of which had investment grade credit ratings. Certain counterparties to the Company's commodity derivatives positions are no longer participants in the Company's credit facilities following the execution of new credit agreements on October 22, 2014 and an amendment on July 10, 2015. See "Note 8 - Debt". All of the counterparties are believed to have minimal credit risk. 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:

Convertible Security Embedded Derivative

The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with the convertible note it received in February 2012 as partial consideration upon the sale of Hunter Disposal, LLC ("Hunter Disposal") to GreenHunter Resources, Inc. ("GreenHunter"), a related party. The embedded derivative was valued using a Black-Scholes model valuation of the conversion option.

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

	June 30, 2015
Life (in years)	1.6
Risk-free interest rate	0.75%
Estimated volatility	84%
Dividend	—
GreenHunter stock price at end of period	$0.67

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 its assets as compared to the financial statements as a whole.

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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, 2015
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	2,447	$	—	$	—
Convertible security derivative assets	—		—		27
Total assets at fair value	$	2,447	$	—	$	27
Liabilities
Commodity derivative liabilities	$	—	$	490	$	—
Total liabilities at fair value	$	—	$	490	$	—

	Fair Value Measurements on a Recurring Basis
	December 31, 2014
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	3,864	$	—	$	—
Commodity derivative assets	—		16,511		—
Convertible security derivative assets	—		—		75
Total assets at fair value	$	3,864	$	16,511	$	75

The following table presents the changes in fair value of the derivative assets and liabilities measured at fair value using significant unobservable inputs (Level 3 inputs) for the six-month period ended June 30, 2015:

	Convertible Security Embedded Derivative Asset
	(in thousands)
Fair value as of December 31, 2014	$	75
Decrease in fair value recognized in gain (loss) on derivative contracts, net	(48		)
Fair value as of June 30, 2015	$	27

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, 2015				December 31, 2014
	Fair Value Hierarchy	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
		(in thousands)
Senior Notes	Level 2	$	597,459	$	540,000	$	597,355	$	498,000
MHR Senior Revolving Credit Facility	Level 3	$	5,000	$	5,000	$	—	$	—
MHR Second Lien Term Loan	Level 3	$	328,002	$	319,769	$	329,140	$	329,140
Equipment Notes Payable	Level 3	$	18,078	$	18,041	$	22,238	$	22,150

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 identical or similar assets in markets that are not active).

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The carrying value of the Company's senior revolving credit facility (the "MHR Senior Revolving Credit Facility") approximates fair value as the facility is subject to short-term floating interest rates that approximate the rates available to the Company at these dates.  The fair value hierarchy for the MHR Senior Revolving Credit Facility is Level 3.

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. 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. A reconciliation of the beginning and ending balances of the Company's ARO is presented in "Note 5 - Asset Retirement Obligations".

The Company recorded impairment charges of $13.9 million during the six months ended June 30, 2015 as a result of writing down the carrying value of certain proved properties to estimated fair value. The fair value of the properties impaired was $487.3 million as of June 30, 2015. In order to determine the amounts of the impairment charges, Magnum Hunter compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management's expectations of economically recoverable proved, probable, and possible reserves. If the net capitalized cost exceeds the undiscounted future net cash flows, Magnum Hunter impairs the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a discounted cash flow model utilizing a 10% discount rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Magnum Hunter's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

The Company recorded impairment charges of $16.8 million during the first quarter of 2014 in order to record MHP at the estimated selling price less costs to sell, based on additional information on estimated selling prices obtained through active marketing of the assets. The fair value of these net assets was $60.0 million as of March 31, 2014. The Company had designated this valuation as Level 3. Effective September 2014, the Company withdrew its plan to divest MHP. Consequently, the assets and liabilities of MHP are presented as held for use and the results of MHP's operations are presented in continuing operations for all periods presented in these interim consolidated financial statements.

NOTE 7 - INVESTMENTS AND DERIVATIVES

Investment Holdings - Available for Sale Securities

The Company's investment holdings in available for sale securities 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. At December 31, 2014, 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 period then ended. At March 31, 2015, the Company's investment in New Standard Energy Limited ("NSE"), an Australian Securities Exchange-listed Australian company, was in a gross unrealized loss position for greater than a year. The Company reviewed its investment for impairment and considered such factors as NSE's future business outlook, the prevailing economic environment and the overall market condition for the Company's investment. As a result of its review, the Company recorded an other-than-temporary impairment of $9.0 million which was reclassified from accumulated other comprehensive income into "Other expense" on the consolidated statements of operations during the first quarter of 2015, related to the decline in value of its investment in NSE.

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Investment Holdings - GreenHunter

The Company holds an equity method investment in common shares of GreenHunter received as partial consideration for the sale by Triad Hunter of its equity ownership interest in Hunter Disposal to GreenHunter in 2012. The GreenHunter common stock investment had no carrying value at June 30, 2015 or December 31, 2014. The GreenHunter common shares are publicly traded and had a fair value of $1.3 million at June 30, 2015 and December 31, 2014, which is not reflected in the carrying value since the Company's investment is accounted for using the equity method.

Below is a summary of changes in investments for the six months endedJune 30, 2015:

	Available for Sale Securities
	(in thousands)
Carrying value as of December 31, 2014	$	3,864
Loss from equity method investment(1)	(318		)
Change in fair value recognized in other comprehensive loss	(1,099		)
Carrying value as of June 30, 2015	$	2,447

⁽¹⁾As a result of the carrying value of the Company's investment in common stock of GreenHunter being reduced to zero from equity method losses, the Company is required to allocate any additional losses to its investment in the Series C preferred stock of GreenHunter. The Company recorded additional equity method loss against the carrying value of its investment in the Series C preferred stock of GreenHunter before recording any mark-to-market adjustments.

The Company's investments in available for sale securities have been presented in current assets as "Investments" in the consolidated balance sheet as of June 30, 2015 and December 31, 2014.

The cost for equity securities and their respective fair values as of June 30, 2015 and December 31, 2014 are as follows:

	June 30, 2015
	(in thousands)
	Cost		Gross Unrealized Losses			Fair Value
Securities available for sale, carried at fair value:
Equity securities	$	883	$	(174	)	$	709
Equity securities - related party (see "Note 13 - Related Party Transactions")	2,200		(462		)	1,738
Total Securities available for sale	$	3,083	$	(636	)	$	2,447

	December 31, 2014
	(in thousands)
	Cost		Gross Unrealized Losses			Fair Value
Securities available for sale, carried at fair value:
Equity securities	$	9,876	$	(7,323	)	$	2,553
Equity securities - related party (see "Note 13 - Related Party Transactions")	2,200		(889		)	1,311
Total Securities available for sale	$	12,076	$	(8,212	)	$	3,864

The methods of determining the fair values of Magnum Hunter's investments in equity securities are described in "Note 6 - Fair Value of Financial Instruments".

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Commodity and Financial Derivative Instruments

The Company periodically enters into certain commodity derivative instruments such as futures contracts, swaps, collars, and basis swap contracts. 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. The commodity derivative contracts held by the Company as of June 30, 2015 are contracts which were in a net liability position at the time of termination of the majority of its commodity derivative contracts during May 2015. The Company has not designated any commodity derivative instruments as hedges.

As of June 30, 2015, the Company had the following commodity derivative instruments:

Crude Oil	Period	Bbl/day	Price per Bbl
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Jan 2015 - Dec 2015	259	$70.00

On May 7, 2015, the Company obtained consent under the MHR Senior Revolving Credit Facility to terminate the Company's open commodity derivative positions, so long as all such terminations occur prior to the November 1, 2015 borrowing base redetermination. See "Note 8 - Debt". The Company received approximately $11.8 million in cash proceeds from the termination of the majority of its open commodity derivative positions that were terminated on May 7, 2015.

As of June 30, 2015, Citibank, N.A. is the only counterparty to the Company's commodity derivatives positions.  Collateral securing the MHR Senior Revolving Credit Facility is used as collateral for the Company's commodity derivatives with those counterparties participating, currently or at the time the commodity derivative position was entered into, in the MHR Senior Revolving Credit Facility, under which the Company had outstanding borrowings of $5.0 million as of June 30, 2015. Effective as of July 10, 2015, Citibank, N.A. is no longer a participant in the Company's credit facilities. The Company is exposed to credit losses in the event of nonperformance by the counterparties where the Company's open commodity derivative contracts are in a gain position. The Company does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. See "Note 8 - Debt".

At June 30, 2015, 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 6 - Fair Value of Financial Instruments" and "Note 13 - Related Party Transactions".

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

	Derivatives not designated as hedging instruments
	Derivative Assets				Derivative Liabilities
	June 30, 2015		December 31, 2014		June 30, 2015		December 31, 2014
	(in thousands)
Commodity
Derivative assets	$	—	$	16,511	$	—	$	—
Derivative liabilities	—		—		490		—
Total commodity	$	—	$	16,511	$	490	$	—
Financial
Derivative assets	$	27	$	75	$	—	$	—
Total financial	$	27	$	75	$	—	$	—
Total derivatives	$	27	$	16,586	$	490	$	—

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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 of those derivatives in the Company's consolidated balance sheets as of:

	June 30, 2015
	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset on the Consolidated Balance Sheet		Net Amount
	(in thousands)
Current liabilities:  Fair value of derivative contracts	(490		)	—		(490		)
	$	(490	)	$	—	$	(490	)

	December 31, 2014
	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	$	18,146		$	(1,635	)	$	16,511
Current liabilities:  Fair value of derivative contracts	(1,635		)	1,635			—
	$	16,511		$	—		$	16,511

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, 2015 and 2014:

	Three Months Ended June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(in thousands)
Gain (loss) on settled transactions	$	(1,117	)	$	(2,267	)	$	3,194		$	(4,551	)
Gain (loss) on open contracts	792			(739		)	(417		)	(4,044		)
Total gain (loss), net	$	(325	)	$	(3,006	)	$	2,777		$	(8,595	)

NOTE 8 - DEBT

Long-term debt at June 30, 2015 and December 31, 2014 consisted of the following: 

	June 30, 2015			December 31, 2014
	(in thousands)
Senior Notes payable due May 15, 2020, interest rate of 9.75%, net of unamortized net discount of $2.5 million and $2.6 million at June 30, 2015 and December 31, 2014, respectively	$	597,459		$	597,355
Various equipment and real estate notes payable with maturity dates February 2015 - November 2017, interest rates of 4.25% - 7.94%	18,078			22,238
MHR Senior Revolving Credit Facility due October 22, 2018, interest rate of 4.19% at June 30, 2015 and 2.92% at December 31, 2014	5,000			—
MHR second lien term loan due October 22, 2019, interest rate of 8.5%, net of unamortized discount of $9.4 million and $10.0 million at June 30, 2015 and December 31, 2014, respectively	328,002			329,140
	948,539			948,733
Less: current portion	(9,854		)	(10,770		)
Total long-term debt obligations, net of current portion	$	938,685		$	937,963

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The following table presents the scheduled or expected approximate annual maturities of debt, gross of unamortized discount of $12.0 million as of June 30, 2015: 

	(in thousands)
2015	$	4,912
2016	12,127
2017	5,948
2018	8,958
2019	325,757
Thereafter	602,826
Total	$	960,528

MHR Senior Revolving Credit Facility and Second Lien Term Loan

Senior Revolving Credit Facility

On October 22, 2014, the Company entered into the Fourth Amended and Restated Credit Agreement by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders party thereto and the agents party thereto (the "Credit Agreement").

First Amendment to Credit Agreement and Limited Waiver

On February 24, 2015, the Company entered into a First Amendment to Credit Agreement and Limited Waiver (the "First Amendment") that, among other things, (i) waived the then existing current ratio covenant requirement for the December 31, 2014 compliance period and (ii) lowered the current ratio requirement to 0.75 from 1.0 for the fiscal quarter ending March 31, 2015. Pursuant to the First Amendment, the current ratio requirement would have increased to 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter. The First Amendment also modified the leverage ratio requirement to remain at not more than 2.5x beginning with the December 31, 2014 compliance period through the December 31, 2015 compliance period.

In addition, the First Amendment provided that, until such time as the Company can demonstrate a (i) current ratio of 1.0 to 1.0 as of the last day of a fiscal quarter or, if there is a proposed Liquidity Event (described below) or other arms-length liquidity event with a non-affiliate or unrestricted subsidiary, demonstrate a current ratio of 1.0 to 1.0 on a pro forma basis as of the last day of a calendar month assuming that the Liquidity Event (or other liquidity event) had occurred during such calendar month and (ii) in the case of a decrease of the Rates for ABR Loans and Eurodollar Loans, pro forma compliance with the other applicable financial covenants as of the last day of the fiscal quarter most recently ended, (such period, the "Adjusted Period"), then:

i. neither the Company nor any of its restricted subsidiaries were permitted to make additional investments in excess of $2 million in the aggregate in oil and gas properties (other than acreage swaps and associated assets) and other applicable assets;

ii. neither the Company nor any of its restricted subsidiaries were permitted to make additional capital contributions to or other investments in unrestricted subsidiaries in amounts in excess of $2 million in the aggregate; and

iii. the Company could not make any additional capital contributions to or other investments in Eureka Hunter Holdings.

For purposes of the First Amendment, a "Liquidity Event" means any event or events resulting in (i) an increase in Liquidity (as defined in the Credit Agreement, as amended by the First Amendment) of at least $36,000,000 as a result of an arm's length transaction with a person or entity that is not an affiliate of the Company or (ii) the receipt by the Company or any restricted subsidiary of aggregate net cash proceeds of at least $73,000,000 as a result of one or more arm's length transactions with either (a) persons or entities who are not affiliates of the Company or (b) the Company's unrestricted subsidiaries.

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The First Amendment also provided that effective March 31, 2015, if a Liquidity Event (described in clause (i) of the preceding paragraph) had not occurred prior to such date, or April 30, 2015 if a proposed Liquidity Event described in clause (ii) of the preceding paragraph for which a pro forma current ratio calculation was used had not occurred prior to such date, the rates for ABR Loans and Eurodollar Loans would automatically increase by 1.00% and the commitment fee would automatically increase by 0.25% and such elevated rates would continue until the day immediately preceding the date on which the Adjusted Period ended. No Liquidity Event or proposed Liquidity Event for which a pro forma current ratio calculation was used had occurred as of April 30, 2015. Accordingly the rates for ABR Loans and Eurodollar Loans and the commitment fee were increased as described in the second preceding sentence.

Second Amendment to Credit Agreement and Limited Waiver

The Company entered into the Second Amendment to Credit Agreement and Limited Waiver (the "Second Amendment") on and effective as of April 17, 2015 by and among the Company, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto. The waiver required that certain events and conditions be satisfied by May 29, 2015 as further described below. The Second Amendment amended the Credit Agreement to:

i. Extend the amount of time the Company and its Restricted Subsidiaries (as defined in the Credit Agreement) may have accounts payable outstanding after the invoice date from 90 days to 180 days for any day on or prior to May 29, 2015, after which the date the restriction would have reverted back to 90 days.

ii. Condition the Company's ability to pay cash dividends on its three outstanding series of preferred stock as follows:

1. Payment of the preferred stock dividends for the month of April 2015 was permitted provided the Company's previously filed shelf registration statement (the "Shelf Registration Statement"), providing for, among other things, at-the-market ("ATM") offerings of equity securities of the Company, had been declared effective by the Securities and Exchange Commission (the "SEC") and the Company had executed an agreement (a "Sales Agreement") with an underwriter or sales agent to proceed with any such ATM offerings. The Shelf Registration Statement was declared effective on April 22, 2015 and the Company entered into a Sales Agreement on April 23, 2015.

2. Payment of the preferred stock dividends for the month of May 2015 was permitted provided the Company had received, by May 29, 2015, at least $65.0 million of aggregate net cash proceeds from the issuance by the Company of equity securities, permitted asset sales by the Company or any Restricted Subsidiary or the entry into a joint venture by the Company or any Restricted Subsidiary (including the receipt of any contemplated upfront payments therefrom).

iii. Increase the applicable interest rate margins under the First Lien Credit Agreement by a nominal amount of 25 basis points. The applicable interest rate margins will automatically revert back to the lower levels in effect immediately prior to the effective date of the First Amendment when the Company demonstrates full compliance with its financial covenants under the Credit Agreement or compliance with such covenants on a pro forma basis giving effect to one or more Liquidity

Events.

In addition, pursuant to the Second Amendment, the lenders agreed to waive (i) effective as of March 31, 2015, compliance with the current ratio and leverage ratio covenants under the Credit Agreement for the fiscal quarter ended March 31, 2015 (which covenants, prior to the waiver, required a current ratio of not less than 0.75 to 1.0, and leverage ratio of not more than 2.5 to 1.0, for such fiscal quarter) and (ii) any default or event of default that may have occurred as a result of non-compliance with the accounts payable aging limitation in effect prior to the effective date of the Second Amendment, as described above. These waivers were subject to the Company having received, by May 29, 2015, at least $65.0 million of aggregate net cash proceeds from one or more of the issuance by the Company of equity securities, permitted asset sales by the Company or any Restricted Subsidiary or the entry into a joint venture by the Company or any Restricted Subsidiary (including the receipt of upfront payments therefrom) (the "Waiver Condition").

On May 7, 2015, the Company obtained consent under the MHR Senior Revolving Credit Facility to terminate the Company's open commodity derivative positions, so long as all such terminations occurred prior to the November 1, 2015 borrowing base redetermination. Such terminations have been contemplated and are reflected in the May 1, 2015 borrowing base redetermination. Following the May 1, 2015 borrowing base redetermination, the Company's borrowing base under the MHR Senior Revolving Credit Facility was maintained at $50 million. The Company terminated the majority of its open commodity derivative positions on May 7, 2015. See "Note 7 - Investments and Derivatives".

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Third Amendment to Credit Agreement and Limited Consent

On and effective as of May 28, 2015, the Company entered into the Third Amendment to Credit Agreement and Limited Consent (the "Third Amendment") by and among the Company, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto. The Third Amendment amended the Credit Agreement to:

i. Extend the amount of time the Company and its Restricted Subsidiaries may have accounts payable outstanding after the invoice date from 90 days to 180 days for any day on or prior to June 19, 2015 (rather than May 29, 2015, as provided in the Second Amendment), after which June 19, 2015 date the restriction would have reverted back to 90 days; and

ii. Remove the condition, previously added by the Second Amendment, on the Company's ability to pay cash dividends on its three outstanding series of preferred stock for the month of May 2015, so that the Company may pay such dividends as scheduled on June 1, 2015 without regard to such condition.

In addition, pursuant to the Third Amendment, the lenders agreed to extend the deadline for Magnum Hunter to satisfy the Waiver Condition from May 29, 2015 to June 19, 2015.

Fourth Amendment to Credit Agreement and Limited Consent

On and effective as of June 19, 2015, the Company entered into the Fourth Amendment to Credit Agreement and Limited Consent (the "Fourth Amendment") by and among the Company, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto. The Fourth Amendment amended the Credit Agreement to extend the amount of time the Company and its Restricted Subsidiaries may have accounts payable outstanding after the invoice date from 90 days to 180 days for any day on or prior to July 10, 2015, after which July 10, 2015 date the restriction would have reverted back to 90 days. In addition, pursuant to the Fourth Amendment, the lenders agreed to extend the deadline for Magnum Hunter to satisfy the Waiver Condition from June 19, 2015 to July 10, 2015.

Fifth Amendment to Credit Agreement and Limited Waiver

On and effective as of July 10, 2015, the Company entered into the Fifth Amendment to Credit Agreement and Limited Waiver (the "Fifth Amendment") by and among the Company, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto. The Fifth Amendment amended the Credit Agreement to, among other things:

i. Permanently eliminate the Company's obligation to raise $65.0 million in net cash proceeds from one or more of the issuance by the Company of equity securities, permitted asset sales by the Company or any Restricted Subsidiary or the entry into a joint venture by the Company or any Restricted Subsidiary (including the receipt of upfront payments therefrom);

ii. Extend the amount of time the Company and its Restricted Subsidiaries may have accounts payable outstanding after the invoice date from 90 days to 180 days for any day on or prior to the earlier of (a) December 31, 2015 or (b) the date that is ten business days following the date on which the Company consummates the sale of all or substantially all of the Company's equity ownership interest in Eureka Hunter Holdings (the date of such sale, the "Trigger Date"), after which earlier date the restriction will revert back to 90 days; and

iii. Permit certain lenders to sell and assign their rights and obligations under the Credit Agreement to the Bank of Montreal.

In addition, the Fifth Amendment includes a waiver of compliance by the Company with the current ratio and leverage ratio covenants for the fiscal quarter ended June 30, 2015 (which covenants, prior to the waiver, required a current ratio of not less than 1.0 to 1.0 and a leverage ratio of not more than 2.5 to 1.0) and for each fiscal quarter ending thereafter until the earlier of (i) the fiscal quarter ending December 31, 2015 or (ii) the fiscal quarter in which the Trigger Date occurs, at which time the waiver of these financial covenants will no longer be in effect commencing with the earlier of the fiscal quarters referred to in clauses (i) and (ii) of this sentence. Upon expiration of the waiver of these financial covenants, the Company will be required to maintain (i) a current ratio of not less than 1.0 to 1.0 for the fiscal quarter during which the waiver expired and each quarter ending thereafter and (ii) a leverage ratio of not more than (a) 2.5 to 1.0 for the fiscal quarters ending September 30, 2015 (if the Trigger Date occurs during such fiscal quarter) and December 31, 2015 and (b) 2.0 to 1.0 for the fiscal quarter ending March 31, 2016 and for each fiscal quarter ending thereafter.

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As of June 30, 2015, the borrowing base under the Senior Revolving Credit Facility was $50.0 million, and outstanding borrowings were $5.0 million. The Company also posted letters of credit for $39.0 million using availability under the Company's Senior Revolving Credit Facility. As of June 30, 2015, the borrowing capacity under the Senior Revolving Credit Facility was $6.0 million.

On July 27, 2015, the Company became aware of a technical default under the Credit Agreement, as amended. In accordance with the terms of the Credit Agreement, as amended, the Company may not have accounts payable outstanding in excess of 180 days from the invoice date for any day on or prior to the earlier of (a) December 31, 2015 or (b) the Trigger Date, after which earlier date the restriction will revert back to 90 days. As of August 7, 2015, the Company had approximately $8.8 million in accounts payable, in excess of permissible amounts provided for in the Credit Agreement, which were outstanding in excess of 180 days from the invoice date. Under the Credit Agreement, the Company has 30 days to cure this technical default and expects to cure the technical default within the 30 day deadline, on or before August 26, 2015. Between July 27, 2015 and August 7, 2015, the Company realized net proceeds of $6.0 million from the sale of the Company's common stock through an ATM sales program, which proceeds were used to reduce the amount of accounts payable outstanding in excess of 180 days from the invoice date, as well as proceeds from the final settlement of the sale of unproved, undeveloped leasehold acreage to Antero and cash on hand. The Company plans to continue utilizing proceeds from non-core asset sales and a limited amount of ATM offerings of its equity securities to cure the technical default and to maintain these minimum credit requirements in the future.

Second Lien Term Loan

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

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

i. a ratio of the present value of proved reserves using five year strip pricing to secured debt of not less than 1.5 to 1.0 and a ratio of the present value of proved developed and producing reserves using five year strip pricing to secured debt of not less than 1.0 to 1.0, each as of the last day of any fiscal quarter commencing with the fiscal quarter ending December 31, 2014; and

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

On and effective as of April 17, 2015, the Company entered into a First Amendment to Credit Agreement and Limited Waiver (the "Second Lien Amendment"), by and among the Company, as borrower, Credit Suisse AG Cayman Islands Branch, as administrative agent and collateral agent, and the several lenders and guarantors party thereto. The Second Lien Amendment amended the Second Lien Term Loan Agreement by permanently extending the amount of time the Company and its Restricted Subsidiaries (as defined in the Second Lien Term Loan Agreement) may have accounts payable outstanding after the invoice date from 90 days to 180 days. In addition, pursuant to the Second Lien Amendment, the lenders waived any default or event of default that may have occurred in connection with any non-compliance with the accounts payable aging limitation in effect prior to the effective date of the Second Lien Amendment.

At June 30, 2015, the Company was in compliance with the proved reserves and proved developed and producing reserves coverage ratio financial covenants applicable for the period, contained in the Second Lien Term Loan Agreement.

On July 27, 2015, the Company became aware of a technical default under the Second Lien Term Loan Agreement, as amended. In accordance with the terms of the Second Lien Term Loan Agreement, as amended, the Company may not have accounts payable outstanding in excess of 180 days from the invoice date. As of August 7, 2015, the Company had approximately $8.8 million in accounts payable, in excess of permissible amounts provided for in the Credit Agreement, which were outstanding in excess of 180 days from the invoice date. The Company has 30 days to cure this technical default and expects to cure the technical default within the 30 day deadline, on or before August 26, 2015. Between July 27, 2015 and August 7, 2015, the Company realized net proceeds of $6.0 million from the sale of shares of its common stock through the ATM program, which proceeds were used to reduce the amount of accounts payable outstanding in excess of 180 days from the invoice date, as well as proceeds from the final settlement of the sale of unproved, undeveloped leasehold acreage to Antero and cash on hand. The Company plans to continue utilizing proceeds from non-core asset sales and a limited amount of ATM offerings of its equity securities to cure the technical default and to maintain these minimum credit requirements in the future.

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Interest Expense

The following table sets forth interest expense for the three and six month periods ended June 30, 2015 and 2014, respectively:

	Three Months Ended   June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
	(in thousands)
Interest expense incurred on debt, net of amounts capitalized	$	23,262	$	15,937	$	45,920	$	33,084
Amortization and write-off of deferred financing costs	840		3,939		1,647		4,807
Total interest expense	$	24,102	$	19,876	$	47,567	$	37,891

For the six-month period ended June 30, 2014, interest expense incurred on debt includes $1.7 million in unamortized deferred financing costs related to the amendment of the MHR Senior Revolving Credit Facility.

NOTE 9 - SHARE-BASED COMPENSATION

Employees, officers, directors, and other persons who contribute to the success of Magnum Hunter are eligible for grants of unrestricted common stock, restricted common stock, common stock options, and stock appreciation rights under the Company's Amended and Restated Stock Incentive Plan.  At June 30, 2015, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 12,399,175 shares had been issued under the plan as of June 30, 2015, of which 2,308,084 shares were unvested at June 30, 2015. Additionally, 10,747,306 options to purchase shares and stock appreciation rights were outstanding as of June 30, 2015, of which 2,314,793 were unvested at June 30, 2015.

The Company recognized share-based compensation expense of $1.7 million and $4.8 million for the three and six months ended June 30, 2015, respectively, and $2.3 million and $3.4 million for the three and six months ended June 30, 2014, respectively.

A summary of common stock option activity for the six months ended June 30, 2015 and 2014 is presented below:

	Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands of shares)				Weighted Average Exercise Price per Share
Outstanding at beginning of period	13,195		16,891		$	5.92	$	5.69
Granted	—		—		$	—	$	—
Exercised	—		(2,115	)	$	—	$	4.14
Forfeited	(2,448	)	(932	)	$	6.43	$	6.32
Outstanding at end of period	10,747		13,844		$	5.81	$	5.88
Exercisable at end of period	8,433		9,478		$	5.91	$	6.20

A summary of the Company's non-vested common stock options and stock appreciation rights for the six months ended June 30, 2015 and 2014 is presented below:

	Six Months Ended June 30,
	2015		2014
	(in thousands of shares)
Non-vested at beginning of period	4,055		6,908
Granted	—		—
Vested	(1,356	)	(1,801	)
Forfeited	(385	)	(741	)
Non-vested at end of period	2,314		4,366

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Total unrecognized compensation cost related to the non-vested common stock options and stock appreciation rights was $1.1 million and $6.3 million as of June 30, 2015 and 2014, respectively.  The unrecognized compensation cost at June 30, 2015 is expected to be recognized over a weighted-average period of 0.68 years. At June 30, 2015, the weighted average remaining contract life of outstanding options was 4.56 years.

On March 30, 2015, the Company granted 535,274 shares of common stock for 2014 bonuses to executives and officers of the Company. The shares had a fair value at the time of grant of $1.4 million based on the Company's stock price on the grant date. On June 18, 2015, the Company granted 600,000 restricted shares of common stock to non-employee members of the board of directors of the Company which vest two years from the date of grant, or if earlier, (i) upon the death or disability of the director or (ii) upon a change in control of the Company that occurs at least six months following the date of grant. The shares had a fair value at the time of grant of $0.7 million based on the Company's stock price on the grant date and an estimated forfeiture rate of 5.6%. During the six months ended June 30, 2015, the Company also granted an additional 105,000 restricted shares of common stock to certain newly hired officers which vest over a 3-year period, and which had a fair value at the time of grant of $0.3 million based on the Company's stock price on the grant date and an estimated forfeiture rate of 5.6%.

Total unrecognized compensation cost related to non-vested, restricted shares amounted to $6.8 million and $8.3 million as of June 30, 2015 and 2014, respectively.  The unrecognized cost at June 30, 2015 is expected to be recognized over a weighted-average period of 1.64 years.

NOTE 10 - SHAREHOLDERS' EQUITY

Common Stock

During the six months ended June 30, 2015, the Company issued 1,100,937 shares of the Company's common stock in connection with share-based compensation which had fully vested to senior management and directors of the Company.

On March 13, 2015, the Company filed a universal shelf Form S-3 Registration Statement to register the sale by the Company of a maximum aggregate amount of up to $500 million of debt and equity securities. The Company filed amendments to this Form S-3 Registration Statement on April 15, 2015 and April 20, 2015 and the Form S-3 Registration Statement became effective on April 22, 2015. On April 23, 2015, the Company entered into an "At the Market" Sales Agreement with a sales agent to conduct ATM offerings of its equity securities. As of June 30, 2015, the Company had sold an aggregate of 11,441,596 shares of its common stock for aggregate proceeds of $21.8 million net of $0.6 million in sales commissions and other fees through this ATM offering under the Form S-3 Registration Statement.

Preferred Dividends Incurred

A summary of the Company's preferred dividends for the three and six months ended June 30, 2015 and 2014 is presented below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
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		8,849
Dividend on Series E Preferred Stock	1,860		1,861		3,722		3,695
Total dividends on Preferred Stock	$	8,847	$	8,848	$	17,695	$	17,668
Dividend on Eureka Hunter Holdings Series A Preferred Units	$	—	$	4,253	$	—	$	8,281
Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	—		2,229		—		4,277
Total dividends on Preferred Stock of discontinued operations	$	—	$	6,482	$	—	$	12,558

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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, 2015 and 2014:

	June 30,
	2015	2014
	(in thousands of shares)
Series E Preferred Stock	10,946	10,946
Warrants	19,173	19,214
Unvested restricted shares	2,242	1,475
Common stock options and stock appreciation rights	10,747	13,844
Total	43,108	45,479

NOTE 11 - 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"). Pursuant to this Unit Purchase Agreement, Ridgeline had purchased $200.0 million of Eureka Hunter Holdings Series A Preferred Units as of September 16, 2014.

On September 16, 2014, the Company entered into an agreement (the "Transaction Agreement") with MSI and Eureka Hunter Holdings relating to a separate purchase agreement between MSI and Ridgeline providing for the purchase by MSI of all the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units owned by Ridgeline. The Transaction Agreement also provided for the execution of the LLC Agreement to be entered into by Magnum Hunter, MSI and the minority interest members of Eureka Hunter Holdings contingent upon and contemporaneously with the closing of MSI's purchase of Ridgeline's equity interests in Eureka Hunter Holdings, which occurred on October 3, 2014.

In accordance with the terms of the LLC Agreement, all of the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units of Eureka Hunter Holdings acquired by MSI from Ridgeline were converted into Series A-2 Common Units, a new class of equity interests of Eureka Hunter Holdings, which were subsequently derecognized by the Company and included in the gain on deconsolidation of Eureka Hunter Holdings on December 18, 2014.

NOTE 12 - TAXES

The Company did not recognize an income tax benefit or expense from continuing operations for the three and six months ended June 30, 2015 and 2014 as a result of its large net operating losses and corresponding valuation allowance.

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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 carry forwards. 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, 2015, no adjustments have been proposed by any tax jurisdiction that would have a significant impact on the Company's liquidity, future results of operations or financial position.

NOTE 13 - RELATED PARTY TRANSACTIONS

The following table sets forth the related party balances as of June 30, 2015 and December 31, 2014:

	June 30, 2015			December 31, 2014
	(in thousands)
GreenHunter (1)
Accounts payable - net	$	(809	)	$	(224	)
Derivative assets (2)	$	27		$	75
Investments (2)	$	1,738		$	1,311
Notes receivable (2)	$	952		$	1,224
Prepaid expenses	$	—		$	1,000
Eureka Hunter Holdings (3)
Accounts receivable (payable) - net	$	(5,053	)	$	122
Assets of discontinued operations	$	345,318		$	347,191
Pilatus Hunter
Accounts receivable - net	$	12		$	12
Classic Petroleum, Inc. (5)
Accounts payable	$	(304	)	$	—

The Company holds investments in a related party consisting of 1,846,722 shares of common stock of GreenHunter with no carrying value as of June 30, 2015 and 88,000 shares of Series C preferred stock of GreenHunter with a carrying value of $1.7 million as of June 30, 2015.

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The following table sets forth the related party transaction activities for the three and six months ended June 30, 2015 and 2014, respectively:

		Three Months Ended   June 30,				Six Months Ended   June 30,
		2015		2014		2015		2014
		(in thousands)
GreenHunter
	Production costs (1)	$	1,288	$	632	$	2,199	$	1,076
	Midstream natural gas gathering, processing, and marketing	$	—	$	400	$	—	$	400
	Oilfield services (1)	$	71	$	—	$	104	$	—
	General and administrative (1)	$	6	$	13	$	12	$	36
	Interest income (2)	$	39	$	38	$	70	$	83
	Miscellaneous income (2)	$	55	$	55	$	110	$	110
	Loss from equity method investment (2)	$	87	$	135	$	318	$	357
	Capitalized costs incurred (1)	$	19	$	1,192	$	465	$	1,810
Pilatus Hunter, LLC (4)
	General and administrative	$	25	$	88	$	36	$	158
Eureka Hunter Holdings (3)
	Production costs	$	478	$	—	$	596	$	—
	Transportation, processing, and other related costs	$	4,973	$	—	$	10,714	$	—
	Oilfield Services	$	13	$	—	$	16	$	—
	Capitalized costs incurred	$	—	$	—	$	121	$	—
Classic Petroleum (5)
	Capitalized costs incurred	$	23	$	212	$	185	$	524

_________________________________

⁽¹⁾   GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman and a major shareholder. 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 certain affiliated companies. 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 6 - 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 investment in affiliates - equity method and an available for sale investment in GreenHunter included in investments. 

⁽³⁾  Following a series of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. The Company deconsolidated Eureka Hunter Holdings and accounts for its retained interest as of December 31, 2014 under the equity method of accounting. See "Note 7 - Investments and Derivatives". As discussed in "Note 2 - Acquisitions, Divestitures, and Discontinued Operations", in June 2015 the Company adopted a plan to dispose of its equity method investment in Eureka Hunter Holdings, and has classified the related operations as discontinued operations and the investment as assets of discontinued operations for all periods presented.

⁽⁴⁾  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.

⁽⁵⁾  Classic Petroleum, Inc. is an entity owned by the brother of James W. Denny, III, the Company's Executive Vice President and President of the Company's Appalachian Division. Triad Hunter received land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services.

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In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water.  On December 22, 2014, Triad Hunter entered into an Amendment to Produced Water Hauling and Disposal Agreement with GreenHunter Water to secure long-term water disposal at reduced rates through December 31, 2019. To ensure disposal capacity, in connection with the amendment on December 29, 2014, Triad Hunter made a prepayment of $1.0 million towards services to be provided under the Produced Water Hauling and Disposal Agreement. GreenHunter Water provided a 50% credit for all services performed under the agreement until the prepayment amount was utilized in full, which occurred during the first half of 2015.

As of June 30, 2015, the Company had a note receivable from GreenHunter with an outstanding principal balance of approximately $1.0 million.  Under the terms of the promissory note, GreenHunter is required to make quarterly payments to the Company  comprised of principal of $137,500 and accrued interest through the maturity of the note in February 2017. Under the terms of the note, failure to pay timely is considered an event of default. As of March 31, 2015, GreenHunter was past due on principal and interest payments in aggregate of $168,437, which were due on February 17, 2015. On May 4, 2015, GreenHunter made this past due principal and interest payment of $168,437.

As of June 30, 2015, Mr. Evans, the Company's Chairman and Chief Executive Officer, held 27,641 Series A-1 Common Units of Eureka Hunter Holdings.

Triad Hunter and Eureka Hunter Pipeline are parties to an Amended and Restated Gas Gathering Services Agreement, which was executed on March 21, 2012, and amended on October 3, 2014 in contemplation of the LLC Agreement. Under the terms of the gathering agreement, Triad Hunter reserved throughput capacity in the gas gathering pipeline system of Eureka Hunter Holdings for which Triad Hunter has committed to minimum reservation fees of approximately $0.75 per MMBtu.

Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Holdings and its subsidiaries became related parties of the Company. The Company and Eureka Hunter Holdings entered into a Services Agreement on March 20, 2012, and amended on September 15, 2014, under which the Company agreed to provide administrative services to Eureka Hunter Holdings related to its operations. The terms of the Services Agreement provide that the Company will receive an administrative fee of $500,000 per annum and a personnel services fee equal to the Company's employee cost plus 1.5% subject to mutually agreed upon increases from time to time. Under the terms of the LLC Agreement, certain specified employees of the Company that perform services for Eureka Hunter Holdings and its subsidiaries and for whom the Company previously billed a personnel services fee, are expected to become employees of Eureka Hunter Holdings or a subsidiary of Eureka Hunter Holdings.

On July 18, 2014, the Company entered into a consulting agreement with Kirk J. Trosclair, a former executive of Alpha Hunter Drilling, LLC, a wholly-owned subsidiary of the Company. Mr. Trosclair ceased employment with the Company on July 18, 2014 and is currently the Chief Operating Officer of GreenHunter. The agreement has a term of 12 months and provides that Mr. Trosclair will receive monthly compensation of $10,000, and Mr. Trosclair is eligible to continue vesting in previously granted stock options and unvested restricted stock awards, subject to continued service under the consulting agreement. In connection with this agreement, for the six months ended June 30, 2015, the Company paid Mr. Trosclair $89,000, which includes reimbursement of expenses incurred on behalf of the Company, and recognized $76,000 in stock compensation expense.

NOTE 14 - COMMITMENTS AND CONTINGENCIES

Agreement to Purchase Utica Shale Acreage

On August 12, 2013, Triad Hunter entered into an asset purchase agreement with MNW. 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 January 14, 2015, Triad Hunter closed on the acquisition of 2,665 net leasehold acres for $12.0 million from MNW. To date, under the asset purchase agreement, Triad Hunter has now acquired a total of approximately 25,044 net leasehold acres from MNW, or approximately 78.3% of the approximately 32,000 total net leasehold acres anticipated under the asset purchase agreement.

Drilling Rig Purchase

During June 2014, the Company, through its wholly-owned subsidiary, Alpha Hunter Drilling, LLC, executed 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, which was expected to be on or about January 15, 2015. In February 2015, the Company was notified that the rig was complete and available for delivery. However, the Company has not taken delivery of the rig and and has initiated negotiations to apply the deposit towards a trade on a different drilling rig or associated equipment.

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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 subsequently appealed the decision dismissing the Securities Cases to the U.S. Court of Appeals for the Second Circuit. One June 23, 2015, the U.S. Court of Appeals for the Second Circuit entered a Summary Order unanimously affirming the Southern District of New York's dismissal of the Securities Cases in favor of the Company and the individual defendants. It is possible that additional investor lawsuits could be filed over these events.

On May 10, 2013, Steven Handshu filed a stockholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers. On June 6, 2013, Zachariah Hanft filed another stockholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers. On June 18, 2013, Mark Respler filed another stockholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers. On June 27, 2013, Timothy Bassett filed another stockholder derivative suit in the Southern District of Texas on behalf of the Company against the Company's directors and senior officers. On September 16, 2013, the Southern District of Texas allowed Joseph Vitellone to substitute for Mr. Bassett as plaintiff in that action. On March 19, 2014 Richard Harveth filed another stockholder derivative suit in the 125th District Court of Harris County, Texas.  These suits are collectively referred to as the Derivative Cases. The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company's motion to dismiss the stockholder derivative case maintained by Joseph Vitellone and entered a final judgment of dismissal. The court held that Mr. Vitellone failed to plead particularized facts demonstrating that pre-suit demand on the Company's board was excused. In addition, on December 13, 2013, the 151st Judicial District Court of Harris County, Texas dismissed the lawsuit filed by Steven Handshu for want of prosecution after the plaintiff failed to serve any defendant in that matter. On January 21, 2014, the Hanft complaint was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the United States District Judge for the District of Delaware granted the Company's supplemental motion to dismiss the Derivative Case filed by Mark Respler. On July 22, 2014, the 125th District Court of Harris County, Texas issued an Order and Final Judgment granting the Company's and the individual defendants' motion for summary judgment in its entirety and entering a final judgment dismissing the suit filed by Richard Harveth. The plaintiffs may file an appeal. All of the Derivative Cases have now been dismissed. 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 ("Scavo Action"). The Scavo Action seeks various

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books and records relating to the claims in the Securities Cases and the Derivative Cases, as well as costs and attorneys' fees. The Company has filed an answer in the Scavo Action, which has now been dismissed. It is possible that additional similar actions may be filed and that similar stockholder demands could be made.

In April 2013, the Company also received a letter from the staff of the SEC's Division of Enforcement (the "Staff") stating that the Staff 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. In 2014, the SEC issued additional subpoenas for documents and testimony and has taken testimony from certain individuals. The Company intends to cooperate with the subpoenas. In connection with the Staff's inquiry, on March 24, 2015, the Company received a "Wells Notice" from the Staff, stating that the Staff has made a preliminary determination to recommend that the SEC file an enforcement action against the Company. On that date, the Staff issued similar Wells Notices to Gary C. Evans, the Company's Chairman and Chief Executive Officer, J. Raleigh Bailes, Sr., a director of the Company and former Chairman of the Company's Audit Committee, the former chief financial officer of the Company who was in office at the time of the Company's decision to dismiss its prior independent registered public accounting firm and the former chief accounting officer of the Company who had resigned from that position with the Company in October 2012. The Wells Notice issued to the Company states that the proposed action against the Company would allege violations of Sections 17(a)(2) and 17(a)(3) of the Securities Act of 1933 and Sections 13(a), 13(b)(2)(A), and 13(b)(2)(B) of the Securities Exchange Act of 1934 and Rules 13a-l, 13a-13, and 13a-15(a) thereunder. The proposed actions against the individuals would allege violations of those same provisions, as well as violations of Section 13(b)(5) of the Securities Exchange Act of 1934 and Rules 13a-14 and 13a-15(c) thereunder. The proposed actions described in the Wells Notices do not include any claims for securities fraud under Section 10(b) of the Securities Exchange Act of 1934 or Rule 10b-5 thereunder or under Section 17(a)(1) of the Securities Act of 1933. The Wells Notices state that the Staff's recommendation may involve a civil injunctive action, public administrative proceeding, and/or cease-and-desist proceeding, and may seek remedies that might include, among other things, a cease-and-desist order, injunctions, disgorgement with pre-judgment interest and civil money penalties, as well as potential administrative remedies against Mr. Bailes under Rule 102(e)(1)(iii) of the SEC's Rules of Practice. A Wells Notice is neither a formal allegation nor a finding of wrongdoing. It allows the recipient the opportunity, through a "Wells Submission", to provide the recipient's reasons of law, policy or fact as to why the proposed enforcement action should not be filed and to address the issues raised by the Staff before any decision is made by the SEC on whether to authorize the commencement of an enforcement proceeding. On April 21, 2015, the Company responded to its Wells Notice in the form of a Wells Submission, pursuant to which the Company set forth why it believes an enforcement action against it and the individuals should not be commenced. The Company has engaged and continues to engage in discussions with the Staff regarding the issues raised in the Wells Notices. The Company cannot predict with confidence or certainty the ultimate outcome of the SEC process, including whether a settlement with respect to the issues raised in the Wells Notices may be reached with the Staff. If an enforcement action is subsequently brought against the Company by the SEC, the Company intends to mount a vigorous defense consistent with the defenses that were successfully mounted with respect to all of the previous Securities Cases and Derivative Cases.

Any potential liability, if any, 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 also 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 a case styled Karen S. Phipps v. Eureka Hunter Pipeline, LLC et al., Civil Action No. 14-C-41, in the Circuit Court of Ohio County, West Virginia. In October 2014, in a case styled Exterran Energy Solutions, LP v. Eureka Hunter Pipeline, LLC and Magnum Hunter Resources Corporation, Civil Action No. 2014-63353, in the District Court of Harris County, Texas, Exterran Energy Solutions, LP, one of the co-defendants in the Phipps lawsuit, filed suit against the Company and Eureka Hunter Pipeline seeking a declaratory judgment that Eureka Hunter Pipeline is obligated to indemnify Exterran with respect to the Phipps lawsuit. In April 2014, the estate of the other deceased third-party contractor employee sued the Company, Eureka Hunter Pipeline and certain other parties in a case styled 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 also been asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter Resources Corporation and certain other parties in a case styled Jonathan Whisenhunt v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-135, in the Circuit Court of Ohio County, West Virginia. The claim filed by the injured third-party contractor employee, Jonathan Whisenhunt, has been resolved and dismissal of this case is anticipated in the near term. A portion of the settlement was paid by an insurer of Eureka Hunter Pipeline, and the remainder paid by the co-defendants or their insurers. The

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cross-claims among the defendants in the Whisenhunt litigation have not been resolved. In addition, the claim filed by Antoinette M. Miller has been successfully mediated and, subject to Court approval, is anticipated to be resolved and dismissed in the near term. Insurers providing coverage to Eureka Hunter Pipeline, Magnum Hunter Resources Corporation and other affiliated or related entities will pay a portion of the settlement, with the remainder to be paid by the co-defendants or their insurers. 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 related to the litigation remaining regarding 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, subject to the retention amounts under the insurance policies.

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 15 - SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended June 30,
	2015			2014
	(in thousands)
Cash paid for interest	$	41,947		$	35,679
Non-cash transactions
Non-cash consideration received from sale of assets	$	—		$	9,447
Change in accrued capital expenditures	$	(75,585	)	$	41,270
Non-cash additions to asset retirement obligation	$	516		$	13
Eureka Hunter Holdings Series A Preferred Unit dividends paid in kind	$	—		$	1,950

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NOTE 16 - SEGMENT REPORTING

U.S. Upstream, Midstream, and Oilfield Services represent the operating segments of the Company.  Effective September 30, 2013, the Canadian Upstream segment, comprised of the WHI Canada operations, was classified as discontinued operations. The Company sold 100% of the equity in WHI Canada in May 2014.

The following tables set forth operating activities and capital expenditures by segment for the three and six months ended, and segment assets as of June 30, 2015 and 2014, respectively.

	As of and for the Three Months Ended June 30, 2015
	U.S. Upstream			Canadian Upstream		Midstream and Marketing		Oilfield Services			Corporate Unallocated (1)			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	33,701		$	—	$	431	$	6,878		$	—		$	(1,484	)	$	39,526
Depletion, depreciation, amortization and accretion	21,266			—		—		999			—			48			22,313
Gain on sale of assets, net	(26,744		)	—		—		—			—			—			(26,744		)
Other operating expenses	27,329			—		197		4,848			8,610			(1,556		)	39,428
Other expense	(601		)	—		—		(142		)	(23,868		)	—			(24,611		)
Income (loss) from continuing operations before income tax	11,249			—		234		889			(32,478		)	24			(20,082		)
Total loss from discontinued operations, net of tax	—			—		—		—			(1,594		)	—			(1,594		)
Net income (loss)	$	11,249		$	—	$	234	$	889		$	(34,072	)	$	24		$	(21,676	)
Total assets	$	1,101,855		$	—	$	160	$	45,566		$	389,168		$	(2,485	)	$	1,534,264
Total capital expenditures	$	13,104		$	—	$	—	$	48		$	410		$	—		$	13,562

	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	$	84,138		$	—		$	39,556		$	7,795		$	—		$	(1,841	)	$	129,648
Depletion, depreciation, amortization and accretion	31,188			—			—			838			—			—			32,026
Gain on sale of assets, net	(316		)	—			—			(371		)	—			—			(687		)
Other operating expenses	41,113			—			38,554			6,361			13,054			(5,587		)	93,495
Other income (expense)	204			—			—			(211		)	(22,498		)	—			(22,505		)
Income (loss) from continuing operations before income tax	12,357			—			1,002			756			(35,552		)	3,746			(17,691		)
Total income (loss) from discontinued operations, net of tax	(2,705		)	11,461			(39,970		)	—			(12,776		)	(3,746		)	(47,736		)
Net income (loss)	$	9,652		$	11,461		$	(38,968	)	$	756		$	(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

35

	As of and for the Six Months Ended June 30, 2015
	U.S. Upstream			Canadian Upstream		Midstream and Marketing		Oilfield Services			Corporate Unallocated (1)			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	83,914		$	—	$	749	$	13,552		$	—		$	(3,293	)	$	94,922
Depletion, depreciation, amortization and accretion	78,163			—		—		2,005			—			(105		)	80,063
Gain on sale of assets, net	(28,384		)	—		—		(12		)	—			—			(28,396		)
Other operating expenses	88,988			—		601		10,125			19,644			(3,144		)	116,214
Other expense	(8,814		)	—		—		(308		)	(43,641		)	—			(52,763		)
Income (loss) from continuing operations before income tax	(63,667		)	—		148		1,126			(63,285		)	(44		)	(125,722		)
Total loss from discontinued operations, net of tax	—			—		—		—			(1,873		)	—			(1,873		)
Net income (loss)	$	(63,667	)	$	—	$	148	$	1,126		$	(65,158	)	$	(44	)	$	(127,595	)
Total assets	$	1,101,855		$	—	$	160	$	45,566		$	389,168		$	(2,485	)	$	1,534,264
Total capital expenditures	$	60,422		$	—	$	—	$	469		$	1,858		$	—		$	62,749

	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	$	160,350		$	—	$	65,593		$	15,706		$	—		$	(4,131	)	$	237,518
Depletion, depreciation, amortization and accretion	56,128			—		—			1,628			—			—			57,756
Loss on sale of assets, net	3,757			—		—			(369		)	—			—			3,388
Other operating expenses	109,978			—		65,443			13,074			23,542			(10,963		)	201,074
Other expense	(168		)	—		—			(420		)	(45,742		)	—			(46,330		)
Income (loss) from continuing operations before income tax	(9,681		)	—		150			953			(69,284		)	6,832			(71,030		)
Total income (loss) from discontinued operations, net of tax	(7,024		)	10,636		(40,102		)	—			(12,776		)	(6,832		)	(56,098		)
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⁾   Includes the Company's retained interest in Eureka Hunter Holdings which has a value of $345.3 million at June 30, 2015. As discussed in "Note 2 - Acquisitions, Divestitures, and Discontinued Operations", in June 2015 the Company adopted a plan to dispose of its equity method investment in Eureka Hunter Holdings, and has classified the related operations as discontinued operations and the investment as assets of discontinued operations for all periods presented.

36

NOTE 17 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS

Guarantor Subsidiaries

Certain of the Company's subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, LLC, Shale Hunter, LLC, Magnum Hunter Marketing, LLC, MHP, NGAS Hunter, LLC, Triad Hunter, Viking International Resources, Co., Inc., and Bakken Hunter Canada, 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 may also guarantee any debt of the Company issued pursuant to the Form S-3 Registration Statement filed by the Company with the SEC on March 15, 2015, amended on April 20, 2015, and declared effective on April 22, 2015.

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, 2015 and December 31, 2014, and for the three and six months ended June 30, 2015 and 2014, are as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of June 30, 2015
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	12,886		$	30,542		$	377		$	(2,441	)	$	41,364
Intercompany accounts receivable	1,136,540			—			—			(1,136,540		)	—
Property and equipment (using successful efforts method of accounting)	6,653			1,118,792			—			(44		)	1,125,401
Investment in subsidiaries	(146,125		)	92,314			—			53,811			—
Assets of discontinued operations and other	366,578			921			—			—			367,499
Total Assets	$	1,376,532		$	1,242,569		$	377		$	(1,085,214	)	$	1,534,264
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	25,755		$	119,623		$	9		$	(2,443	)	$	142,944
Intercompany accounts payable	—			1,097,221			41,555			(1,138,776		)	—
Long-term liabilities	929,551			40,543			—			—			970,094
Redeemable preferred stock	100,000			—			—			—			100,000
Shareholders' equity (deficit)	321,226			(14,818		)	(41,187		)	56,005			321,226
Total Liabilities and Shareholders' Equity	$	1,376,532		$	1,242,569		$	377		$	(1,085,214	)	$	1,534,264

37

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of December 31, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries		Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	85,647		$	41,533	$	589		$	(2,378	)	$	125,391
Intercompany accounts receivable	1,113,417			—		—			(1,113,417		)	—
Property and equipment (using successful efforts method of accounting)	5,506			1,170,122		30			—			1,175,658
Investment in subsidiaries	(91,595		)	94,134		—			(2,539		)	—
Assets of discontinued operations and other	369,995			3,980		—			—			373,975
Total Assets	$	1,482,970		$	1,309,769	$	619		$	(1,118,334	)	$	1,675,024
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	25,347		$	148,109	$	2,567		$	(2,383	)	$	173,640
Intercompany accounts payable	—			1,073,091		42,560			(1,115,651		)	—
Long-term liabilities	925,767			43,762		—			—			969,529
Redeemable preferred stock	100,000			—		—			—			100,000
Shareholders' equity (deficit)	431,856			44,807		(44,508		)	(300		)	431,855
Total Liabilities and Shareholders' Equity	$	1,482,970		$	1,309,769	$	619		$	(1,118,334	)	$	1,675,024

38

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Three Months Ended June 30, 2015
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	12		$	41,214		$	233		$	(1,933	)	$	39,526
Expenses	31,922			29,601			42			(1,957		)	59,608
Income (loss) from continuing operations before equity in net income of subsidiaries	(31,910		)	11,613			191			24			(20,082		)
Equity in net income of subsidiaries	11,828			(144		)	—			(11,684		)	—
Income (loss) from continuing operations	(20,082		)	11,469			191			(11,660		)	(20,082		)
Gain on dilution of interest in Eureka Hunter Holdings	—			—			—			—			—
Loss from discontinued operations, net of tax	(1,594		)	—			—			—			(1,594		)
Net income (loss)	(21,676		)	11,469			191			(11,660		)	(21,676		)
Dividends on preferred stock	(8,847		)	—			—			—			(8,847		)
Net income (loss) attributable to common shareholders	$	(30,523	)	$	11,469		$	191		$	(11,660	)	$	(30,523	)
	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		$	131,208		$	274		$	(1,840	)	$	129,648
Expenses	36,512			116,053			362			(5,588		)	147,339
Income (loss) from continuing operations before equity in net income of subsidiaries	(36,506		)	15,155			(88		)	3,748			(17,691		)
Equity in net income of wholly-owned subsidiaries	(19,314		)	(984		)	—			20,298			—
Income (loss) from continuing operations	(55,820		)	14,171			(88		)	24,046			(17,691		)
Loss from discontinued operations, net of tax	—			—			(38,778		)	(3,746		)	(42,524		)
Gain (loss) 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		)	—			—			—			(8,848		)
Dividends on preferred stock of discontinued operations	—			—			(6,482		)	—			(6,482		)
Net income (loss) attributable to common shareholders	$	(80,148	)	$	14,171		$	(35,080	)	$	21,080		$	(79,977	)

39

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Six Months Ended June 30, 2015
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	13		$	98,210		$	761		$	(4,062	)	$	94,922
Expenses	63,208			161,050			404			(4,018		)	220,644
Income (loss) from continuing operations before equity in net income of subsidiaries	(63,195		)	(62,840		)	357			(44		)	(125,722		)
Equity in net income of subsidiaries	(62,527		)	(1,820		)	—			64,347			—
Income (loss) from continuing operations	(125,722		)	(64,660		)	357			64,303			(125,722		)
Gain on dilution of interest in Eureka Hunter Holdings	2,390			—			—			—			2,390
Income from discontinued operations, net of tax	(4,263		)	—			—			—			(4,263		)
Net income (loss)	(127,595		)	(64,660		)	357			64,303			(127,595		)
Dividends on preferred stock	(17,695		)	—			—			—			(17,695		)
Net income (loss) attributable to common shareholders	$	(145,290	)	$	(64,660	)	$	357		$	64,303		$	(145,290	)
	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		$	241,089		$	445		$	(4,130	)	$	237,518
Expenses	71,305			247,770			437			(10,964		)	308,548
Income (loss) from continuing operations before equity in net income of subsidiaries	(71,191		)	(6,681		)	8			6,834			(71,030		)
Equity in net income of wholly-owned subsidiaries	(48,129		)	(829		)	—			48,958			—
Income (loss) from continuing operations	(119,320		)	(7,510		)	8			55,792			(71,030		)
Loss from discontinued operations, net of tax	—			—			(35,541		)	(6,832		)	(42,373		)
Gain (loss) on sale of discontinued operations, net of tax	(19,799		)	—			6,074			—			(13,725		)
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		)	—			—			—			(17,668		)
Dividends on preferred stock of discontinued operations	—			—			(12,558		)	—			(12,558		)
Net income (loss) attributable to common shareholders	$	(156,787	)	$	(7,510	)	$	(42,017	)	$	49,849		$	(156,465	)

40

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended June 30, 2015
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries		Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(21,676	)	$	11,469		$	191	$	(11,660	)	$	(21,676	)
Foreign currency translation loss	—			(13		)	—		—			(13		)
Unrealized gain on available for sale securities	—			309			—		—			309
Amounts reclassified for other than temporary impairment of available for sale securities	—			—			—		—			—
Comprehensive income (loss)	(21,676		)	11,765			191		(11,660		)	(21,380		)

	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	)

	Six Months Ended June 30, 2015
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries		Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(127,595	)	$	(64,660	)	$	357	$	64,303	$	(127,595	)
Foreign currency translation gain	—			102			—				102
Unrealized loss on available for sale securities	—			(1,099		)	—		—		(1,099		)
Amounts reclassified for other than temporary impairment of available for sale securities	—			8,992			—		—		8,992
Comprehensive income (loss)	(127,595		)	(56,665		)	357		64,303		(119,600		)

41

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(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
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	)

42

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	Six Months Ended June 30, 2015
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries		Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Cash flows from operating activities	$	(57,824	)	$	109,933		$	—	$	(149	)	$	51,960
Cash flows from investing activities	(1,283		)	(98,570		)	—		149			(99,704		)
Cash flows from financing activities	5,898			(2,540		)	—		—			3,358
Effect of exchange rate changes on cash	—			24			—		—			24
Net increase (decrease) in cash	(53,209		)	8,847			—		—			(44,362		)
Cash at beginning of period	64,165			(10,985		)	—		—			53,180
Cash at end of period	$	10,956		$	(2,138	)	$	—	$	—		$	8,818

	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 flows from operating activities	$	(192,121	)	$	182,620		$	28,248		$	—	$	18,747
Cash flows from investing activities	49,572			(177,365		)	(57,579		)	—		(185,372		)
Cash flows 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

43

NOTE 18 - SUBSEQUENT EVENTS

Amendment and Waiver to Credit Agreement

On July 10, 2015, the Company entered into the Fifth Amendment, as described in "Note 8 - Debt".

Letter Agreement with Eureka Hunter Holdings and MSI

On July 27, 2015, the Company entered into the July 2015 Letter Agreement with Eureka Hunter Holdings and MSI, as described in "Note 2 - Acquisitions, Divestitures, and Discontinued Operations".

Derivative Contracts

During July and August 2015, as required under the terms of the Fifth Amendment, the Company entered into certain derivative transactions to protect its operating revenues and cash flows related to a portion of its future oil and natural gas sales from the risk of significant declines in commodity prices. The Company entered into costless collars for 80,000 MMbtu per day for the period from August 2015 to December 2015 with an average floor price of $2.66/MMBtu and an average ceiling price of $3.15/MMBtu and for 1,500 Bbl per day for the period from September 2015 through December 2015 with a floor price of $45.00/Bbl and a ceiling price of $48.00/Bbl. The Company also entered into a fixed price swap for the month of August 2015 for 1,500 Bbl per day at $44.65/Bbl. The Company has not designated any of its commodity derivative instruments as hedges.

Sales of Common Stock

As of August 7, 2015, the Company has sold an additional 7,720,495 shares of its common stock for proceeds of $9.3 million, net of sales commissions of $0.2 million, through its ATM offering under the Form S-3 Registration Statement subsequent to June 30, 2015.

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, 2015. 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, 2014, 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, 2014, 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,

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

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

• other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, as amended, and our subsequent filings with the Securities and Exchange Commission (the "SEC"), including this Quarterly Report on Form 10-Q.

Executive Overview

We are an independent oil and gas company engaged primarily in the exploration for and the exploitation, acquisition, development and production of natural gas and natural gas liquids resources in the United States. We are focused in what we believe to be two of the most prolific unconventional shale resource plays in the United States, specifically, the Marcellus Shale in West Virginia and Ohio and the Utica Shale in southeastern Ohio and western West Virginia. We also own (i) primarily non-operated oil and gas properties in the Williston Basin/Bakken Shale in Divide County, North Dakota and (ii) operated natural gas properties in Kentucky. Our wholly-owned subsidiary, Alpha Hunter, currently owns and operates six portable, trailer mounted drilling rigs, which are used both for our Appalachian Basin drilling operations and to provide drilling services to third parties.

Our principal business strategy is to (i) focus on high return projects in the liquids rich Marcellus Shale and the dry gas and liquids rich Utica Shale in West Virginia and Ohio, (ii) utilize our expertise in unconventional resource plays to improve our rates of return, (iii) focus on properties with operating control, (iv) selectively monetize assets at opportune times and attractive prices to the extent such assets are deemed non-core assets or we deem the disposition thereof desirable in furtherance of our principal business strategy and (v) reduce costs in the current commodity price environment. We believe the increased scale in our core natural gas and natural gas liquids 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 core acreage, selective bolt-on acquisitions of additional operated properties and mineral leasehold acreage positions in our core natural gas and natural gas liquids operating regions, and the monetization of selected assets.

Through our substantial investment in Eureka Hunter Holdings, LLC ("Eureka Hunter Holdings"), we are also currently involved in midstream operations, primarily in West Virginia and Ohio. In June 2015, we adopted a plan to divest of our entire equity ownership interest in Eureka Hunter Holdings in order to improve our liquidity position. Based on early indications of interest from third parties, we believe that we could complete the divestiture within the next 60 to 90 days. We have reclassified our equity investment in Eureka Hunter Holdings to assets of discontinued operations as of June 30, 2015 and December 31, 2014. All operations of Eureka Hunter Holdings related to periods prior to December 18, 2014 that were previously consolidated and all subsequent equity method losses, have been reclassified to discontinued operations for all periods presented.

In addition to the planned divestiture of Eureka Hunter Holdings, we have also identified a series of additional potential liquidity enhancing transactions. These liquidity events, which are outlined in greater detail below, include the removal of letters of credit associated with firm transportation commitments, joint ventures, non-core acreage sales, and the access of capital markets.

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Second Quarter 2015 Operational Highlights

U.S. Upstream

• Our average oil and natural gas production from continuing operations increased to 126,034 Mcfe/d for the three months ended June 30, 2015, compared to 105,254 Mcfe/d for the same period in 2014. Average production for the second quarter of 2015 was comprised of 15.1% oil, 68.1% natural gas, and 16.8% NGLs as compared to average production for the second quarter of 2014 of 26.8% oil, 57.5% natural gas, and 15.7% NGLs.

• We completed additional wells on the WVDNR and Stalder pads in our shale resource plays in the Marcellus and Utica Shales. Production increased as a result of the completion of additional wells on pads where previously producing wells had been shut in. As of June 30, 2015, the majority of significant unfinished drilling activities had been completed and the majority of shut in production had been returned to sales.

• We have suspended substantially all of our drilling and completion operations as we continue to monitor the commodity markets, regional supply and demand, and to further evaluate the timing of additional drilling and completion activities based upon anticipated reductions in service costs and potential improvement in commodity prices.

Oilfield Services

• As of June 30, 2015, four of the Schramm T200XD drilling rigs were under term contracts to EQT in the Appalachian Basin area for the top-hole drilling of multiple wells through December 2015. One Schramm T200XD drilling rig was temporarily demobilized during the first quarter of 2015, but went back under contract on a project-by-project basis to a third party beginning in May 2015.

• Our Schramm T500XD drilling rig was under contract to Triad Hunter for our Marcellus Shale and Utica Shale drilling program and is currently on standby, as we continue to re-evaluate our capital spending plan for 2015. Rigs deployed under contracts with non-affiliated companies were running on contracted daily rates of $12,500 at June 30, 2015.

Second Quarter 2015 Financial Highlights

• Oil and natural gas revenues from continuing operations decreased by 60.1% to $33.4 million compared to $83.8 million during the same three-month period in 2014, due to declines in commodity prices between the comparable periods.

• We reported a net loss from continuing operations of $20.1 million for the three months ended June 30, 2015, compared to net loss from continuing operations of $17.7 million for the three months ended June 30, 2014. Total operating expenses were $35.0 million for the three months ended June 30, 2015, an $89.8 million decrease from the three months ended June 30, 2014. The decrease in operating expense was primarily due to a $26.7 million gain on the sale of certain undeveloped and unproven leasehold acreage in Tyler County, West Virginia and a $38.4 million decrease in midstream natural gas gathering, processing and marketing expenses due to the decision made by a third party customer to market its own natural gas.

• On May 7, 2015, we terminated the majority of our open commodity derivative positions and received approximately $11.8 million in cash proceeds.

• On June 18, 2015, we closed on the sale of our interests in certain undeveloped and unproved leasehold acreage located in West Virginia for cash consideration of approximately $33.6 million.

• In June 2015, we adopted a plan to divest of our entire equity ownership interest in Eureka Hunter Holdings in order to improve our liquidity position. Based on early indications of interest, we believe that we could complete the divestiture within the next 60 to 90 days.

• Through June 30, 2015, we sold 11,441,596 shares of our common stock for net proceeds of $21.8 million pursuant to an At-the-Market ("ATM") offering.

• Our general and administrative expenses decreased over $7.5 million, or 40.0% for the three month period ended June 30, 2015 as compared to the three months ended June 30, 2014. We reduced our general and administrative expenses by reducing legal costs, reducing our reliance on outside consultants and temporary staffing, and closing our offices in Denver, Colorado and Calgary, Alberta, among other measures.

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Liquidity and Capital Resources

We have historically relied on borrowings under our credit facilities, proceeds from sales of assets, including liquidation of derivative positions, and proceeds from the sale of securities in the capital markets to meet our liquidity needs.  Due to the precipitous decline in oil, natural gas, and NGLs prices, we have taken steps to assess our core assets and dramatically reduce our capital expenditures. In June 2015, we announced our plan to divest of our entire ownership interest in Eureka Hunter Holdings. Based on early indications of interest from third parties, we believe that we could complete the divestiture within the next 60 to 90 days and expect to realize proceeds of $460 to $600 million. Our ability to fund planned capital expenditures, to make acquisitions, fund our operations and comply with our debt covenants depends upon the divestiture of our approximate 45.53% ownership interest in Eureka Hunter Holdings, sales of other assets, our future operating performance, which is dependent upon commodity prices, availability of borrowings under our credit facilities, and, to a lesser extent, 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 our planned divestiture of our entire interest in Eureka Hunter Holdings will be successful at the indicated amounts or whether additional liquidity from equity or debt financings beyond our credit facilities will be available, or available on acceptable terms, or at all, in the foreseeable future.

While we believe that our capital resources from the planned divestiture of our entire equity ownership interest in Eureka Hunter Holdings, existing cash balances, anticipated cash flow from operating activities, available borrowing capacity under the credit facility, proceeds from future sales of assets and proceeds from capital market transactions, will be adequate to execute our corporate strategies and to meet debt service obligations in 2015, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. 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.  Although the Company is no longer exposed to significant reductions in our borrowing capacity from redeterminations of our borrowing base, we are constrained on the amount of additional borrowing that the Company may incur. Sustained declines in prices for commodities may also put downward pressure on cash provided from our operations.

Factors that will affect our liquidity in 2015 include expected increases in production and operating cash flows associated with certain new and previously completed wells, which had been shut-in for a substantial portion of 2014 and 2015 due to pad drilling. As of June 30, 2015, all of these wells are currently producing. While the Company is currently evaluating the monetization of certain of our assets, market factors, including further declines in the prices of oil and natural gas, may result in postponement of such asset sales.

Debt covenant compliance

As of June 30, 2015, the outstanding principal amount of our debt, gross of unamortized discounts, was $961 million, of which $9.9 million becomes due in the next twelve months, and we had a working capital deficiency of $101.6 million. Our failure to service any debt or to comply with the applicable debt covenants could result in a default under the related debt agreement, and under any other debt agreement or any commodity derivative contract under which such default is a cross-default, which could result in the acceleration of the payment of such debt, termination of the lenders' commitments to make further loans to us, loss of our ownership interests in the secured properties, early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect our business, financial condition and results of operations.

As more fully discussed in "Amendments to MHR Senior Revolving Credit Facility", on and effective as of July 10, 2015, the Company entered into an amendment to its credit agreement and limited waiver to our revolving credit facility, which among other things (i) extends the amount of time the Company may have payables outstanding after the date of invoice from 90 days to 180 days for any day on or prior to the earlier of (a) December 31, 2015 or (b) the date that is ten business days following the date on which the Company consummates the sale of all or substantially all of the Company's equity ownership interest in Eureka Hunter Holdings (the date of such sale, the "Trigger Date"), after which earlier date the restriction will revert back to 90 days, and (ii) provides a limited waiver to the current ratio and secured net debt to EBITDAX ratio for the June 30, 2015 compliance period under our revolving credit facility and for each fiscal quarter ending thereafter until the earlier of (i) the fiscal quarter ending December 31, 2015 or (ii) the fiscal quarter in which the Trigger Date occurs. Additionally, the amendment and limited waiver under the revolving credit facility permanently removed the Company's obligation to raise at least $65 million in aggregate net cash proceeds from specified liquidity transactions, which was an obligation imposed on us in an earlier amendment to our revolving credit facility. If we had not entered into this amendment and waiver, we would not have been in compliance with the current ratio or secured net debt to EBITDAX financial ratio set forth under our revolving credit facility, as amended, which required that the Company have a current ratio of not less than 1.0 to 1.0 as of that date and a secured net debt to EBITDAX ratio of not more than 2.5 to 1.0 for the June 30, 2015 compliance period.

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This amendment and waiver provides the Company additional time and flexibility under our debt agreements to pursue and complete the liquidity enhancing transactions described below. We believe that these waivers and amendments as well as the successful execution of certain contemplated transactions will enable us to maintain compliance with such ratios for the next twelve months.

On July 27, 2015, we became aware of a technical default under our revolving credit facility, as amended, and our second lien term loan, as amended. In accordance with the terms of the revolving credit facility, as amended, we may not have accounts payable outstanding in excess of 180 days from the invoice date for any day on or prior to the earlier of (a) December 31, 2015 or (b) the date that is ten business days following the Trigger Date, after which earlier date the restriction will revert back to 90 days. In accordance with the terms of the second lien term loan, as amended, we may not have accounts payable outstanding in excess of 180 days from the invoice date. As of August 7, 2015, we had approximately $8.8 million in accounts payable, in excess of permissible amounts provided for in the Credit Agreement, which were outstanding in excess of 180 days from the invoice date. We have 30 days to cure this technical default and expect to cure the technical default within the 30 day deadline, on or before August 26, 2015. Between July 27, 2015 and August 7, 2015, we realized net proceeds of $6.0 million from the sale of shares of our common stock through an ATM program, which proceeds were used to reduce the amount of accounts payable outstanding in excess of 180 days from the invoice date, as well as proceeds from the final settlement of the sale of unproved, undeveloped leasehold acreage to Antero and cash on hand. We plan to continue utilizing proceeds from non-core asset sales and a limited amount of ATM offerings of our equity securities to cure the technical default and to maintain these minimum credit requirements in the future.

Other liquidity enhancing potential transactions

In addition to the recently announced plan to divest of our entire equity ownership interest in Eureka Hunter Holdings, we continue to actively pursue each of the following transactions described in more detail in our Annual Report on Form 10-K for the year ended December 31, 2014 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015:

i. Entering into a joint venture under which we would contribute a portion of our Utica Shale undeveloped leasehold acreage in Ohio to further develop our leasehold position while being funded by our joint venture partner and providing additional working capital.

ii. Entering into certain asset management agreements for the marketing by a third party of certain of our natural gas production whereby the third party also agrees to provide credit support to certain interstate pipeline companies in replacement of our firm transportation letters of credit, resulting in the cancellation of the letters of credit and a corresponding increase in borrowing capacity under the revolving credit facility;

iii. Selling approximately 27,000 net non-core unproved leasehold acres, which are non-contiguous and consists of four distinct areas, located in West Virginia and Ohio; and

iv. Issuing common stock through ATM offerings or otherwise.

The Company believes that such transactions, if completed, could provide additional liquidity or enhance the value of our assets with minimal required capital. We cannot provide assurance as to whether or when we will be able to consummate these or other liquidity enhancing transactions, or, if any liquidity enhancing transactions are consummated, whether they will be on the terms contemplated or will provide us with sufficient liquidity to meet our cash flow needs, maintain compliance with the financial covenants in our debt agreements or satisfy the waivers set forth in the amendments and waivers to our revolving credit facility as described above.

We have an interest payment due on November 15, 2015 on our Senior Notes, which have an aggregate principal balance outstanding of $600 million as of June 30, 2015.  Interest on the Senior Notes accrues at an annual rate of 9.75% and is payable semi-annually on May 15 and November 15.  We expect that the total interest payment due on November 15, 2015 will be approximately $30 million, of which we had accrued $7.5 million as of June 30, 2015.

On March 13, 2015 we filed a universal shelf Form S-3 Registration Statement, which was declared effective on April 22, 2015, to enable us to issue securities from time to time, including issuances of common stock in ATM offerings. Based on the current market price of our common stock and the amount of available authorized but unissued shares of our common stock, the proceeds from potential ATM offerings could provide substantial additional liquidity. As of June 30, 2015, the Company has sold an aggregate of 11,441,596 shares of its common stock and received aggregate proceeds of $21.8 million net of sales commissions and other fees of $0.6 million through its ATM offering under this Form S-3 Registration Statement. Subsequent to June 30, 2015, we sold an additional 7,720,495 shares of common stock for proceeds of $9.3 million net of sales commissions of $0.2 million.

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Liquidity Position

We define liquidity as funds available under our senior revolving credit facility plus cash and cash equivalents, excluding amounts held by our subsidiaries that are unrestricted subsidiaries under our senior revolving credit facility. The following table summarizes our liquidity position at June 30, 2015 compared to December 31, 2014:

	June 30, 2015			December 31, 2014
	(in thousands)
Borrowing base under MHR Senior Revolving Credit Facility	$	50,000		$	50,000
Cash and cash equivalents	8,818			53,180
Borrowings under MHR Senior Revolving Credit Facility	(5,000		)	—
Letters of credit issued	(38,961		)	(39,261		)
Liquidity	$	14,857		$	63,919

Sources of Cash

For the six months ended June 30, 2015, our primary sources of cash were cash flows from operating activities. The following table summarizes our sources and uses of cash for the periods noted:

	Six Months Ended June 30,
	2015			2014
	(In thousands)
Cash flows provided by operating activities	$	51,960		$	18,747
Cash flows used in investing activities	(99,704		)	(185,372		)
Cash flows provided by financing activities	3,358			133,991
Effect of foreign currency exchange rates	24			41
Net increase (decrease) in cash and cash equivalents	$	(44,362	)	$	(32,593	)

Operating Activities

Our cash provided by operating activities was $52.0 million for the six months ended June 30, 2015, compared to $18.7 million for the six months ended June 30, 2014, an increase of $33.3 million or 178%, primarily due to the increased available cash from changes in receivables and payables compared to the same period in 2014.

Investing Activities

Our cash used in investing activities for the six months ended June 30, 2015, was $99.7 million, principally from completion of new wells developed during 2014 in the Marcellus and Utica Shales which were turned to sales during 2015. This amount included the payment of expenditures previously accrued related to our 2014 capital expenditure program. Cash used in investing activities was partially offset by the cash proceeds from the sale of assets of $34.2 million.

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.

Financing Activities

Our cash used in financing activities for the six months ended June 30, 2015 was $3.4 million. Net proceeds from the sale of common stock under the ATM offering of $21.8 million and borrowings against our revolving credit facility of $5.0 million were partially offset by the payment of preferred dividends of $17.7 million and repayments of debt of $5.9 million during the six months ended June 30, 2015.

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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. Our then majority owned subsidiary, Eureka Hunter Pipeline, paid in full and terminated its term loan with Pennant Park and borrowed $65.0 million from the Eureka Hunter Pipeline Credit Agreement executed in March 2014. 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 financing costs on loans of $6.0 million during the six months ended June 30, 2014.

2015 Capital Expenditures

The following table summarizes our actual capital expenditures for the six months ended June 30, 2015 and our capital budget for 2015. 

	Capital Expenditures Incurred (1)		Capital Expenditure Budget
	Six Months Ended June 30, 2015		For the Year ending December 31, 2015
	(In thousands)
Exploration and Development Drilling Programs
Marcellus and Utica Shales	$	26,000	$	70,000
Williston Basin/Bakken Shale	13,000		10,000
Leasehold Acreage Acquisition
Marcellus and Utica Shales	21,000		20,000
Total capital expenditures	$	60,000	$	100,000

________________________________

⁽¹⁾  Capital expenditures on other property, plant, and equipment of approximately $2.7 million are not included in the summary above. Amounts represent capital expenditures incurred during the six months ended June 30, 2015. Cash paid for capital expenditures of $136.6 million during the six months ended June 20, 2015 includes payment of capital expenditures incurred during 2014.

Our capital expenditures of $62.7 million during the first half of 2015, of which $13.5 million were incurred during the second quarter, decreased from the comparable periods in 2014 as we reduced our upstream capital expenditures budget for 2015 due to the current commodity price environment.

Our capital expenditure budget for the remainder of 2015 may be reduced or increased depending on realized prices for our natural gas, natural gas liquids and oil, investment opportunities, continued effective implementation of cost reduction initiatives, including reduction of oil and gas field service costs, and funding allocations. Our upstream capital expenditure budget is also subject to change based on a number of other factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for natural gas and oil, the results of our exploration and development 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 new drilling locations.

Amendments to MHR Senior Revolving Credit Facility

On and effective as of May 28, 2015 and June 19, 2015, the Company entered into the Third and Fourth Amendment, respectively, to Credit Agreement and Limited Consent (the "Third Amendment" and the "Fourth Amendment", respectively) by and among the Company, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto. The Third Amendment amended the Credit Agreement to extend the amount of time the Company and its Restricted Subsidiaries may have accounts payable outstanding after the invoice date from 90 days to 180 days until June 19, 2015, after which the amount of time would have reverted back to 90 days. The Third Amendment also removed the condition, contained in a previous amendment, on the Company's ability to pay cash dividends on its three outstanding series of preferred stock for the month of May 2015.

In addition, pursuant to the Third Amendment, the lenders agreed to extend the deadline for Magnum Hunter to satisfy the Company's obligation to have received at least $65.0 million of aggregate net cash proceeds from one or more specified transactions by a certain date (the "Waiver Condition"), as provided in a previous amendment, from May 29, 2015 to June 19, 2015.

The Fourth Amendment amended the Credit Agreement to extend the amount of time the Company and its Restricted Subsidiaries may have accounts payable outstanding after the invoice date from 90 days to 180 days until July 10, 2015. In addition, pursuant

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to the Fourth Amendment, the lenders agreed to extend the deadline for Magnum Hunter to satisfy the Waiver Condition from June 19, 2015 to July 10, 2015.

On and effective as of July 10, 2015, the Company entered into the Fifth Amendment to Credit Agreement and Limited Waiver (the "Fifth Amendment") by and among the Company, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto. The Fifth Amendment amended the Credit Agreement to:

i. Permanently eliminate the Company's obligation to raise $65.0 million in net cash proceeds from one or more of the issuance by the Company of equity securities, permitted asset sales by the Company or any Restricted Subsidiary or the entry into a joint venture by the Company or any Restricted Subsidiary (including the receipt of upfront payments therefrom);

ii. Extend the amount of time the Company and its Restricted Subsidiaries may have accounts payable outstanding after the invoice date from 90 days to 180 days for any day on or prior to the earlier of (a) December 31, 2015 or (b) the date that is ten business days following the date on which the Company consummates the sale of all or substantially all of the Company's equity ownership interest in Eureka Hunter Holdings (the date of such sale, the "Trigger Date"), after which earlier date the restriction will revert back to 90 days; and

iii. Permit certain lenders to sell and assign their rights and obligations under the Credit Agreement to the Bank of Montreal.

In addition, the Fifth Amendment includes a waiver of compliance by the Company with the current ratio and leverage ratio covenants for the fiscal quarter ended June 30, 2015 (which covenants, prior to the waiver, required a current ratio of not less than 1.0 to 1.0 and a leverage ratio of not more than 2.5 to 1.0) and for each fiscal quarter ending thereafter until the earlier of (i) the fiscal quarter ending December 31, 2015 or (ii) the fiscal quarter in which the Trigger Date occurs, at which time the waiver of these financial covenants will no longer be in effect commencing with the earlier of the fiscal quarters referred to in clauses (i) and (ii) of this sentence. Upon expiration of the waiver of these financial covenants, the Company will be required to maintain (i) a current ratio of not less than 1.0 to 1.0 for the fiscal quarter during which the waiver expired and each quarter ending thereafter and (ii) a leverage ratio of not more than (a) 2.5 to 1.0 for the fiscal quarters ending September 30, 2015 (if the Trigger Date occurs during such fiscal quarter) and December 31, 2015 and (b) 2.0 to 1.0 for the fiscal quarter ending March 31, 2016 and for each fiscal quarter ending thereafter.

We believe that these waivers and modifications to our financial covenant ratios together with the successful execution of certain contemplated asset sales and other transactions will enable us to maintain compliance with such ratios for the next twelve months.

Additional Letter Agreement with Eureka Hunter Holdings and MSI

On March 30, 2015, the Company entered into a letter agreement (the "March 2015 Letter Agreement") with Eureka Hunter Holdings and MSIP II Buffalo Holdings, LLC ("MSI"), an affiliate of Morgan Stanley Infrastructure II Inc. Pursuant to the March 2015 Letter Agreement, the parties agreed, among other things, that MSI would make a capital contribution in cash to Eureka Hunter Holdings of approximately $37.8 million (the "Additional Contribution") by no later than March 31, 2015 (and it subsequently did make such capital contribution), in exchange for additional Series A-2 Units in Eureka Hunter Holdings, which Additional Contribution was used to fund certain additional capital expenditures of Eureka Hunter Pipeline and for certain other uses.

Pursuant to the March 2015 Letter Agreement, the parties further agreed that the Company has the right, in its discretion, to fund as a capital contribution to Eureka Hunter Holdings, all or a portion (in specified minimum amounts) of its pro rata share of the Additional Contribution, which pro rata share equals approximately $18.7 million (the "MHR Additional Contribution Component"), in exchange for additional Series A-1 Units in Eureka Hunter Holdings at a specified price per unit. The March 2015 Letter Agreement specified that the Company's deadline for funding the MHR Additional Contribution Component was June 30, 2015 (the "MHR Contribution Deadline").

On July 27, 2015, the Company entered into an additional letter agreement (the "July 2015 Letter Agreement") with Eureka Hunter Holdings and MSI, effective as of June 30, 2015, pursuant to which the parties agreed, subject to certain conditions, to extend the MHR Contribution Deadline to the earlier of (i) September 30, 2015 or (ii) the day immediately preceding the date on which the Company disposes, in a sale transaction or otherwise, its equity ownership interest in Eureka Hunter Holdings.

If the Company funds the full MHR Additional Contribution Component on or prior to the MHR Contribution Deadline, (but excluding any other capital contributions that may be made by the Company or MSI pursuant to the LLC Agreement), the Company and MSI will own 46.44% and 52.11%, respectively, of the Class A Common Units of Eureka Hunter Holdings.

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If the Company does not fund the full MHR Additional Contribution Component by the MHR Contribution Deadline, as amended by the July 2015 Letter Agreement, the Company's Series A-1 Units in Eureka Hunter Holdings will be adjusted downward. If the Company does not fund any of the MHR Additional Contribution Component on or prior to the MHR Contribution Deadline, the Company and MSI will own 44.53% and 53.98%, respectively, of the Class A Common Units of Eureka Hunter Holdings. If the Company does not fund all or a portion of the MHR Additional Contribution, a downward adjustment of its capital account, as described above, could result in the Company recognizing a loss on its investment in Eureka Hunter Holdings. If the Company funds a portion (in specified minimum amounts), but not all of the MHR Additional Contribution Component, on or prior to the MHR Contribution Deadline, then the ownership percentages of the Company and MSI will be adjusted in a manner consistent with the first sentence of this paragraph but with the downward adjustment for the Company being proportionally reduced.

Oil, Natural Gas, and NGLs Prices

During the fourth quarter of 2014 and through the date of this report, spot and future market prices for oil and natural gas experienced significant declines as markets reacted to macroeconomic factors related to, among others, oil supplies and increased production in the United States, the rate of economic growth domestically and internationally, and the oil production outlook provided by the Organization of Petroleum Exporting Countries. In addition, the basis differential in Appalachia has widened against NYMEX natural gas prices for the same period during 2014. If prices continue to decline as a result of increased supply and volumes of natural gas in storage 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.

Our realized prices for oil, gas, and NGLs continue to be adversely affected by market conditions. Our average quarterly realized price for oil for the three months ended June 30, 2015 declined $44.82, or 46.1% from the comparable period in 2014. Average quarterly prices for natural gas and NGLs experienced larger price declines of 67.4% and 70.4%, respectively. The declines in our realized prices are the result of overall declines in commodity markets in the United States and the effects of regional pricing differentials in the Williston and Appalachian Basins. The table below shows the impact that volatility in the oil and natural gas markets has had on our realized prices over the past five quarters.

	Average Prices (U.S. Dollars)
	Three Months Ended
	June 30, 2014		September 30, 2014		December 31, 2014		March 31, 2015		June 30, 2015
Oil (per Bbl)	$	97.13	$	90.55	$	58.79	$	30.16	$	52.31
Natural gas (per Mcf)	$	5.13	$	3.43	$	2.87	$	2.91	$	1.67
NGLs (per Bbl)	$	55.71	$	41.29	$	38.05	$	25.48	$	16.51

Results of Operations

The following table sets forth summary information from continuing operations regarding oil, natural gas and NGLs revenues, production, average product prices and average production costs and expenses for the three and six months ended June 30, 2015 and 2014, respectively. The results of our Canadian operations and the operations of Eureka Hunter Holdings have been excluded from the amounts below because they are reflected as discontinued operations for all periods presented.

Certain prior-year balances have been reclassified to correspond with current-year presentation. As a result of the Company's decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented.

Also, for all periods presented, we have separately classified transportation and processing expenses incurred to deliver gas to processing plants and to selling points, which were previously included as components of lease operating expenses and severance taxes and marketing. The Company has renamed lease operating expenses as "Production costs" and presented transportation and processing expenses as "Transportation, processing, and other related costs" in order to provide more meaningful information on costs associated with production and development.

As we continue to focus on the exploration, development and production of natural gas and natural gas liquids in the Appalachian Basin of West Virginia and Ohio, we have presented total production volumes for all periods in terms of Mcfe rather than Boe as previously presented.

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	Three Months Ended   June 30,				Six Months Ended   June 30,
	2015		2014		2015		2014
Oil and natural gas revenue and production
Revenues (in thousands, U.S. Dollars)
Oil	$	15,087	$	41,506	$	24,631	$	76,859
Natural gas	13,023		28,264		44,883		55,784
NGLs	5,308		14,002		13,295		27,094
Total oil and natural gas sales	$	33,418	$	83,772	$	82,809	$	159,737
Production
Oil (MBbl)	288		427		605		853
Natural gas (MMcf)	7,809		5,506		18,752		10,455
NGLs (MBbl)	322		251		635		480
Total (MMcfe)	11,469		9,578		26,190		18,452
Mcfe/d	126,034		105,254		144,698		101,944
Average prices (U.S. Dollars)
Oil (per Bbl)	$	52.31	$	97.13	$	40.73	$	90.15
Natural gas (per Mcf)	$	1.67	$	5.13	$	2.39	$	5.34
NGLs (per Bbl)	$	16.51	$	55.71	$	20.94	$	56.42
Total average price (per Mcfe)	$	2.91	$	8.75	$	3.16	$	8.66
Costs and expenses (per Mcfe)
Production costs	$	0.82	$	1.06	$	0.88	$	1.26
Severance tax and marketing	$	0.15	$	0.60	$	0.17	$	0.58
Transportation, processing, and other related costs	$	0.93	$	0.71	$	1.18	$	1.02
Exploration	$	0.13	$	0.96	$	0.38	$	1.36
Impairment of proved oil and natural gas property	$	0.01	$	0.02	$	0.53	$	0.92
Depletion, depreciation and accretion	$	1.95	$	3.34	$	3.06	$	3.13
General and administrative expense (1)	$	0.98	$	1.96	$	0.92	$	1.78
Other segments (in thousands)
Midstream natural gas gathering, processing and marketing revenues	$	472	$	39,646	$	930	$	65,757
Midstream natural gas gathering, processing and marketing expenses	$	184	$	38,536	$	678	$	65,432
Oilfield services revenues	$	5,393	$	5,954	$	10,258	$	11,575
Oilfield services expenses	$	4,678	$	4,089	$	8,889	$	8,036

_________________________________

⁽¹⁾  General and administrative expense includes: (i) professional services expenses of $3.0 million ($0.26 per Mcfe) for the three months ended June 30, 2015 and $7.2 million ($0.76 per Mcfe) for the three months ended June 30, 2014, (ii) professional services expenses of $7.5 million ($0.29 per Mcfe) for the six months ended June 30, 2015 and $14.2 million ($0.77 per Mcfe) the six months ended June 30, 2014, (iii) non-cash stock compensation of $1.7 million ($0.14 per Mcfe) for the three months ended June 30, 2015 and $2.3 million ($0.24 per Mcfe) for the three months ended June 30, 2014, and (iv) non-cash stock compensation of $4.8 million ($0.18 per Mcfe) for the six months ended June 30, 2015 and $3.4 million ($0.18 per Mcfe) for the six months ended June 30, 2014.

Three Months Ended June 30, 2015 and 2014

Oil and natural gas production. Production increased by 19.7%, or 1,891 MMcfe, to 11,469 MMcfe for the three months endedJune 30, 2015 compared to 9,578 MMcfe for the three months endedJune 30, 2014. Our average daily production was 126,034 Mcfe/d during the 2015 period, representing an overall increase of 19.7%, or 20,780 Mcfe/d, compared to 105,254 Mcfe/d for the 2014 period. Natural gas production from the Appalachian Basin alone increased from 5,378 MMcf for the three months ended June 30, 2014 to 7,724 MMcf for the three months ended June 30, 2015; an increase of 43.6%. Production of natural gas and NGLs increased in the current quarter as a result of new Marcellus Shale and Utica Shale wells that began producing from the Everett Weese, Stewart Winland, WVDNR, and Stalder pads. The increase in NGL production in 2015 results from our Marcellus wells, which generally have a high liquid content.

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Oil production for the three months endedJune 30, 2015 was 288 MBbl versus 427 MBbl for the three months endedJune 30, 2014, a decrease of 32.5%. Production of oil declined in 2015 as the result of our divestiture of non-core properties in the Williston Basin. Production from the Williston Basin decreased 29.1%, from 308 MBbl in oil production during the three months endedJune 30, 2014 to 218 MBbl during the three months endedJune 30, 2015.

Total production for the three months ended June 30, 2015, on an Mcfe basis, was 15.1% oil, 68.1% natural gas, and 16.8% NGLs compared to 26.8% oil, 57.5% natural gas, and 15.7% NGLs for the same period in 2014.

Oil and natural gas sales. Oil and natural gas sales decreased60.1%, or $50.4 million, for the three months endedJune 30, 2015 to $33.4 million from $83.8 million for the three months endedJune 30, 2014. The decrease in oil and natural gas sales primarily resulted from decreases in prices received, partially offset by higher production volumes from our Marcellus Shale and Utica Shale wells. Our total sales prices were impacted by declines in prices received for oil, natural gas, and NGLs of 46.1%, 67.4% and 70.4%, respectively. Our average realized natural gas price for the three months ended June 30, 2015 was $1.67 per Mcf, a $1.06 per Mcf negative differential to the average NYMEX price for the period. Our average realized oil price for the three months ended June 30, 2015 was $52.31 per barrel, an $7.51 per barrel negative differential to the average WTI price for the period. Of the total decrease in oil and natural gas sales for the 2015 period, $52.5 million was attributable to decreases in prices received and was offset by an increase in production of $2.1 million.

Midstream natural gas gathering, processing and marketing revenues. Revenue from midstream operations decreased by $39.2 million, or 98.8%, for the three months endedJune 30, 2015 to $0.5 million from $39.6 million for the three months endedJune 30, 2014, primarily due to the decision made by a third party customer to begin marketing their own natural gas, which had previously been marketed by our subsidiary, Magnum Hunter Marketing, on this customer's behalf.

Oilfield services revenue. Drilling services revenue decreased by 9.4%, or $0.6 million, for the three months endedJune 30, 2015 to $5.4 million from $6.0 million for the three months endedJune 30, 2014. During the three months endedJune 30, 2015, our drilling rig revenue days increased from 355 to 431 as compared to the three months endedJune 30, 2014. For the three months endedJune 30, 2015, the total effective equipment performance of our drilling rigs was 75%, and our rigs were 77% utilized.

Gain (loss) on sale of assets. We recorded a gain on sale of assets in operating expenses of $26.7 million for the three months endedJune 30, 2015, primarily related to the sale of certain undeveloped and unproven leasehold acreage in Tyler County, West Virginia. Gain on sale of assets of $0.7 million for the three months endedJune 30, 2014 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.

Production costs. Our production costs decreased$0.8 million, or 8.2%, for the three months endedJune 30, 2015 to $9.4 million ($0.82 per Mcfe) from $10.2 million ($1.06 per Mcfe) for the three months endedJune 30, 2014. The fluctuation in production costs was comprised of an increase of $2.0 million attributable to increased production volumes, offset by a decrease of $2.8 million attributable to lower costs/Mcfe. Of the decrease in costs/Mcfe, $4.8 million and $0.4 million was due to lower recurring costs in the Appalachian and Williston Basins, respectively, partially offset by a $2.4 million increase in non-recurring workover expenses. The increase in non-recurring workover expenses is comprised of a $3.7 million increase in the Appalachian Basin, offset by a $1.3 million decrease in the Williston Basin for the three months endedJune 30, 2015 as compared to the three months endedJune 30, 2014.

Severance taxes and marketing.  Our severance taxes and marketing decreased$4.0 million, or 69.3%, for the three months endedJune 30, 2015, to $1.8 million from $5.7 million for the three months endedJune 30, 2014.  The decrease in severance taxes and marketing was attributable primarily to the decrease in our sales.  

Transportation, processing, and other related costs. Our transportation, processing, and other related costs increased by $3.8 million, or 55.4%, the three months endedJune 30, 2015 to $10.6 million ($0.93 per Mcfe) from $6.8 million ($0.71 per Mcfe) the three months endedJune 30, 2014. Of these amounts, approximately $3.7 million and $2.5 million, respectively, related to reservation fees for the three months ended June 30, 2015 and 2014. The increase in transportation, processing, and other related costs was attributable primarily to increased natural gas and NGL production from our Appalachian properties as additional wells began producing during 2015.

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Exploration.We recognize exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. Leasehold impairments relate to leases that expired undrilled or are expected to expire and that the Company does not plan to develop. We recorded $1.5 million of exploration expense for the three months endedJune 30, 2015, compared to $9.2 million for the three months endedJune 30, 2014 as reflected in the following table:

	Three Months Ended   June 30,
	2015		2014
	(in thousands)
Leasehold impairments:
Williston Basin	$	—	$	8,834
Appalachian Basin	931		(1		)
Leasehold impairments	931		8,833
Geological and geophysical costs	548		353
Total exploration expense	$	1,479	$	9,186

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

During the three months endedJune 30, 2015, we performed an impairment analysis and recorded impairment of proved oil and natural gas properties of $0.1 million to reduce the carrying value of these properties to their estimated fair values. During the three months endedJune 30, 2014, we recorded impairment of proved oil and natural gas properties of $0.2 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. The following table summarizes impairments of proved oil and natural gas properties for the periods indicated:

	Three Months Ended   June 30,
	2015		2014
	(in thousands)
Appalachian Basin	$	—	$	158
Western Kentucky	95		—
Total impairment of proved oil and gas properties	$	95	$	158

Midstream natural gas gathering, processing and marketing expenses. Expenses from the midstream operations decreased by $38.4 million, or 99.5%, for the three months endedJune 30, 2015 to $0.2 million from $38.5 million for the three months endedJune 30, 2014 due primarily to Magnum Hunter Marketing's decreased activities as a result of the decision made by a third party customer to begin marketing its own natural gas, which had previously been marketed by Magnum Hunter Marketing on this customer's behalf.

Oilfield services expenses.  Oilfield services expenses increased by $0.6 million, or 14.4%, to $4.7 million for the three months endedJune 30, 2015 from $4.1 million for the three months endedJune 30, 2014.

Depletion, depreciation, amortization, and accretion. Our depletion, depreciation, amortization and accretion expense ("DD&A"), decreased$9.7 million, or 30.3%, to $22.3 million for the three months endedJune 30, 2015, from $32.0 million for the three months endedJune 30, 2014. Our DD&A/Mcfe decreased by $1.39, or 41.6%, to $1.95 per Mcfe for the three months endedJune 30, 2015, compared to $3.34 per Mcfe for the three months endedJune 30, 2014. These decreases were primarily a result of our divestiture of non-core properties in the Williston Basin.

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General and administrative. Our general and administrative expenses ("G&A") decreased$7.5 million, or 40.0%, to $11.3 million or $0.98 per Mcfe for the three months endedJune 30, 2015 from $18.8 million or $1.96 per Mcfe for the three months endedJune 30, 2014. The decrease is primarily attributable to our efforts to further reduce G&A through the reduction of legal costs, reduction in reliance on outside consultants and temporary staffing, and the closing of our offices in Denver, Colorado and Calgary, Alberta, among other factors, as reflected in the following table:

	Three Months Ended   June 30,
	2015		2014		Decrease
	(in thousands)
Professional fees	$	3,005	$	7,236	$	(4,231	)
Salaries and personnel costs	3,858		4,822		(964		)
Non-cash stock compensation expense	1,653		2,314		(661		)
Other general and administrative expenses	2,741		4,404		(1,663		)
Total general and administrative expenses	$	11,257	$	18,776	$	(7,519	)

Interest expense, net. Our interest expense, net of interest income, increased by 21.3%, to $24.1 million from $19.8 million for the three months endedJune 30, 2015, compared to the three months endedJune 30, 2014. A higher average debt level during the second quarter of 2015 compared to the 2014 period accounted for $7.3 million of the increase, which was partially offset by a decrease of $3.0 million due to lower amortization and write-off of deferred financing costs.

Commodity and financial derivative activities. Our commodity and financial derivative activity resulted in a net loss of $0.3 million for the quarter ended June 30, 2015, compared to a net loss of $3.0 million for the quarter ended June 30, 2014. 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,
	2015			2014
	(in thousands)
Commodity derivatives
Realized loss on settled transactions	$	(1,117	)	$	(2,267	)
Unrealized gain (loss) on open contracts	815			(1,021		)
Total commodity derivatives	(302		)	(3,288		)
Financial derivatives
Unrealized gain (loss) on open contracts	(23		)	282
Net loss	$	(325	)	$	(3,006	)

We do not designate our derivative instruments as hedges.

At June 30, 2015, the Company has recognized an asset for an embedded derivative related to a convertible security, due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. An unrealized loss of $23,000 and an unrealized gain of $282,000 are recorded for this embedded derivative instrument in the three months endedJune 30, 2015 and 2014, respectively. This derivative instrument originated in 2012 and has resulted in no cash outlays as of June 30, 2015.

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, 2015 and 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, 2015 or 2014 net loss.

Income (loss) from discontinued operations, net of tax. In September 2013, the Company adopted a plan to divest all of its interests in WHI Canada. The Company has reclassified the associated assets and liabilities to assets and liabilities held for sale and the

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operations are reflected as discontinued operations for all periods presented. The Company closed on the sale of its interests in WHI Canada during the second quarter of 2014.

In June 2015, the Company adopted a plan to divest of its entire equity ownership interest in Eureka Hunter Holdings. Prior to December 18, 2014, Eureka Hunter Holdings was a consolidated subsidiary of the Company and its operations were included in the Midstream and Marketing operating segment. Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company determined it no longer held a controlling financial interest in Eureka Hunter Holdings. However, the Company exercises significant influence through its retained equity interest and through representation on Eureka Hunter Holdings' board of managers. As a result, the Company uses the equity method to account for its retained interest in Eureka Hunter Holdings. The Company has reclassified its equity method investment in Eureka Hunter Holdings to assets of discontinued operations for all periods presented. All operations related to periods prior to December 18, 2014, and all subsequent equity method losses, are reflected as discontinued operations.

We recognized loss from discontinued operations of $1.6 million for the three months endedJune 30, 2015, compared to loss of $42.5 million for the three months endedJune 30, 2014. The following table summarizes the loss from discontinued operations for the periods indicated:

	Three months ended June 30,
	2015			2014
	(in thousands)
Eureka Hunter Holdings	(1,594		)	(43,716		)
Williston Hunter Canada	—			1,192
	$	(1,594	)	$	(42,524	)

Gain (loss) on disposal of discontinued operations, net of tax. We recognized no gain or loss on disposal of discontinued operations for the three months endedJune 30, 2015 compared to a loss on disposal of discontinued operations of $5.2 million for the three months endedJune 30, 2014, respectively. The following table summarizes the loss on disposal of discontinued operations for the period indicated:

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

Net loss attributable to non-controlling interest.  Net loss attributable to non-controlling interest of $0.8 million for the three months endedJune 30, 2014 represented 1.7% of the net income or loss incurred by our then majority-owned subsidiary, Eureka Hunter Holdings, and 12.5% of the net income or loss incurred by our subsidiary, PRC Williston. 

Prior to July 24, 2014, we owned 87.5% of the equity interests in PRC Williston, LLC ("PRC Williston"), which sold substantially all of its assets on December 30, 2013. On July 24, 2014, we executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, we now own 100% of the equity interests in PRC Williston and have all rights and claims to its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston's equity reflected in the consolidated financial statements as of June 30, 2015.

As a result of the deconsolidation of Eureka Hunter Holdings in December 2014, we derecognized the non-controlling interests attributed to Eureka Hunter Holdings as part of the gain on deconsolidation recorded in the fourth quarter of 2014.

Dividends on preferred stock. Total dividends on our preferred stock were approximately $8.8 million for the three months endedJune 30, 2015 and for the three months endedJune 30, 2014. The Series C Preferred Stock had a stated value of $100.0 million at both June 30, 2015 and December 31, 2014, and carries a cumulative dividend rate of 10.25% per annum. The Series D Preferred Stock had a stated value of $221.2 million at both June 30, 2015 and December 31, 2014, and carries a cumulative dividend rate

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of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million at both June 30, 2015 and December 31, 2014, and carries a cumulative dividend rate of 8.0% per annum.

Dividends on preferred stock of discontinued operations. Total dividends on preferred stock of discontinued operations were approximately $6.5 million for the three months endedJune 30, 2014 and were related to the Eureka Hunter Holdings Series A Preferred Units. The Eureka Hunter Holdings Series A Units were converted into a new class of equity during the fourth quarter of 2014.

Six Months EndedJune 30, 2015 and 2014

Oil and natural gas production.  Production increased by 41.9%, or 7,738 MMcfe, to 26,190 MMcfe for the six months ended June 30, 2015, compared to 18,452 MMcfe for the six months ended June 30, 2014. Our average daily production was 144,698 Mcfe/d during the 2015 period, representing an overall increase of 41.9%, or 42,754 Mcfe/d, compared to 101,944 Mcfe/d for the 2014 period. Natural gas production from the Appalachian Basin alone increased from 10,186 MMcf for the six months ended June 30, 2014 to 18,591 MMcf for the six months ended June 30, 2015, an increase of 82.5%. Production of natural gas and NGLs increased during the 2015 period as a result of new Marcellus Shale and Utica Shale wells that began producing from the Everett Weese, Stewart Winland, WVDNR, and Stalder pads. The increase in NGLs production in 2015 results from our Marcellus wells, which have a high liquid content.

Oil production for the six months ended June 30, 2015 was 605 MBbl versus 853 MBbl for the six months ended June 30, 2014, a decrease of 29.1%. Production of oil declined in 2015 as a result of our divestiture of non-core properties in the Williston Basin. Production from the Williston Basin decreased 30.4%, from 629 MBbl in oil production during the six months ended June 30, 2014 to 438 MBbl during the six months ended June 30, 2015.

Total production for the six months ended June 30, 2015, on an Mcfe basis, was 13.9% oil, 71.6% natural gas, and 14.5% NGLs compared to 27.7% oil, 56.7% natural gas, and 15.6% NGLs for the same period in 2014. 

Oil and natural gas sales.  Oil and natural gas sales decreased$76.9 million, or 48.2% for the six months ended June 30, 2015, to $82.8 million from $159.7 million for the six months ended June 30, 2014.  The decrease in oil and natural gas sales primarily resulted from decreases in prices received, partially offset by higher production volumes from our Marcellus Shale and Utica Shale wells.  Our total sales prices were impacted by decreases in prices received for oil, natural gas, and NGLs of 54.8%, 55.3%, and 62.9%, respectively. Our average realized natural gas price for six months ended June 30, 2015 was $2.39 per Mcf, a $0.41 negative differential to the average NYMEX price for the period. Our average realized oil price for the six months ended June 30, 2015, was $40.73 per barrel, a $16.56 per barrel negative differential to the average WTI price for the period. Of the total decrease in oil and natural gas sales for the 2015 period, $107.7 million was attributable to decreases in prices received and was offset by an increase in production of $30.8 million. 

Midstream natural gas gathering, processing and marketing revenues.  Revenue from the midstream operations segment decreased by $64.8 million, or 98.6%, for the six months ended June 30, 2015 to $0.9 million from $65.8 million for the six months ended June 30, 2014, primarily due to the decision made by a third party customer to begin marketing its own natural gas, which had previously been marketed by Magnum Hunter Marketing on this customer's behalf.

Oilfield services revenue.  Drilling services revenue decreased by $1.3 million, or 11.4%, for the six months ended June 30, 2015 to $10.3 million from $11.6 million for the six months ended June 30, 2014. This decrease was primarily attributable to lower utilization of the fleet of rigs caused by the downturn in commodity prices. During the six months ended June 30, 2015, our drilling rig revenue days decreased from 818 to 816 as compared to the six months ended June 30, 2014. For the six months ended June 30, 2015, the total effective equipment performance of our drilling rigs was 72%, and our rigs were 75% utilized.

Gain (loss) on sale of assets.  We recorded a net gain on sale of assets in operating expenses of $28.4 million for the six months ended June 30, 2015, compared to a net loss on sale of assets of $3.4 million for the six months ended June 30, 2014. The gain on sale of assets during the six months ended June 30, 2015 relates primarily to the sale of certain undeveloped and unproven leasehold acreage in Tyler County, West Virginia, as well as post-closing adjustments related to the sales of certain North Dakota oil and natural gas properties during the latter part of 2014. Of the total net loss on sale of assets recorded during the six months ended June 30, 2014, $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.

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Production costs.  Our production costs decreased less than $0.1 million, or 0.4% for the six months ended June 30, 2015 compared to the six months ended June 30, 2014. Production costs per Mcfe decreased to $0.88 per Mcfe for the six months ended June 30, 2015 from $1.26 per Mcfe for the six months ended June 30, 2014.  The decrease in production costs was comprised of $9.8 million attributable to lower costs/Mcfe, offset by $9.7 million attributable to increased production volumes. Of the decrease in costs/Mcfe, $4.4 million and $4.8 million was due to lower recurring costs in the Appalachian Basin and Williston Basin, respectively, and $0.6 million was due to lower non-recurring workover expenses. The decrease in non-recurring workover expenses is comprised of a $4.1 million decrease in the Williston Basin, partially offset by a $3.5 million increase in the Appalachian Basin for the six months ended June 30, 2015 as compared to the six months ended June 30, 2014.

Severance taxes and marketing.  Our severance taxes and marketing decreased$6.1 million, or 57.2%, for the six months ended June 30, 2015, to $4.6 million from $10.7 million for the six months ended June 30, 2014.  The decrease in severance taxes was attributable primarily to the decrease in our sales.  

Transportation, processing, and other related costs. Our transportation, processing, and other related costs increased by $12.1 million, or 64.1%, for the six months ended June 30, 2015 to $31.0 million ($1.18 per Mcfe) from $18.9 million ($1.02 per Mcfe) for the six months ended June 30, 2014. Of these amounts, approximately $7.4 million and $4.7 million, respectively, related to reservation fees for the six months ended June 30, 2015 and 2014. The increase in transportation, processing, and other related costs was attributable primarily to increased natural gas and NGLs production from our Appalachian properties as additional wells began producing during 2015.

Exploration.  We recognize exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. Leasehold impairments relate to leases that expired undrilled or are expected to expire and that the Company does not plan to develop. We recorded $10.0 million of exploration expense for the six months ended June 30, 2015, compared to $25.1 million for the six months ended June 30, 2014, as reflected in the following table: 

	Six Months Ended   June 30,
	2015		2014
	(in thousands)
Leasehold impairments:
Williston Basin	$	7,606	$	19,919
Appalachian Basin	1,163		4,464
Leasehold impairments	8,769		24,383
Geological and geophysical costs	1,200		727
Total exploration expense	$	9,969	$	25,110

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

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During the six months ended June 30, 2015, we performed an impairment analysis and recorded impairment of proved oil and natural gas properties of $13.9 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. During the six months ended June 30, 2014, we recorded impairments on our proved oil and natural gas properties of $16.9 million, primarily in order to reduce the carrying value of properties owned by MHP to their estimated fair values, based upon developments in our marketing activities relating to MHP. The following table summarizes impairments of proved oil and natural gas properties for the periods indicated:

	Six Months Ended   June 30,
	2015		2014
	(in thousands)
Appalachian Basin	$	10,944	$	158
Western Kentucky	2,950		16,754
South Texas	55		—
Total impairment of proved oil and gas properties	$	13,949	$	16,912

Midstream natural gas gathering, processing and marketing expenses. Expenses from the midstream operations decreased by $64.8 million, or 99.0% for the six months ended June 30, 2015, to $0.7 million from $65.4 million for the six months ended June 30, 2014 primarily due to Magnum Hunter Marketing's decreased activities as a result of the decision made by a third party customer to begin marketing its own natural gas, which had previously been marketed by Magnum Hunter Marketing on this customer's behalf.

Oilfield services expenses.  Oilfield services expenses increased$0.9 million or 10.6% to $8.9 million for the six months ended June 30, 2015 from $8.0 million for the six months ended June 30, 2014. 

Depletion, depreciation, amortization, and accretion. Our DD&A increased$22.3 million, or 38.6%, to $80.1 million for the six months ended June 30, 2015, from $57.8 million for the six months ended June 30, 2014. Approximately $35.1 million of the increase between the comparable periods is due to increases in proved reserves in the Appalachian Basin and increased production in 2015, offset by decreases of approximately $13.0 million related to our divestiture of non-core properties in the Williston Basin during the second quarter of 2014. Our DD&A/Mcfe decreased by $0.07, or 2.2%, to $3.06 per Mcfe for the six months ended June 30, 2015, compared to $3.13 per Mcfe for the six months ended June 30, 2014 due to increased natural gas production. Natural gas wells generally have a lower rate on an Mcfe basis than oil and NGLs.

General and administrative.  Our G&A decreased$8.7 million, or 26.7%, to $24.0 million ($0.92 per Mcfe) for the six months ended June 30, 2015, from $32.8 million ($1.78 per Mcfe) for the six months ended June 30, 2014.  The decrease is primarily attributable to our efforts to further reduce general and administrative expenses through the reduction of legal costs, reduction in reliance on outside consultants and temporary staffing, and the closing of our offices in Denver, Colorado and Calgary, Alberta, among other factors, as reflected in the following table:

	Six Months Ended   June 30,
	2015		2014		Increase (Decrease)
	(in thousands)
Professional fees	$	7,493	$	14,201	$	(6,708	)
Salaries and personnel costs	5,820		8,602		(2,782		)
Non-cash stock compensation expense	4,837		3,375		1,462
Other general and administrative expenses	5,879		6,592		(713		)
Total general and administrative expenses	$	24,029	$	32,770	$	(8,741	)

Interest expense, net.  Our interest expense, net of interest income, increased by 25.6%, to $47.5 million for the six months ended June 30, 2015, from $37.8 million for the six months ended June 30, 2014.  Our higher average debt level accounted for an increase of $12.8 million, offset by lower amortization and write-off of deferred financing costs which accounted for a decrease of $3.1 million in the six months ended June 30, 2015 compared to the same period in 2014.

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Commodity and financial derivative activities.  Our commodity and financial derivative activity resulted in a net gain of $2.8 million for the six month period ended June 30, 2015 compared to a net loss of $8.6 million for the six month period ended June 30, 2014. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:

	Six Months Ended   June 30,
	2015			2014
	(in thousands)
Commodity derivatives
Realized gain (loss) on settled transactions	$	3,194		$	(4,551	)
Unrealized loss on open contracts	(369		)	(4,282		)
Total commodity derivatives	2,825			(8,833		)
Financial derivatives
Gain (loss) on embedded derivatives	(48		)	238
Net gain (loss)	$	2,777		$	(8,595	)

We do not designate our derivative instruments as hedges.

At June 30, 2015, the Company has recognized an asset for an embedded derivative related to a convertible security, due to the conversion feature of the promissory note received as partial consideration for the sale of Hunter Disposal. An unrealized loss of $48,000 and an unrealized gain of $238,000 are recorded for this embedded derivative instrument in the six months ended June 30, 2015 and 2014, respectively. This derivative instrument originated in 2012 and has resulted in no cash outlays as of June 30, 2015.

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, 2015 and 2014, and have a full valuation allowance on all deferred tax assets. As a result, we did not recognize a tax benefit on our June 30, 2015 or 2014 net loss.

Gain on dilution of interest in Eureka Hunter Holdings. On March 30, 2015, the Company, Eureka Hunter Holdings and MSI entered into the March 2015 Letter Agreement, pursuant to which the parties agreed that, among other things, MSI purchased additional Class A Common Units of Eureka Hunter Holdings. The Company recognized a pre-tax gain of $2.4 million based on the difference between the carrying value of the Company's Series A-1 Units and the proceeds received by Eureka Hunter Holdings for the issuance of additional Series A-2 Units to MSI which resulted in permanent dilution of the Company's equity interest in Eureka Hunter Holdings. The gain included the Company's equity method basis difference which was proportionally reduced by $3.9 million based on the change in the Company's ownership in the net assets of Eureka Hunter Holdings after giving effect to the dilution of the Company's interest as a result of the share issuance.

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

In June 2015, the Company adopted a plan to divest of its entire equity ownership interest in Eureka Hunter Holdings. Prior to December 18, 2014, Eureka Hunter Holdings was a consolidated subsidiary of the Company and its operations were included in the Midstream and Marketing operating segment. Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company determined it no longer held a controlling financial interest in Eureka Hunter Holdings. However, the Company exercises significant influence through its retained equity interest and through representation on Eureka Hunter Holdings' board of managers. As a result, the Company uses the equity method to account for its retained interest in Eureka Hunter Holdings. The Company has reclassified its equity method investment in Eureka Hunter Holdings to assets of discontinued operations for all periods presented. All operations related to periods prior to December 18, 2014, and all subsequent equity method losses, are reflected as discontinued operations.

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The Company recognized a loss from discontinued operations of $4.3 million for the six months ended June 30, 2015, compared to loss of $42.4 million for the six months ended June 30, 2014. The following table summarizes the income from discontinued operations for the period indicated:

	Six Months Ended June 30,
	2015			2014
	(in thousands)
Eureka Hunter Holdings	(4,263		)	(46,934		)
Williston Hunter Canada	—			4,561
	$	(4,263	)	$	(42,373	)

Gain (loss) on disposal of discontinued operations, net of tax. The Company recognized no gain or loss on disposal of discontinued operations for the six months ended June 30, 2015 compared to a loss on disposal of discontinued operations of $13.7 million for the six months ended June 30, 2014. The following table summarizes the loss on disposal of discontinued operations for the period indicated:

	Six Months Ended   June 30,
	2014
	(in thousands)
Eagle Ford Hunter	$	(7,024	)
Williston Hunter Canada	(6,701		)
	$	(13,725	)

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

Prior to July 24, 2014, we owned 87.5% of the equity interests in PRC Williston, LLC ("PRC Williston"), which sold substantially all of its assets on December 30, 2013. On July 24, 2014, we executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, we now own 100% of the equity interests in PRC Williston and have all rights and claims to its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston's equity reflected in the consolidated financial statements as of June 30, 2015.

As a result of the deconsolidation of Eureka Hunter Holdings in December 2014, we derecognized the non-controlling interests attributed to Eureka Hunter Holdings as part of the gain on deconsolidation recorded in the fourth quarter of 2014.

Dividends on preferred stock.  Total dividends on our preferred stock were approximately $17.7 million for the six months ended June 30, 2015, and $17.7 million for the six months ended June 30, 2014. The Series C Preferred Stock had a stated value of $100.0 million at both June 30, 2015 and December 31, 2014, and carries a cumulative dividend rate of 10.25% per annum.  The Series D Preferred Stock had a stated value of $221.2 million at both June 30, 2015 and December 31, 2014, and carries a cumulative dividend rate of 8.0% per annum. The Series E Preferred Stock had a stated value of $95.1 million at both June 30, 2015 and December 31, 2014, and carries a cumulative dividend rate of 8.0% per annum.

Dividends on preferred stock of discontinued operations. Total dividends on preferred stock of discontinued operations were approximately $12.6 million for the six months ended June 30, 2014 and were related to the Eureka Hunter Holdings Series A Preferred Units. The Eureka Hunter Holdings Series A Units were converted into a new class of equity during the fourth quarter of 2014.

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Related Party Transactions

The following table sets forth the related party transaction activities for the three and six months ended June 30, 2015 and 2014, respectively:

		Three Months Ended   June 30,				Six Months Ended   June 30,
		2015		2014		2015			2014
		(in thousands)
GreenHunter
	Production costs (1)	$	1,288	$	632	$	2,199		$	1,076
	Midstream natural gas gathering, processing, and marketing	$	—	$	400	$	—		$	400
	Oilfield services (1)	$	71	$	—	$	104		$	—
	General and administrative (1)	$	6	$	13	$	12		$	36
	Interest income (2)	$	39	$	38	$	70		$	83
	Miscellaneous income (2)	$	55	$	55	$	110		$	110
	Loss from equity method investment (2)	$	87	$	135	$	318		$	357
	Capitalized costs incurred (1)	$	19	$	1,192	$	465		$	1,810
Pilatus Hunter, LLC (4)
	General and administrative	$	25	$	88	$	36		$	158
Eureka Hunter Holdings (3)
	Production costs	$	478	$	—	$	596		$	—
	Transportation, processing, and other related costs	$	4,973	$	—	$	10,714		$	—
	Oilfield Services	$	13	$	—	$	16		$	—
	General and administrative	$	—	$	—	$	(5	)	$	—
	Capitalized costs incurred	$	—	$	—	$	121		$	—
Classic Petroleum (5)
	Capitalized costs incurred	$	23	$	212	$	185		$	524

__________________________________

(1) GreenHunter is an entity of which Gary C. Evans, our Chairman and CEO, is the Chairman and a major shareholder. 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 certain affiliated companies. 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. The fair market value of the derivative was $27,000, and $75,000 at June 30, 2015 and December 31, 2014, respectively.  See "Note 6 - 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 investment in affiliate - equity-method 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.

(4) Following a series of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. The Company deconsolidated Eureka Hunter Holdings and accounts for its retained interest under the equity method of accounting. See "Note 7 - Investments and Derivatives". As discussed in "Note 2 - Acquisitions, Divestitures, and Discontinued Operations", in June 2015 the Company adopted a plan to dispose of its equity method investment in Eureka Hunter Holdings, and has classified the related operations as discontinued operations and the investment as assets of discontinued operations for all periods presented.

(5) Classic Petroleum, Inc. is an entity owned by the brother of James W. Denny, III, the Company's Executive Vice President and President of the Company's Appalachian Division. Triad Hunter received land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services. The Company also had accounts payable of $304,000 to Classic Petroleum, Inc. as of June 30, 2015.

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In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five-year tank rental agreement with GreenHunter Water.  On December 22, 2014, Triad Hunter entered into an Amendment to Produced Water Hauling and Disposal Agreement with GreenHunter Water to secure long-term water disposal at reduced rates through December 31, 2019. To ensure disposal capacity, in connection with the amendment on December 29, 2014, Triad Hunter made a prepayment of $1.0 million towards services to be provided under the Produced Water Hauling and Disposal Agreement. GreenHunter Water provided a 50% credit for all services performed under the agreement until the prepayment amount was utilized in full, which occurred during the second half of 2015.

As of June 30, 2015, the Company had a note receivable from GreenHunter with an outstanding principal balance of approximately $1.0 million.  Under the terms of the promissory note, GreenHunter is required to make quarterly payments to the Company  comprised of principal of $137,500 and accrued interest through the maturity of the note in February 2017. Under the terms of the note, failure to pay timely is considered an event of default. As of March 31, 2015, GreenHunter was past due on principal and interest payments in aggregate of $168,437, which were due on February 17, 2015. On May 4, 2015, GreenHunter made this past due principal and interest payment of $168,437.

As of June 30, 2015, Mr. Evans, the Company's Chairman and Chief Executive Officer, held 27,641 Series A-1 Common Units of Eureka Hunter Holdings.

Triad Hunter and Eureka Hunter Pipeline are parties to an Amended and Restated Gas Gathering Services Agreement, which was executed on March 21, 2012, and amended on October 3, 2014 in contemplation of the LLC Agreement. Under the terms of the gathering agreement, Triad Hunter reserved throughput capacity in the gas gathering pipeline system of Eureka Hunter Holdings for which Triad Hunter has committed to minimum reservation fees of approximately $0.75 per MMBtu.

Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Holdings and its subsidiaries became related parties of the Company. The Company and Eureka Hunter Holdings entered into a Services Agreement on March 20, 2012, and amended on September 15, 2014, under which the Company agreed to provide administrative services to Eureka Hunter Holdings related to its operations. The terms of the Services Agreement provide that the Company will receive an administrative fee of $500,000 per annum and a personnel services fee equal to the Company's employee cost plus 1.5% subject to mutually agreed upon increases from time to time. Under the terms of the LLC Agreement, certain specified employees of the Company that perform services for Eureka Hunter Holdings and its subsidiaries and for whom the Company previously billed a personnel services fee, are expected to become employees of Eureka Hunter Holdings or a subsidiary of Eureka Hunter Holdings.

On July 18, 2014, the Company entered into a consulting agreement with Kirk J. Trosclair, a former executive of Alpha Hunter Drilling, LLC, a wholly-owned subsidiary of the Company. Mr. Trosclair ceased employment with the Company on July 18, 2014 and is currently the Chief Operating Officer of GreenHunter. The agreement has a term of 12 months and provides that Mr. Trosclair will receive monthly compensation of $10,000, and Mr. Trosclair is eligible to continue vesting in previously granted stock options and unvested restricted stock awards, subject to continued service under the consulting agreement. In connection with this agreement, for the six months ended June 30, 2015, the Company paid Mr. Trosclair $89,000, which includes reimbursement of expenses incurred on behalf of the Company and recognized $76,000 in stock compensation expense.

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Commitments and Contractual Obligations

The following table presents our contractual obligations as of June 30, 2015:

Contractual Obligations	Total		2015		2016 - 2017		2018 - 2019		After 2019
Long-term debt (1)	$	960,528	$	4,912	$	18,075	$	334,715	$	602,826
Interest on long-term debt (2)	416,376		46,491		174,804		168,324		26,757
Gas transportation and compression contracts	160,542		7,416		29,545		29,522		94,059
Asset retirement obligations (3)	26,911		259		9,853		2,874		13,925
Commodity derivative liabilities (4)	490		490		—		—		—
Operating lease obligations	1,713		413		1,093		207		—
Drilling rig installments	5,200		5,200		—		—		—
Total	$	1,571,760	$	65,181	$	233,370	$	535,642	$	737,567

No dividends on preferred securities issued by the Company have been included in the table above because the total amounts to be paid are not determinable. See "Note 10 - Shareholders' Equity" to our consolidated financial statements for further details regarding our obligations to preferred shareholders.

________________________________

(1) See "Note 8 - Debt", to our consolidated financial statements.

(2) Interest payments have been calculated by applying the interest rate in effect as of June 30, 2015 on the debt facilities in place as of June 30, 2015. This results in a weighted average interest rate of 9.19%.

(3) See "Note 5 - 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 7 - Investments and Derivatives" to our consolidated financial statements for additional information regarding the Company's derivative obligations.

MNW Lease Acquisitions

On August 12, 2013, we 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, we 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. The maximum purchase price, if MNW delivers 32,000 acres with acceptable title, would be $142.1 million, excluding title costs. During the six months ended June 30, 2015 and 2014, we purchased 2,665 and 11,128 net leasehold acres, respectively, from MNW for an aggregate purchase price of $12.0 million and $45.9 million, respectively. As of June 30, 2015, we have purchased a total of 25,044 net leasehold acres from MNW for an aggregate purchase price of $103.9 million.

We believe that MNW may not be able to provide us with satisfactory title to all of the remaining net leasehold acres subject to purchase under the asset purchase agreement, and therefore we anticipate that most of the remaining net leasehold acres will not be ultimately acquired by us.

Commitments for Firm Transportation

Throughout 2014, Triad Hunter's natural gas production has been delivered into an over-supplied market in Appalachia, where natural gas has been trading at a significant discount to the Henry Hub Natural Gas spot price ("Henry Hub"). Triad Hunter has been exploring alternative natural gas transportation routes for delivery into markets where natural gas supply is more tempered with respect to demand. By accessing such markets, Triad Hunter expects the differential between Henry Hub pricing and our realized price for natural gas to improve.

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

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

The TGT and REX Transportation Services Agreements are not included in the above contractual commitment schedule as the Company does not have any contractual obligations for firm transportation with either TGT or REX until they have received approval from FERC for each parties respective pipeline project.

Triad Hunter is required to provide credit support to TGT and REX under the provisions of their respective agreements, which may include letters of credit or specified cash collateral. In November 2014, Triad Hunter posted a $36.9 million letter of credit in accordance with the provisions of the REX Transportation Services Agreement. Additionally, in October 2015, Triad Hunter will be required to begin posting letters of credit related to the TGT Transportation Services Agreement of approximately $13 million, escalating thereafter up to $65 million by December 2016, assuming Triad Hunter retains this firm transportation agreement. This credit support is required to demonstrate Triad Hunter's ability to pay the monthly reservation charges to REX and TGT upon completion and the entry into service of the respective pipeline extension projects.

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

These agreements with TGT and REX will provide alternative routes for delivery of Triad Hunter's natural gas production into markets where there is not presently a surplus in supply, and has improved the margins on our natural gas production to date.

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, 2015, the off-balance sheet arrangements and transactions that we have entered into include operating lease agreements and commitments to purchase firm transportation from third parties.  We do not believe that these arrangements are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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, 2014, 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 and Note 1 - "Organization, Nature of Operations and Summary of Significant Accounting Policies" to the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014, as amended.

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Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in energy prices, interest rates, market prices for publicly traded equity instruments, and other related factors. These risks can affect revenues and cash flows from operating, investing, and financing activities. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, and not for trading purposes.

Commodity Price Risk

The Company's most significant market risk relates to prices for natural gas, crude oil, and NGLs. Recent declines in market prices for natural gas, crude oil, and NGLs have resulted in lower realized prices for the Company's production during the three and six months ended June 30, 2015. Further declines could impact the extent to which the Company develops portions of its proved and unproved oil and natural gas properties, and could possibly include temporarily shutting in certain wells that are uneconomic to produce if commodity prices drop below break-even levels. 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 period of time, we could be required under successful efforts accounting rules to recognize a write down of the carrying value of our oil and natural gas properties.

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 fluctuation. As per the applicable accounting requirements, we record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as income (expense) on our consolidated statements of operations as they occur.  The derivative contracts we held as of June 30, 2015 are contracts which were in a net liability position at the time of termination of the majority of our commodity derivative contracts during May 2015. Although our derivative hedging instruments may qualify for cash flow hedge accounting, we do not currently elect hedge accounting for our commodity derivative instruments.

As of June 30, 2015, the Company held derivative instruments associated with future production of 0.3 MMBbls of crude oil, representing a gross liability of $0.5 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, 2015:

	As of June 30, 2015
	Fair Value As Reported			Fair Value: 10% Price Increase			Fair Value: 10 % Price Decrease
	(in thousands)
Crude oil	$	(490	)	$	(284	)	$	(742	)
Total Fair Value	$	(490	)	$	(284	)	$	(742	)
Change in Fair Value				$	206		$	(252	)

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

At June 30, 2015, we had the following commodity derivative positions outstanding:

			Weighted Average
Crude Oil	Period	Bbls/day	Price per Bbl
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Jan 2015 - Dec 2015	259	$70.00

At June 30, 2015, the fair value of our open commodity derivative contracts was a liability of $0.5 million.

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The following table summarizes the gains and losses on settled and open commodity derivative contracts for the three and six months ended June 30, 2015 and 2014:

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(in thousands)
Gain (loss) on settled transactions	$	(1,118	)	$	(2,267	)	$	3,194		$	(4,551	)
Gain (loss) on open transactions	815			(1,021		)	(370		)	(4,282		)
Total gain (loss)	$	(303	)	$	(3,288	)	$	2,824		$	(8,833	)

See "Note 7 - Investments and Derivatives" in the accompanying consolidated financial statements for additional information on derivative instruments.

Interest Rate Risk

Borrowings under the MHR Senior Revolving Credit Facility 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 $5,000 and $6,000 for the three and six months ended June 30, 2015.

Financial Instrument Price Risk

We have investments in both publicly-traded and non-publicly-traded financial instruments. Our ability to divest of these instruments is a function of overall market liquidity which is impacted by, among other things, the amount of outstanding securities of a particular issuer, trading history of the issuer, overall market conditions, and entity-specific facts and circumstances that impact a particular issuer. As a result, market volatility and overall financial performance and liquidity of the issuer could result in significant fluctuations in the fair value of these instruments, and we may be unable to recover the full cost of these investments. A 10% increase or decrease in market prices for our marketable securities would increase or decrease fair value by $0.2 million.

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Item 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

The Company's management, including the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), performed an evaluation of the effectiveness of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of June 30, 2015. 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 the Company's disclosure controls and procedures were effective as of June 30, 2015.

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, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 14 - "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.

Liquidity

We continue to actively pursue certain liquidity enhancing transactions, as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources," including without limitation the sale of all of our equity ownership interest in Eureka Hunter Holdings. However, we cannot provide assurance as to whether or when we will be able to consummate these or other liquidity enhancing transactions, or, if any liquidity enhancing transactions are consummated, whether they will be on the terms contemplated or will provide sufficient liquidity to meet our cash flow needs, including debt service, or maintain compliance with the financial covenants in our debt agreements.

Our failure to service any debt or to comply with the applicable debt covenants could result in a default under the related debt agreement, and under any other debt agreement or any commodity derivative contract under which such default is a cross-default, which could result in the acceleration of the payment of such debt, termination of the lenders' commitments to make further loans to us, loss of our ownership interests in the secured properties, early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect our business, financial condition and results of operations.

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

None.

Item 3.         Defaults upon Senior Securities

None.

Item 4.         Mine Safety Disclosures

Not applicable.

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Item 5.         Other Information

None.

Item 6.        Exhibits

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

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SIGNATURES

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

	MAGNUM HUNTER RESOURCES CORPORATION
Date: August 7, 2015		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman and Chief Executive Officer
Date: August 7, 2015		/s/ Joseph C. Daches
		Joseph C. Daches,
		Senior Vice President and Chief
		Financial Officer

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INDEX TO EXHIBITS

Exhibit Number	Description
2.1+	Purchase and Sale Agreement, dated May 22, 2015, by and between Triad Hunter, LLC and Antero Resources Corporation (incorporated by reference from the Registrant's Current Report on Form 8-K filed on May 29, 2015).
2.2+	Letter Agreement, dated July 27, 2015, by and among Eureka Hunter Holdings, LLC, Magnum Hunter Resources Corporation and MSIP II Buffalo Holdings, LLC (incorporated by reference from the Registrant's Current Report on Form 8-K filed on July 28, 2015).
10.1.1	Second Amendment to Credit Agreement and Limited Waiver, dated April 17, 2015, by and among Magnum Hunter Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on April 20, 2015).
10.1.2	Third Amendment to Credit Agreement and Limited Consent, dated May 28, 2015, by and among Magnum Hunter Resources Corporation, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on May 29, 2015).
10.1.3	Fourth Amendment to Credit Agreement and Limited Consent, dated June 19, 2015, by and among Magnum Hunter Resources Corporation, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on June 24, 2015).
10.1.4	Fifth Amendment to Credit Agreement and Limited Waiver, dated July 10, 2015, by and among Magnum Hunter Resources Corporation, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on July 16, 2015).
10.2	First Amendment to Credit Agreement and Limited Waiver, dated April 17, 2015, by and among Magnum Hunter Resources Corporation, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, and the several lenders and guarantors party thereto (incorporated by reference from the Registrant's Current Report on Form 8-K filed on April 20, 2015).
12.1#	Computation of Ratio of Earnings to Fixed Charges.
31.1#	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2#	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1@	Certification of the Chief Executive Officer and Chief Financial Officer provided pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS#	XBRL Instance Document.
101.SCH#	XBRL Taxonomy Extension Schema Document.
101.CAL#	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB#	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE#	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF#	XBRL Taxonomy Extension Definition Presentation Linkbase Document.
+	Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules and similar attachments have been omitted from this exhibit and will be provided to the Securities and Exchange Commission upon request.
#	Filed herewith.
@	This exhibit is furnished herewith and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

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