Magnum Hunter Resources 10-Q 2015 Q1 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

For the quarterly period ended March 31, 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 May 8, 2015, there were 208,300,253 shares of the registrant's common stock ($0.01 par value) outstanding.

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED MARCH 31, 2015

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited):
Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	1
Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014	3
Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 and 2014	4
Consolidated Statement of Shareholders' Equity for the Three Months Ended March 31, 2015	5
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	6
Notes to Consolidated Financial Statements	7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3. Quantitative and Qualitative Disclosures About Market Risk	63
Item 4. Controls and Procedures	65
Part II. OTHER INFORMATION	65
Item 1. Legal Proceedings	65
Item 1A. Risk Factors	65
Item 3. Defaults Upon Senior Securities	66
Item 5. Other Information	66
Item 6. Exhibits	66
SIGNATURES	67

MAGNUM HUNTER RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

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

(unaudited)

	March 31, 2015		December 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	13,653	$	53,180
Accounts receivable:
Oil and natural gas sales	6,718		16,319
Joint interests and other, net of allowance for doubtful accounts of $459 at March 31, 2015 and $308 at December 31, 2014	10,654		23,888
Derivative assets	15,376		16,586
Inventory	3,412		2,268
Investments	2,225		3,864
Prepaid expenses and other assets	2,750		4,091
Total current assets	54,788		120,196
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting, net	1,066,623		1,098,235
Gas transportation, gathering and processing equipment and other, net	77,534		77,423
Total property, plant and equipment, net	1,144,157		1,175,658
OTHER ASSETS
Deferred financing costs, net of amortization of $15,906 at March 31, 2015 and $15,099 at December 31, 2014	22,093		22,856
Other assets	875		3,928
Investment in affiliates, equity method	346,912		347,191
Total assets	$	1,568,825	$	1,669,829

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)

	March 31, 2015			December 31, 2014
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt	$	10,171		$	10,770
Accounts payable	112,459			130,502
Accounts payable to related parties	2,239			90
Accrued liabilities	35,204			20,277
Revenue payable	6,532			5,450
Other liabilities	2,377			1,356
Total current liabilities	168,982			168,445
Long-term debt, net of current portion	940,809			937,963
Asset retirement obligations, net of current portion	25,564			26,229
Other long-term liabilities	5,499			5,337
Total liabilities	1,140,854			1,137,974
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 March 31, 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 March 31, 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 March 31, 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 202,449,056 and 201,420,701 issued, and 201,534,104 and 200,505,749 outstanding as of March 31, 2015 and December 31, 2014, respectively	2,024			2,014
Additional paid in capital	912,957			909,783
Accumulated deficit	(899,313		)	(784,546		)
Accumulated other comprehensive loss	(66		)	(7,765		)
Treasury stock, at cost:
Series E Preferred Stock, 81 shares as of March 31, 2015 and December 31, 2014	(2,030		)	(2,030		)
Common stock, 914,952 shares as of March 31, 2015 and December 31, 2014	(1,914		)	(1,914		)
Total shareholders' equity	327,971			431,855
Total liabilities and shareholders' equity	$	1,568,825		$	1,669,829

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   March 31,
	2015			2014
REVENUES AND OTHER
Oil and natural gas sales	$	49,391		$	75,965
Midstream natural gas gathering, processing, and marketing	458			31,723
Oilfield services	4,865			5,621
Other revenue	682			173
Total revenue	55,396			113,482
OPERATING EXPENSES
Production costs	13,805			13,056
Severance taxes and marketing	2,823			4,975
Transportation, processing, and other related costs	20,337			12,033
Exploration	8,490			15,924
Impairment of proved oil and gas properties	13,854			16,754
Midstream natural gas gathering, processing, and marketing	494			29,999
Oilfield services	4,211			3,947
Depletion, depreciation, amortization and accretion	57,750			29,409
Loss (gain) on sale of assets, net	(1,652		)	4,075
General and administrative	12,772			16,072
Total operating expenses	132,884			146,244
OPERATING LOSS	(77,488		)	(32,762		)
OTHER INCOME (EXPENSE)
Interest income	49			45
Interest expense	(23,465		)	(23,897		)
Gain on derivative contracts, net	3,102			347
Gain on dilution of interest in Eureka Hunter Holdings, LLC	2,390			—
Loss from equity method investments	(2,900		)	(246		)
Other expense	(7,607		)	(44		)
Total other expense, net	(28,431		)	(23,795		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(105,919		)	(56,557		)
Income tax benefit	—			—
LOSS FROM CONTINUING OPERATIONS, NET OF TAX	(105,919		)	(56,557		)
Income from discontinued operations, net of tax	—			3,369
Loss on disposal of discontinued operations, net of tax	—			(8,513		)
NET LOSS	(105,919		)	(61,701		)
Net loss attributed to non-controlling interests	—			109
LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	(105,919		)	(61,592		)
Dividends on preferred stock	(8,848		)	(14,896		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(114,767	)	$	(76,488	)
Weighted average number of common shares outstanding, basic and diluted	200,918,521			172,146,431
Loss from continuing operations per share, basic and diluted	$	(0.57	)	$	(0.41	)
Loss from discontinued operations per share, basic and diluted	—			(0.03		)
NET LOSS PER COMMON SHARE, BASIC AND DILUTED	$	(0.57	)	$	(0.44	)
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION
Loss from continuing operations, net of tax	$	(105,919	)	$	(56,448	)
Loss from discontinued operations, net of tax	—			(5,144		)
Net loss	$	(105,919	)	$	(61,592	)

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   March 31,
	2015			2014
NET LOSS	$	(105,919	)	$	(61,701	)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation gain (loss)	115			(2,348		)
Unrealized loss on available for sale securities	(1,408		)	(56		)
Amounts reclassified for other than temporary impairment of available for sale securities	8,992			—
Total other comprehensive income (loss)	7,699			(2,404		)
COMPREHENSIVE LOSS	(98,220		)	(64,105		)
Comprehensive loss attributable to non-controlling interests	—			109
COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	$	(98,220	)	$	(63,996	)

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	—	—	1,028	—		—		10		3,481			—			—			—			3,491
Shares withheld for taxes	—	—	—	—		—		—		(307		)	—			—			—			(307		)
Dividends on preferred stock	—	—	—	—		—		—		—			(8,848		)	—			—			(8,848		)
Net loss	—	—	—	—		—		—		—			(105,919		)	—			—			(105,919		)
Foreign currency translation	—	—	—	—		—		—		—			—			115			—			115
Unrealized loss on available for sale securities, net	—	—	—	—		—		—		—			—			(1,408		)	—			(1,408		)
Amounts reclassified from accumulated other comprehensive income for other than temporary impairment of available for sale securities	—	—	—	—		—		—		—			—			8,992			—			8,992
BALANCE, March 31, 2015	4,425	4	202,449	$	221,244	$	95,069	$	2,024	$	912,957		$	(899,313	)	$	(66	)	$	(3,944	)	$	327,971

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)

	Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(105,919	)	$	(61,701	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	57,750			29,408
Exploration	7,838			13,712
Impairment of proved oil and gas properties	13,854			—
Share-based compensation	3,185			1,061
Cash paid for plugging wells	—			(22		)
Loss (gain) on sale of assets	(1,652		)	31,238
Unrealized loss (gain) on derivative contracts	1,209			(2,631		)
Gain on dilution of interest in Eureka Hunter Holdings, LLC	(2,390		)	—
Loss from equity method investment	2,900			246
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	1,124			3,621
Changes in operating assets and liabilities:
Accounts receivable, net	30,313			(7,828		)
Inventory	(1,144		)	3,246
Prepaid expenses and other current assets	1,585			(562		)
Accounts payable	14,616			(26,020		)
Revenue payable	446			4,841
Accrued liabilities	15,429			15,268
Net cash provided by operating activities	48,136			3,877
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures and advances	(84,255		)	(39,127		)
Change in deposits and other long-term assets	2,789			(107		)
Proceeds from sales of assets	580			16,415
Net cash used in investing activities	(80,886		)	(22,819		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from sale of common shares	—			28,897
Proceeds from sale of Eureka Hunter Holdings Series A Preferred Units	—			3,920
Proceeds from exercise of warrants and options	—			3,983
Preferred stock dividend	(8,848		)	(10,770		)
Repayments of debt	(3,070		)	(84,683		)
Proceeds from borrowings on debt	5,000			101,616
Deferred financing costs	(44		)	(1,331		)
Change in other long-term liabilities	163			24
Net cash provided by (used in) financing activities	(6,799		)	41,656
Effect of changes in exchange rate on cash	22			25
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(39,527		)	22,739
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	53,180			41,713
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	13,653		$	64,452

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 a Dallas, 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 and a substantial equity method investment in midstream 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.

Non-Controlling Interest in Consolidated Subsidiaries

Prior to December 18, 2014, the Company consolidated Eureka Hunter Holdings, LLC ("Eureka Hunter Holdings") in which it owned 48.6% as of December 18, 2014 and December 31, 2014. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC ("Eureka Hunter Pipeline"), TransTex Hunter, LLC ("TransTex Hunter"), and Eureka Hunter Land, LLC. Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. Accordingly, the Company deconsolidated Eureka Hunter Holdings as of December 18, 2014 and accounts for its retained interest under the equity method of accounting with the Company's share of Eureka Hunter Holdings' earnings recorded in "loss from equity method investment" in the consolidated statements of operations. The Company owned 45.5% of the equity interests of Eureka Hunter Holdings as of March 31, 2015. See "Note 7 - Investments and Derivatives".

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 now owns 100% of the equity interests in PRC Williston and has all rights and claims to its remaining assets and liabilities, which are not significant. Consequently, there is no longer any non-controlling interest in PRC Williston's equity reflected in the consolidated financial statements as of March 31, 2015.

7

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 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 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.

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 Financial Accounting Standards Board's ("FASB") Accounting Standards Codification ("ASC") Subtopic 980-605, Regulated Operations-Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. During the three months ended March 31, 2015, the Company had gas transmission, compression and processing revenue, which included gas utility sales from Sentra Corporation's regulated operations aggregating $378,261. During the three months ended March 31, 2014, the Company had revenues of $171,072 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 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. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

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 is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.

8

NOTE 2 - ACQUISITIONS 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 three months ended March 31, 2015, Triad Hunter purchased 2,665 net leasehold acres from MNW for an aggregate purchase price of $12.0 million. Triad Hunter made no purchases from MNW during the three months ended March 31, 2014. As of March 31, 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.

Discontinued Operations

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

As of March 31, 2015 and December 31, 2014, the Company did not have any assets or liabilities associated with assets held for sale.

The Company included 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 months ended March 31, 2014. There was no income or loss from discontinued operations or gain or loss from the disposal of discontinued operations for the three months ended March 31, 2015.

	Three Months Ended   March 31,
	2014
	(in thousands)
Revenues	$	6,244
Expenses	(2,881		)
Other income	6
Income tax benefit	—
Income from discontinued operations, net of tax	3,369
Loss on disposal of discontinued operations, net of taxes of $0	(8,513		)
Loss from discontinued operations, net of taxes	$	(5,144	)

9

NOTE 3 - OIL & NATURAL GAS SALES

During the three months ended March 31, 2015 and 2014, the Company recognized sales from oil, natural gas, and natural gas liquids ("NGLs") as follows:

	Three Months Ended   March 31,
	2015		2014
	(in thousands)
Oil	$	9,544	$	35,353
Natural gas	31,860		27,520
NGLs	7,987		13,092
Total oil and natural gas sales	$	49,391	$	75,965

NOTE 4 - PROPERTY, PLANT, & EQUIPMENT

Oil and Natural Gas Properties

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

	March 31, 2015			December 31, 2014
	(in thousands)
Mineral interests in properties:
Unproved leasehold costs	$	450,530		$	481,643
Proved leasehold costs	284,253			257,185
Wells and related equipment and facilities	634,229			606,406
Advances to operators for wells in progress	1,297			1,411
Total costs	1,370,309			1,346,645
Less accumulated depletion, depreciation, and amortization	(303,686		)	(248,410		)
Net capitalized costs	$	1,066,623		$	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 $13.9 million were recorded during the three months ended March 31, 2015, primarily related to Appalachian Basin properties. Impairments of proved properties of $16.8 million were recorded for the three months ended March 31, 2014, which were comprised entirely 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 $55.3 million for the three months ended March 31, 2015 and $23.9 million for the three months ended March 31, 2014.

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.

10

During the three months ended March 31, 2015 and 2014, the Company recognized exploration expense as follows:

	Three Months Ended   March 31,
	2015		2014
	(in thousands)
Leasehold impairments	$	7,838	$	15,550
Geological and geophysical	652		374
Total exploration expense	$	8,490	$	15,924

Leasehold impairment expense recorded by the Company during the three months ended March 31, 2015 consisted of $7.6 million in the U.S. upstream segment related to leases in the Williston Basin and $0.2 million related to leases in the Appalachian Basin. Leasehold impairment expense during the three months ended March 31, 2014 consisted of $11.1 million related to leases in the Williston Basin and $2.6 million 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 $1.9 million in leasehold impairment expense related to fair value write-downs of MHP for the three months ended March 31, 2014.

Gas Transportation, Gathering, and Processing Equipment and Other

The historical cost of gas transportation, gathering, and processing equipment and other property, presented on a gross basis with accumulated depreciation, as of March 31, 2015 and December 31, 2014 is summarized as follows:

	March 31, 2015			December 31, 2014
	(in thousands)
Gas transportation, gathering and processing equipment and other	$	102,639		$	100,436
Less accumulated depreciation	(25,105		)	(23,013		)
Net capitalized costs	$	77,534		$	77,423

Depreciation expense for gas transportation, gathering, and processing equipment and other property was $1.9 million for the three months ended March 31, 2015 and $4.7 million for the three months ended March 31, 2014.

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NOTE 5 - ASSET RETIREMENT OBLIGATIONS

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

	March 31, 2015			December 31, 2014
	(in thousands)
Asset retirement obligation at beginning of period	$	26,524		$	16,216
Assumed in acquisitions	92			—
Liabilities incurred	4			218
Liabilities settled	—			(107		)
Liabilities sold	—			(2,598		)
Accretion expense	618			1,478
Revisions in estimated liabilities (1)	(862		)	3,208
Reclassified from liabilities associated with assets held for sale	—			8,109
Asset retirement obligation at end of period	26,376			26,524
Less: current portion (included in other liabilities)	(812		)	(295		)
Asset retirement obligation at end of period	$	25,564		$	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

Transfers between Levels 1 and 2 occur at the end of the reporting period in which it is determined that the observability of significant inputs has increased or decreased. There were no transfers between levels of the fair value hierarchy during the three month periods ended March 31, 2015 and 2014.

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

Level 1 Classification:

Available for Sale Securities

At March 31, 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.

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Level 2 Classification:

Commodity Derivative Instruments

At March 31, 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 March 31, 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. 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:

	March 31, 2015
Life	1.9
Risk-free interest rate	0.77%
Estimated volatility	85%
Dividend	—
GreenHunter stock price at end of period	$0.70

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

13

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

	Fair Value Measurements on a Recurring Basis
	March 31, 2015
	(in thousands)
Assets	Level 1		Level 2		Level 3
Available for sale securities	$	2,225	$	—	$	—
Commodity derivative assets	—		15,326		—
Convertible security derivative assets	—		—		50
Total assets at fair value	$	2,225	$	15,326	$	50

	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 three-month period ended March 31, 2015:

	Convertible Security Embedded Derivative Asset
	(in thousands)
Fair value as of December 31, 2014	$	75
Decrease in fair value recognized in gain on derivative contracts, net	(25		)
Fair value as of March 31, 2015	$	50

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: 

		March 31, 2015				December 31, 2014
	Fair Value Hierarchy	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
		(in thousands)
Senior Notes	Level 2	$	597,404	$	546,000	$	597,355	$	498,000
MHR Senior Revolving Credit Facility	Level 3	$	5,000	$	5,000	$	—	$	—
MHR Second Lien Term Loan	Level 3	$	328,559	$	319,584	$	329,140	$	329,140
Equipment Notes Payable	Level 3	$	20,017	$	19,957	$	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).

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.

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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 three months ended March 31, 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 $495.5 million as of March 31, 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 three months ended March 31, 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 has 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 as of September 2014 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 period ended March 31, 2015, related to the decline in value of its investment in NSE.

15

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 March 31, 2015 or December 31, 2014. The GreenHunter common shares are publicly traded and had a fair value of $1.3 million at March 31, 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.

Investment Holdings - Eureka Hunter Holdings

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.

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.

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"), 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").  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.

16

If the Company does not fund the full MHR Additional Contribution Component by the MHR Contribution Deadline, 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.

After the earlier to occur of (a) the Company having made contributions equal to the MHR Additional Contribution Component and (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 March 31, 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 $346.9 million and $347.2 million at March 31, 2015 and December 31, 2014, respectively.

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 preliminarily been allocated to the following identifiable assets of Eureka Hunter Holdings:

	Identifiable Assets
	Ending Basis December 31, 2014		Basis Amortization			Basis Reduction			Ending Basis March 31, 2015
	(in thousands)
Fixed assets	$	5,088	$	(70	)	$	(98	)	$	4,920
Intangible assets	155,189		(1,830		)	(2,705		)	150,654
Goodwill	41,597		—			(1,104		)	40,493
Total basis difference	$	201,874	$	(1,900	)	$	(3,907	)	$	196,067

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 estimated the identifiable assets to which the basis difference is attributable to and has recorded amortization based on this estimate for the period ended March 31, 2015.  The Company is currently finalizing the fair value estimates for Eureka Hunter Holdings and is expecting to finalize this valuation during the second quarter of 2015. 

17

Summarized income information for Eureka Hunter Holdings for the three months ended March 31, 2015 is as follows:

	Three Months Ended   March 31, 2015
	(in thousands)
Operating revenues	$	13,715
Operating loss	$	(472	)
Net loss	$	(1,582	)
Magnum Hunter's interest in Eureka Hunter Holdings net loss	$	(769	)
Basis difference amortization	$	(1,900	)
Magnum Hunter's equity in earnings, net	$	(2,669	)

Below is a summary of changes in investments for the three months ended March 31, 2015:

	Available for Sale Securities			Equity Method Investments
	(in thousands)
Carrying value as of December 31, 2014	$	3,864		$	347,191
Gain on dilution of interest in Eureka Hunter Holdings	—			2,390
Loss from equity method investment(1)	(231		)	(2,669		)
Change in fair value recognized in other comprehensive loss	(1,408		)	—
Carrying value as of March 31, 2015	$	2,225		$	346,912

⁽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 have been presented in the consolidated balance sheet as of March 31, 2015 as follows:

	Available for Sale Securities		Equity Method Investments		Total
Investments - Current	$	2,225	$	—	$	2,225
Investments - Non-current	—		346,912		346,912
Carrying value as of March 31, 2015	$	2,225	$	346,912	$	349,137

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

	March 31, 2015
	(in thousands)
	Cost		Gross Unrealized Losses			Fair Value
Securities available for sale, carried at fair value:
Equity securities	$	883	$	(346	)	$	537
Equity securities - related party (see "Note 13 - Related Party Transactions")	2,200		(512		)	1,688
Total Securities available for sale	$	3,083	$	(858	)	$	2,225

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	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".

Commodity and Financial Derivative Instruments

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

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

As of March 31, 2015, the Company had the following commodity derivative instruments:

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Swaps	Jan 2015 - Dec 2015	40,000	$4.09
			Weighted Average
Crude Oil	Period	Bbl/day	Price per Bbl
Collars (1)	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Jan 2015 - Dec 2015	259	$70.00

________________________________    

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

As of March 31, 2015, Bank of America, Bank of Montreal, Citibank, N.A., and the Royal Bank of Canada are the only counterparties 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 in the MHR Senior Revolving Credit Facility, under which the Company had outstanding borrowings of $5.0 million as of March 31, 2015. Additionally, certain counterparties to the Company's commodity derivatives positions are no longer participants 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 March 31, 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".

19

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
	March 31, 2015		December 31, 2014
	(in thousands)
Commodity
Derivative assets	$	15,326	$	16,511
Total commodity	$	15,326	$	16,511
Financial
Derivative assets	$	50	$	75
Total financial	$	50	$	75
Total derivatives	$	15,376	$	16,586

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

	March 31, 2015
	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset on the Consolidated Balance Sheet			Net Amount
	(in thousands)
Current assets:  Fair value of derivative contracts	$	16,631		$	(1,305	)	$	15,326
Current liabilities:  Fair value of derivative contracts	(1,305		)	1,305			—
	$	15,326		$	—		$	15,326

	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 months ended March 31, 2015 and 2014:

	Three Months Ended   March 31,
	2015			2014
	(in thousands)
Gain (loss) on settled transactions	$	4,311		$	(2,284	)
Gain (loss) on open contracts	(1,209		)	2,631
Total gain, net	$	3,102		$	347

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NOTE 8 - DEBT

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

	March 31, 2015			December 31, 2014
	(in thousands)
Senior Notes payable due May 15, 2020, interest rate of 9.75%, net of unamortized net discount of $2.6 million at March 31, 2015 and December 31, 2014	$	597,404		$	597,355
Various equipment and real estate notes payable with maturity dates February 2015 - November 2017, interest rates of 4.25% - 7.94%	20,017			22,238
MHR Senior Revolving Credit Facility due October 22, 2018, interest rate of 2.93% at March 31, 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 $9.7 million and $10.0 million at March 31, 2015 and December 31, 2014, respectively	328,559			329,140
	950,980			948,733
Less: current portion	(10,171		)	(10,770		)
Total long-term debt obligations, net of current portion	$	940,809		$	937,963

The following table presents the scheduled or expected approximate annual maturities of debt, gross of unamortized discount of $12.3 million: 

	(in thousands)
2015	$	7,701
2016	12,127
2017	5,948
2018	8,958
2019	325,757
Thereafter	602,826
Total	$	963,317

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").

Under the Credit Agreement, as amended as described below, the Company is required to satisfy certain financial covenants, including maintaining:

i. commencing with the fiscal quarter ending June 30, 2015 and for each fiscal quarter ending thereafter, a current ratio (as defined in the Credit Agreement) of not less than 1.0 to 1.0;

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

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

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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. The current ratio requirement increases 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, pursuant to the First Amendment, 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 may 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 may 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 cannot 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) 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.

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 shall automatically increase by 1.00% and the commitment fee shall automatically increase by 0.25% and such elevated rates shall continue until the day immediately preceding the date on which the Adjusted Period ends. 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 preceding sentence.

At March 31, 2015, the Company was not in compliance with its current ratio or its total secured net debt to EBITDAX ratio (as defined) financial covenants under the Credit Agreement, as amended. In addition, the Company failed to comply with certain provisions contained in the Credit Agreement related to the aging of payables. The Company has obtained a waiver from its lenders of the current ratio and total secured net debt to EBITDAX ratio (as defined) financial covenant requirements for the March 31, 2015 compliance period and 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 requires 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 date of invoice from 90 days to 180 days for any day on or prior to May 29, 2015, after which the date the restriction will revert 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.

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2. Payment of the preferred stock dividends for the month of May 2015 will be permitted provided the Company has 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 are 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 failure by the Company to satisfy this waiver condition will constitute an event of default under the Credit Agreement.

As of March 31, 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 $39.3 million using availability under the Company's Senior Revolving Credit Facility. As of March 31, 2015, the borrowing capacity under the Senior Revolving Credit Facility was $5.7 million.

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.

At March 31, 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; however, the Company failed to comply with certain provisions contained in the Second Lien Term Loan Agreement related to the aging of payables.

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 date of invoice 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.

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Interest Expense

The following table sets forth interest expense for the three month periods ended March 31, 2015 and 2014, respectively:

	Three Months Ended   March 31,
	2015		2014
	(in thousands)
Interest expense incurred on debt, net of amounts capitalized	$	22,658	$	20,276
Amortization and write-off of deferred financing costs	807		3,621
Total interest expense	$	23,465	$	23,897

The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. The Company capitalized interest of $0.6 million during the three months ended March 31, 2014 as part of the construction of Eureka Hunter Holdings' gas gathering system, prior to the deconsolidation of Eureka Hunter Holdings on December 18, 2014. The Company capitalized no interest during the three months ended March 31, 2015.

For the three-month period ended March 31, 2014, interest expense incurred on debt includes a $2.2 million prepayment penalty incurred by Eureka Hunter Pipeline as a result of its early termination of the Original Eureka Hunter Credit Facilities on March 28, 2014, which penalty represents an additional cost of borrowing for a period shorter than contractual maturity. In addition, amortization and write-off of deferred financing costs for the three-month period ended March 31, 2014 includes the write-off of $2.7 million in unamortized deferred financing costs related to those terminated agreements, which costs were expensed at the time of early extinguishment.

NOTE 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 March 31, 2015, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 11,728,837 shares had been issued under the plan as of March 31, 2015, of which 1,821,470 shares remained unvested at March 31, 2015. Additionally, 12,466,231 options to purchase shares and stock appreciation rights were outstanding as of March 31, 2015, of which 2,977,557 remained unvested at March 31, 2015.

The Company recognized share-based compensation expense of $3.2 million for the three months ended March 31, 2015 and $1.1 million for the three months ended March 31, 2014.

A summary of common stock option activity for the three months ended March 31, 2015 and 2014 is presented below:

	Three Months Ended March 31,
	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	—		(597	)	$	—	$	6.67
Forfeited	(729	)	(902	)	$	5.93	$	6.37
Outstanding at end of period	12,466		15,392		$	5.92	$	5.61
Exercisable at end of period	9,489		10,003		$	6.04	$	5.74

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A summary of the Company's non-vested common stock options and stock appreciation rights for the three months ended March 31, 2015 and 2014 is presented below:

	Three Months Ended March 31,
	2015		2014
	(in thousands of shares)
Non-vested at beginning of period	4,055		6,908
Granted	—		—
Vested	(725	)	(805	)
Forfeited	(353	)	(714	)
Non-vested at end of period	2,977		5,389

Total unrecognized compensation cost related to the non-vested common stock options and stock appreciation rights was $1.6 million and $7.9 million as of March 31, 2015 and 2014, respectively.  The unrecognized compensation cost at March 31, 2015 is expected to be recognized over a weighted-average period of 0.54 years. At March 31, 2015, the weighted average remaining contract life of outstanding options was 4.5 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 stock price on grant date. During the three months ended March 31, 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 stock price on grant date and estimated forfeiture rate of 5.6%.

Total unrecognized compensation cost related to non-vested, restricted shares amounted to $7.7 million and $9.3 million as of March 31, 2015 and 2014, respectively.  The unrecognized cost at March 31, 2015, is expected to be recognized over a weighted-average period of 1.76 years.

NOTE 10 - SHAREHOLDERS' EQUITY

Common Stock

During the three months ended March 31, 2015, the Company issued 1,028,355 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.

Preferred Dividends Incurred

A summary of the Company's preferred dividends for the three months ended March 31, 2015 and 2014 is presented below:

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Dividend on Eureka Hunter Holdings Series A Preferred Units	$	—	$	4,028
Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	—		2,048
Dividend on Series C Preferred Stock	2,562		2,562
Dividend on Series D Preferred Stock	4,424		4,424
Dividend on Series E Preferred Stock	1,862		1,834
Total dividends on Preferred Stock	$	8,848	$	14,896

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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 March 31, 2015 and 2014:

	March 31,
	2015	2014
	(in thousands of shares)
Series E Preferred Stock	10,946	10,946
Warrants	19,173	17,071
Unvested restricted shares	1,768	1,453
Common stock options and stock appreciation rights	12,466	15,392
Total	44,353	44,862

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 months ended March 31, 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 March 31, 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 March 31, 2015 and December 31, 2014:

	March 31, 2015			December 31, 2014
	(in thousands)
GreenHunter (1)
Accounts payable - net	$	(373	)	$	(228	)
Derivative assets (2)	$	50		$	75
Investments (2)	$	1,688		$	1,311
Notes receivable (2)	$	1,226		$	1,224
Prepaid expenses	$	461		$	1,000
Eureka Hunter Holdings (3)
Accounts receivable (payable) - net	$	(1,596	)	$	122
Equity method investment	$	352,354		$	347,191
Pilatus Hunter
Accounts receivable - net	$	12		$	12
Classic Petroleum, Inc. (5)
Accounts payable	$	(282	)	$	—

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 March 31, 2015 and 88,000 shares of Series C preferred stock of GreenHunter with a carrying value of $1.7 million as of March 31, 2015.

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The following table sets forth the related party transaction activities for the three months ended March 31, 2015 and 2014, respectively:

		Three Months Ended   March 31,
		2015		2014
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	1,339	$	322
	Equipment rental (1)	$	45	$	122
	Gas gathering-trucking (1)	$	6	$	—
	Office space rental	$	4	$	22
	Interest income from note receivable (2)	$	31	$	45
	Dividends received from Series C shares	$	55	$	55
	Unrealized gain on investments (2)	$	376	$	235
Pilatus Hunter, LLC
	Airplane rental expenses (4)	$	11	$	70
Eureka Hunter Holdings (3)
	Transportation costs	$	5,606	$	—
	Disposal services	$	369	$	—
	Equipment rental	$	10	$	—
	Land usage fee	$	3	$	—
Classic Petroleum, Inc. (5)
	Land services	$	162	$	312

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⁽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 sequence 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".

⁽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 receives land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services.

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 is providing a 50% credit for all services performed under the agreement until the prepayment amount is utilized in full, which is anticipated to occur during the first half of 2015. As of March 31, 2015, the prepayment amount had been reduced to $461 thousand.

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As of March 31, 2015, the Company had a note receivable from GreenHunter with an outstanding principal balance of approximately $1.2 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 March 31, 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 three months ended March 31, 2015, the Company paid Mr. Trosclair $31,000, which includes reimbursement of expenses incurred on behalf of the Company, and recognized $49,000 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.

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

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

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

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

In April 2013, the Company also received a letter from the 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

30

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. The Company submitted a response to the Wells Notice in the form of a Wells Submission and continues to engage with the Staff regarding the issues raised in the Wells Notice.

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 cross-claims among the defendants in the Whisenhunt litigation have not been resolved. Investigation regarding the incident is ongoing. It is not possible to predict at this juncture the extent to which, if at all, Eureka Hunter Pipeline or any related entities will incur liability or damages because of this incident. However, the Company believes that its insurance coverage will be sufficient to cover any losses or liabilities it may incur as a result of this incident, 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.

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NOTE 15 - SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Cash paid for interest	$	7,408		$	3,050
Non-cash transactions
Non-cash consideration received from sale of assets	$	—		$	9,400
Change in accrued capital expenditures	$	(35,152	)	$	55,396
Non-cash additions to asset retirement obligation	$	(766	)	$	52
Eureka Hunter Holdings Series A Preferred Unit dividends paid in kind	$	—		$	1,900

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NOTE 16 - SEGMENT REPORTING

U.S. Upstream, Midstream, and Oilfield Services represent the operating segments of the Company.  Beginning September 30, 2013, the Canadian Upstream segment, comprised of the WHI Canada operations, was classified as assets held for sale and 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 months ended, and segment assets as of March 31, 2015 and 2014, respectively.

	As of and for the Three Months Ended March 31, 2015
	U.S. Upstream			Canadian Upstream		Midstream and Marketing			Oilfield Services			Corporate Unallocated (1)			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	50,213		$	—	$	318		$	6,674		$	—		$	(1,809	)	$	55,396
Depletion, depreciation, amortization and accretion	56,897			—		—			1,006			—			(153		)	57,750
Gain on sale of assets, net	(1,640		)	—		—			(12		)	—			—			(1,652		)
Other operating expenses	61,659			—		404			5,277			11,034			(1,588		)	76,786
Other income (expense)	(8,213		)	—		—			(166		)	(20,052		)	—			(28,431		)
Net income (loss)	$	(74,916	)	$	—	$	(86	)	$	237		$	(31,086	)	$	(68	)	$	(105,919	)
Total assets	$	1,113,179		$	—	$	149		$	44,323		$	412,596		$	(1,422	)	$	1,568,825
Total capital expenditures	$	47,318		$	—	$	—		$	421		$	1,448		$	—		$	49,187

	As of and for the Three Months Ended March 31, 2014
	U.S. Upstream			Canadian Upstream			Midstream and Marketing (2)			Oilfield Services			Corporate Unallocated			Inter-segment Eliminations			Total
	(in thousands)
Total revenue	$	76,212		$	—		$	34,735		$	7,911		$	—		$	(5,376	)	$	113,482
Depletion, depreciation, amortization and accretion	24,940			—			3,678			791			—			—			29,409
Loss on sale of assets, net	4,073			—			—			2			—			—			4,075
Other operating expenses	68,865			—			32,070			6,713			10,488			(5,376		)	112,760
Other income (expense)	(372		)	—			30			(209		)	(23,244		)	—			(23,795		)
Income (loss) from continuing operations before income tax	(22,038		)	—			(983		)	196			(33,732		)	—			(56,557		)
Total income (loss) from discontinued operations, net of tax	(4,319		)	(825		)	—			—			—			—			(5,144		)
Net income (loss)	$	(26,357	)	$	(825	)	$	(983	)	$	196		$	(33,732	)	$	—		$	(61,701	)
Total assets	$	1,369,962		$	64,147		$	322,030		$	45,021		$	98,526		$	(5,833	)	$	1,893,853
Total capital expenditures	$	66,311		$	308		$	30,634		$	690		$	23		$	—		$	97,966

_________________________________

⁽¹⁾   Includes the Company's retained interest in Eureka Hunter Holdings which has a value of $346.9 million at March 31, 2015.

⁽²⁾  Includes operations of Eureka Hunter Holdings, which represents approximately 25.0% of Midstream and Marketing revenues for the three months ended March 31, 2014, and which was deconsolidated as of December 18, 2014.

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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. The Company filed an amendment to this registration statement on April 20, 2015, which was declared effective on April 22, 2015. See "Note 18 - Subsequent Events".

Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (the "Non Guarantor Subsidiaries") as of March 31, 2015 and December 31, 2014, and for the three months ended March 31, 2015 and 2014, are as follows:

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Balance Sheets

(in thousands)

	As of March 31, 2015
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
ASSETS
Current assets	$	34,173		$	21,554		$	416		$	(1,355	)	$	54,788
Intercompany accounts receivable	1,147,078			—			—			(1,147,078		)	—
Property and equipment (using successful efforts method of accounting)	6,598			1,137,615			12			(68		)	1,144,157
Investment in subsidiaries	(158,251		)	92,458			—			65,793			—
Investment in affiliate, equity-method	346,912			—			—			—			346,912
Other assets	22,085			883			—			—			22,968
Total Assets	$	1,398,595		$	1,252,510		$	428		$	(1,082,708	)	$	1,568,825
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	40,478		$	128,854		$	1,005		$	(1,355	)	$	168,982
Intercompany accounts payable	—			1,108,513			40,801			(1,149,314		)	—
Long-term liabilities	930,145			41,727			—			—			971,872
Redeemable preferred stock	100,000			—			—			—			100,000
Shareholders' equity (deficit)	327,972			(26,584		)	(41,378		)	67,961			327,971
Total Liabilities and Shareholders' Equity	$	1,398,595		$	1,252,510		$	428		$	(1,082,708	)	$	1,568,825

34

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		$	36,338	$	589		$	(2,378	)	$	120,196
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		)	—
Investment in affiliate, equity-method	347,191			—		—			—			347,191
Other assets	22,804			3,980		—			—			26,784
Total Assets	$	1,482,970		$	1,304,574	$	619		$	(1,118,334	)	$	1,669,829
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	$	25,347		$	142,914	$	2,567		$	(2,383	)	$	168,445
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		$	1,304,574	$	619		$	(1,118,334	)	$	1,669,829

35

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Operations

(in thousands)

	Three Months Ended March 31, 2015
	Magnum Hunter Resources Corporation			��	100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	1			$	56,996		$	528		$	(2,129	)	$	55,396
Expenses	31,565				131,449			362			(2,061		)	161,315
Income (loss) from continuing operations before equity in net income of subsidiaries	(31,564		)		(74,453		)	166			(68		)	(105,919		)
Equity in net income of subsidiaries	(74,355		)		(1,676		)	—			76,031			—
Net income (loss)	(105,919		)		(76,129		)	166			75,963			(105,919		)
Dividends on preferred stock	(8,848		)		—			—			—			(8,848		)
Net income (loss) attributable to common shareholders	$	(114,767	)		$	(76,129	)	$	166		$	75,963		$	(114,767	)
	Three Months Ended March 31, 2014
	Magnum Hunter Resources Corporation				100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments			Magnum Hunter Resources Corporation Consolidated
Revenues	$	108			$	109,881		$	8,869		$	(5,376	)	$	113,482
Expenses	34,793				131,717			8,905			(5,376		)	170,039
Income (loss) from continuing operations before equity in net income of subsidiaries	(34,685		)		(21,836		)	(36		)	—			(56,557		)
Equity in net income of wholly-owned subsidiaries	(28,815		)		155			—			28,660			—
Income (loss) from continuing operations	(63,500		)		(21,681		)	(36		)	28,660			(56,557		)
Income from discontinued operations, net of tax	—				—			3,369			—			3,369
Gain on sale of discontinued operations, net of tax	(4,319		)		—			(4,194		)	—			(8,513		)
Net income (loss)	(67,819		)		(21,681		)	(861		)	28,660			(61,701		)
Net income attributable to non-controlling interest	—				—			—			109			109
Net income (loss) attributable to Magnum Hunter Resources Corporation	(67,819		)		(21,681		)	(861		)	28,769			(61,592		)
Dividends on preferred stock	(8,820		)		—			(6,076		)	—			(14,896		)
Net income (loss) attributable to common shareholders	$	(76,639	)		$	(21,681	)	$	(6,937	)	$	28,769		$	(76,488	)

36

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income (Loss)

(in thousands)

	Three Months Ended March 31, 2015
	Magnum  Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries		Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Net income (loss)	$	(105,919	)	$	(76,129	)	$	166	$	75,963	$	(105,919	)
Foreign currency translation gain	—			115			—		—		115
Unrealized loss on available for sale securities	—			(1,408		)	—		—		(1,408		)
Amounts reclassified for other than temporary impairment of available for sale securities	—			8,992			—		—		8,992
Comprehensive income (loss)	(105,919		)	(68,430		)	166		75,963		(98,220		)

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

37

Magnum Hunter Resources Corporation and Subsidiaries

Condensed Consolidating Statements of Cash Flows

(in thousands)

	Three Months Ended March 31, 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	$	(41,254	)	$	89,611		$	—	$	(221	)	$	48,136
Cash flows from investing activities	151			(81,258		)	—		221			(80,886		)
Cash flows from financing activities	(5,804		)	(995		)	—		—			(6,799		)
Effect of exchange rate changes on cash	—			22			—		—			22
Net increase (decrease) in cash	(46,907		)	7,380			—		—			(39,527		)
Cash at beginning of period	64,165			(10,985		)	—		—			53,180
Cash at end of period	$	17,258		$	(3,605	)	$	—	$	—		$	13,653

	Three Months Ended March 31, 2014
	Magnum Hunter Resources Corporation			100% Owned Guarantor Subsidiaries			Non Guarantor Subsidiaries			Consolidating/ Eliminating Adjustments		Magnum Hunter Resources Corporation Consolidated
Cash flows from operating activities	$	(8,779	)	$	4,611		$	8,045		$	—	$	3,877
Cash flows from investing activities	(181		)	(4,070		)	(18,568		)	—		(22,819		)
Cash flows from financing activities	31,886			4,050			5,720			—		41,656
Effect of exchange rate changes on cash	—			—			25			—		25
Net increase (decrease) in cash	22,926			4,591			(4,778		)	—		22,739
Cash at beginning of period	47,895			(17,651		)	11,469			—		41,713
Cash at end of period	$	70,821		$	(13,060	)	$	6,691		$	—	$	64,452

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NOTE 18 - SUBSEQUENT EVENTS

Amendments and Waivers to Credit Agreements

On February 24, 2015 and April 17, 2015,the Company entered into certain amendments and waivers with respect to the Credit Agreement and the Second Lien Term Loan Agreement.  These amendments and waivers are described in "Note 8 - Debt".

Form S-3 Registration Statement

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. The guarantor financial information as of and for the three months ended March 31, 2015, included in "Note 17 - Condensed Consolidated Guarantor Financial Statements", is applicable to any Guarantor Subsidiaries that may guarantee any debt issued by the Company pursuant to the Form S-3 Registration Statement.

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 May 8, 2015, the Company had sold an aggregate of 6,759,981 shares of its common stock for aggregate proceeds of $13.7 million net of $0.3 million in sales commissions through this ATM offering under the Form S-3 Registration Statement.

Commodity Derivative Terminations

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. 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 expects to receive 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.

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

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

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to inform the reader about matters affecting the financial condition and results of operations of the Company for the three months ended March 31, 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,

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• marketing of oil, natural gas and natural gas liquids,

• exploitation of our current asset base or property acquisitions,

• the effects of government regulation and permitting and other legal requirements,

• plans, objectives, expectations and intentions contained in this report that are not historical,

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

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

• other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 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. Through our substantial equity method investment in Eureka Hunter Holdings, LLC ("Eureka Hunter Holdings"), we are also involved in midstream operations, primarily in West Virginia and Ohio. 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) continue development of the Eureka Hunter Gas Gathering System in West Virginia and Ohio, (v) 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 (vi) 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, continued development of midstream operations through our substantial equity investment in Eureka Hunter Holdings and the monetization of selected assets.

Financial and Operational Performance Highlights

The following are key financial and operational performance highlights for the Company for the first quarter of 2015:

i. Our average oil and natural gas production from continuing operations increased to 163,569 Mcfe/d for the three months ended March 31, 2015, compared to 98,596 Mcfe/d for the same period in 2014. Average production for the first quarter of 2015 was comprised of 12.9% oil, 74.3% natural gas, and 12.8% NGLs.

ii. Oil and natural gas revenues from continuing operations decreased by 35.0% to $49.4 million compared to $76.0 million during the same three-month period in 2014, due primarily to declines in commodity prices between the comparable periods.

iii. We reported a net loss from continuing operations of $105.9 million for the three months ended March 31, 2015, compared to net loss from continuing operations of $56.6 million for the three months ended March 31, 2014.

iv. As of March 31, 2015, we had approximately 273,851 net leasehold acres in our core operating areas, including (a) approximately 80,566 net acres in the Marcellus Shale, (b) approximately 129,899 net acres prospective for the Utica Shale (a portion of which acreage overlaps our Marcellus Shale acreage) and (c) approximately 63,386 net acres in the Williston Basin/Bakken Shale in North Dakota.

v. Pipeline throughput at Eureka Hunter Holdings reached a record peak of 623,713 MMBTu/d in March, 2015 and increased to an average of 413,502 MMBtu/d for the three months ended March 31, 2015 compared to 152,625 MMBtu/d for the same period in 2014.

vi. Our capital expenditures of $49.2 million during the first quarter of 2015 decreased from the first quarter of 2014 as we reduced our upstream capital expenditures budget for 2015 due to the current commodity price environment.

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Recent Developments

Additional Letter Agreement with Eureka Hunter Holdings and MSI

On November 18, 2014, we 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, we 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, we entered into an additional letter agreement with Eureka Hunter Holdings and MSI (the "March 2015 Letter Agreement"), pursuant to which the parties agreed that, among other things, (i) we would no longer be 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 our 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 additional capital expenditures of Eureka Hunter Pipeline and for certain other uses.

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

Pursuant to the March 2015 Letter Agreement, we have the right, in our discretion, to fund as a capital contribution to Eureka Hunter Holdings, all or a portion (in specified minimum amounts) of our 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").  If we fund 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), we will own 46.44% and MSI will own 52.11% of the Class A Common Units of Eureka Hunter Holdings.

If we do not fund the full MHR Additional Contribution Component by the MHR Contribution Deadline, our 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 we do not fund any of the MHR Additional Contribution Component on or prior to the MHR Contribution Deadline, after giving effect to the adjustment described in the preceding sentence, we will own 44.53% and MSI will own 53.98% of the Class A Common Units of Eureka Hunter Holdings. If we fund a portion (in specified minimum amounts), but not all of the MHR Additional Contribution Component, on or prior to the MHR Contribution Deadline, then our ownership percentage and MSI's ownership percentage will be adjusted in a manner consistent with the first sentence of this paragraph (but with the downward adjustment for the Company being proportionately reduced).

If we make any capital contributions to Eureka Hunter Holdings prior to the MHR Contribution Deadline, those capital contributions will first be applied to the amount of the MHR Additional Contribution Component (in specified minimum amounts) until such aggregate additional capital contributions prior to the MHR Contribution Deadline equal the amount of the MHR Additional Contribution Component.

After the earlier to occur of (a) us having made contributions equal to the MHR Additional Contribution Component and (b) the MHR Contribution Deadline, we 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 us under the LLC Agreement.

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Amendments and Waivers to Credit Agreements

On February 24, 2015 and April 17, 2015,we entered into certain amendments and waivers with respect to the Credit Agreement and the Second Lien Term Loan Agreement.  These amendments and waivers are described in "First and Second Amendments to MHR Senior Revolving Credit Facility" and "Amendment to MHR Second Lien Credit Agreement".

Form S-3 Registration Statement

On March 13, 2015, we filed a universal shelf Form S-3 Registration Statement to register our sale of a maximum aggregate amount of up to $500 million of debt and equity securities. We 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, we entered into an "At the Market" Sales Agreement with a sales agent to conduct ATM offerings of our equity securities. As of May 8, 2015, we had sold an aggregate of 6,759,981 shares of our common stock for aggregate proceeds of $13.7 million net of sales commissions of $0.3 million through this ATM offering under the Form S-3 Registration Statement.

MNW Lease Acquisitions

On August 12, 2013, Triad Hunter entered into an asset purchase agreement with MNW Energy, LLC ("MNW"). MNW is an Ohio limited liability company that represents an informal association of various land owners, lessees and sub-lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the purchase agreement, Triad Hunter 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 closing, subject to certain conditions. The maximum purchase price, if MNW delivers 32,000 acres with acceptable title, would by $142.1 million, excluding title costs. During the three months ended March 31, 2015, Triad Hunter purchased 2,665 net leasehold acres from MNW for an aggregate purchase price of $12.0 million. As of March 31, 2015, Triad Hunter has 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 Triad Hunter 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 Triad Hunter.

Commodity Derivative Terminations

On May 7, 2015, we obtained consent under the MHR Senior Revolving Credit Facility to terminate our open commodity derivative positions, so long as all such terminations occur prior to the November 1, 2015 borrowing base redetermination. Such terminations have been contemplated by and are reflected in the May 1, 2015 borrowing base redetermination. Following the May 1, 2015 borrowing base redetermination, our borrowing base under the MHR Senior Revolving Credit Facility was maintained at $50 million. We expect to receive approximately $11.8 million in cash proceeds from the termination of the majority of our open commodity derivative positions that were terminated on May 7, 2015.

Oil, Natural Gas, and NGLs Prices

During the fourth quarter of 2014 and first quarter of 2015, 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 ("OPEC"). 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.

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Although our realized prices for natural gas increased slightly during the three months ended March 31, 2015, our realized prices for oil and NGLs declined compared to the three month period ended December 31, 2014. The declines in our realized prices is 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 15 months.

	Average Prices (U.S. Dollars)
	Three Months Ended
	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014		March 31, 2015
Oil (per Bbl)	$	83.14	$	97.13	$	90.55	$	58.79	$	30.16
Natural gas (per Mcf)	$	5.56	$	5.13	$	3.43	$	2.87	$	2.91
NGLs (per Mcfe)	$	9.53	$	9.29	$	6.88	$	6.34	$	4.25

Liquidity and Capital Resources

We generally rely on cash generated from operations, borrowings under our credit facilities, proceeds from sales of assets and proceeds from the sale of securities in the capital markets, when market conditions are favorable, to meet our liquidity needs.  Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our credit facilities, and, more broadly, on our ability to access the capital markets, all of which are affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.  We cannot predict whether additional liquidity from equity or debt financings beyond our credit facilities will be available, or available on acceptable terms, or at all, in the foreseeable future.

While we believe that our capital resources from 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, to the extent that we access such capital markets at opportune times, will be adequate to execute our corporate strategies and to meet debt service obligations 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 new and previously completed wells, which had been shut-in for a substantial portion of 2014 due to pad drilling. All of these wells are currently producing in early 2015. 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 compliance

As of March 31, 2015, the outstanding principal amount of our debt, gross of unamortized discounts, was $963 million, of which $10.2 million becomes due in the next twelve months, and we had a working capital deficiency of $114.2 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 of March 31, 2015, we were not 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 0.75 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 March 31, 2015 compliance period. In addition, we failed to comply with certain restricted debt provisions contained in both our revolving credit facility and our second lien term loan credit agreements related to the aging of payables. As more fully discussed in "First and Second Amendments to MHR Senior Revolving Credit Facility" and "Amendment to MHR Second Lien Credit Agreement", on and effective as of April 17, 2015, the Company entered into separate amendments to credit agreements and limited waivers to both our revolving credit facility and our second lien term loan, which among other things (i) provide a limited waiver to the current ratio and secured net debt to EBITDAX ratio for the March 31, 2015 compliance period under our revolving credit facility; (ii) extend the amount of

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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 May 29, 2015, after which date the restriction will revert back to 90 days. Additionally, the amendment and limited waiver under the revolving credit facility are conditioned upon the Company having received at least $65 million in aggregate net cash proceeds from specified liquidity transactions; the failure to satisfy this condition would result in an event of default under the revolving credit facility.

These amendments and waivers provide 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.

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:

i. 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;

ii. Conducting sales of assets, including selling a portion of our existing equity interest in Eureka Hunter Holdings;

iii. Issuing common stock through At-the-Market ("ATM") offerings or otherwise; and

iv. Entering into a joint venture under which we would sell or contribute all or a portion of our Utica Shale undeveloped leasehold acreage in Ohio to fund capital expenditures and provide working capital.

We are also currently engaged in discussions with third parties relating to the potential sale by the Company of certain undeveloped net leasehold acres located in Appalachia. The Company considers this acreage to be non-core to its current operations in this region. The Company expects that, if consummated, this specific transaction could generate cash proceeds to the Company of approximately $40 million to $65 million.

We believe that some or all of these transactions can be completed, including transactions necessary to provide up to the $65 million of net cash proceeds by May 29, 2015 required by the waiver and amendment to our revolving credit facility as described above. The Company believes that such transactions, if completed, could provide in excess of $200 million in cash proceeds.

We have an interest payment due on May 15, 2015 on our Senior Notes, which have an aggregate principal balance outstanding of $600 million as of March 31, 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 May 15, 2015 will be approximately $30 million, of which we had accrued $22 million as of March 31, 2015.

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 conditions to the payment of preferred stock dividends and the waivers set forth in the amendments and waivers to our revolving credit facility as described above.

Capital expenditures

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

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Average natural gas prices increased by 1.4% during the first quarter of 2015 compared to the fourth quarter of 2014, while compared to the first quarter of 2014, natural gas prices decreased by 47.7%. Additionally, prices for crude oil, from which we derived approximately 19.3% of our oil and natural gas revenues for the three months ended March 31, 2015, declined by 48.7% compared to the fourth quarter of 2014 and by 63.7% compared to the first quarter of 2014. While we still have exposure to crude oil market prices, our properties now produce predominantly natural gas and NGLs and sales from these products have become the largest component of our overall revenues in 2015 and going forward. These continued declines in market prices for commodities and certain natural gas transportation capacity restraints have resulted in an oversupply of natural gas in the Appalachian Basin, and have resulted in lower realized prices for the three months ended March 31, 2015 compared to prior periods. Although continued declines in market prices have affected our realized prices, we have not had to shut in production due to the economics of any of our wells during the three month period ended March 31, 2015.

We intend to fund our 2015 upstream capital budget, excluding any acquisitions, from a combination of internally-generated cash flows, borrowings under our revolving credit facility, proceeds from capital markets transactions, to the extent we access such capital markets at opportune times, and asset sales. Our upstream capital expenditure budget is based upon our plans to further explore and develop our oil and natural gas interests, but we have flexibility in the timing of a substantial portion of our discretionary capital spending. However, we are taking a more restrained approach to outlays of our capital expenditures in 2015, with an approved capital expenditure budget of up to $100 million. Consequently, market conditions may cause us to defer certain capital projects to future periods.

Our cash flow from operations is driven by commodity prices and production volumes and the effect of commodity derivatives. Prices for oil and natural gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Our working capital is significantly influenced by changes in commodity prices, which the Company manages using derivative instruments, and significant declines in prices will cause us to (i) decrease our production volumes, if continued production will not be profitable based on such prices, and (ii) decrease our exploration and development expenditures, which may adversely affect our production volumes.

We have historically utilized our revolving credit facility to fund a portion of our operating and capital needs, which facility is subject to periodic changes in the borrowing base based upon fluctuations in our proved reserves. As of March 31, 2015, we had outstanding borrowings of $5.0 million under our revolving credit facility, and our borrowing capacity has also been reduced by the amount of certain outstanding natural gas firm transportation letters of credit totaling $39.3 million. As a result, our borrowing capacity under the facility at March 31, 2015 was $5.7 million; however, we are constrained in the amount of additional indebtedness we may incur and still remain compliant with our proved reserves to secured debt ratio covenants required by our second lien term loan.

Upon the filing of our Annual Report on Form 10-K for the year ended December 31, 2014 we became unable to use our then effective universal shelf Form S-3 Registration Statement, which was filed as an automatic self registration statement, because the Company no longer met the criteria of a Well-Known Seasoned Issuer. Accordingly, on March 13, 2015 we filed a new 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, if market conditions at the time support such ATM transactions. As of May 8, 2015, the Company has sold an aggregate of 6,759,981 shares of its common stock and received aggregate proceeds of $13.7 million net of sales commissions of $0.3 million through its ATM offering under this Form S-3 Registration Statement.

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Liquidity Position

We define liquidity as funds available under our senior revolving credit facility plus year-end 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 March 31, 2015 compared to December 31, 2014:

	March 31, 2015			December 31, 2014
	(in thousands)
Borrowing base under MHR Senior Revolving Credit Facility	$	50,000		$	50,000
Cash and cash equivalents	13,653			53,180
Borrowings under MHR Senior Revolving Credit Facility	(5,000		)	—
Letters of credit issued	(39,261		)	(39,261		)
Liquidity	$	19,392		$	63,919

Sources of Cash

For the three months ended March 31, 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:

	Three Months Ended March 31,
	2015			2014
	(In thousands)
Cash flows provided by operating activities	$	48,136		$	3,877
Cash flows used in investing activities	(80,886		)	(22,819		)
Cash flows provided by (used in) financing activities	(6,799		)	41,656
Effect of foreign currency exchange rates	22			25
Net increase (decrease) in cash and cash equivalents	$	(39,527	)	$	22,739

Operating Activities

Our cash provided by operating activities was $48.1 million for the three months ended March 31, 2015, compared to $3.9 million for the three months ended March 31, 2014, an increase of $44.2 million or 1,139%.  The decrease in oil and natural gas sales due to lower prices received resulted in decreased cash available, which was offset by 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 three months ended March 31, 2015, was $80.9 million, principally from completion of new wells developed during 2014 in the Marcellus and Utica Shales which were turned to sales during the first quarter of 2015. This amount included the payment of expenditures previously accrued related to our 2014 capital expenditure program.

Our cash used in investing activities for the three months ended March 31, 2014 was $22.8 million, principally from drilling activities, and partially offset by the cash proceeds from the sale of assets of $16.4 million.

Financing Activities

Our cash used in financing activities for the three months ended March 31, 2015 was $6.8 million mainly due to the payment of preferred dividends of $8.8 million and repayments of debt of $3.1 million. These outflows were partially offset by borrowings against our revolving credit facility of $5.0 million during the three months ended March 31, 2015.

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Our cash provided by financing activities for the three months ended March 31, 2014 was $41.7 million, mainly from borrowings under the MHR Senior Revolving Credit Facility and the Eureka Hunter Pipeline Credit Agreement, as well as from proceeds from the issuance of shares of common stock. Our then majority owned subsidiary, Eureka Hunter Pipeline, paid in full and terminated its term loan with Pennant Park and borrowed $55.0 million from the Eureka Hunter Pipeline Credit Agreement executed in March 2014. In addition to debt financing arrangements, we raised $28.9 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through a private offering of 4,300,000 shares of our common stock.

2015 Capital Expenditures

The following table summarizes our actual capital expenditures (excluding acquisitions) for the three months ended March 31, 2015 and our capital budget for 2015.  We intend to fund the remainder of our 2015 capital expenditures, excluding any acquisitions, from a combination of internally-generated cash flows, borrowings under our revolving credit facility, proceeds from capital markets transactions, to the extent we access such capital markets at opportune times, and asset sales. A substantial portion of our capital expenditures are discretionary in nature, and we may need to exercise flexibility in the timing and extent of such expenditures as a result of market conditions to manage our needs.

	Capital Expenditures Incurred (1)		Capital Expenditure Budget
	Three Months Ended March 31, 2015		For the Year ending December 31, 2015
	(In thousands)
Exploration and Development Drilling Programs
Marcellus and Utica Shales	$	19,000	$	70,000
Williston Basin/Bakken Shale	11,200		10,000
Leasehold Acreage Acquisition
Marcellus and Utica Shales	17,000		20,000
Total capital expenditures	$	47,200	$	100,000

________________________________

(1) Capital expenditures on other property, plant, and equipment of approximately $2.0 million are not included in the summary above.

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.

Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. During 2015, we intend to reevaluate our upstream capital expenditure budget on a quarterly basis. We intend to limit capital spending to allow upstream oil and gas field service cost reductions to catch up with the dramatic drop in benchmark commodity prices that has occurred over the past several months. Therefore, we expect that the remainder of our 2015 upstream capital expenditures will occur during the second half of 2015. Additionally, the focus on minimizing capital spending may change throughout the year as we continue discussions with interested parties regarding potential joint venture opportunities to fund our exploration and development drilling activities in Ohio.

We expect that the 2015 capital expenditure requirements of Eureka Hunter Holdings will be funded primarily by cash flow from its midstream operations, borrowings under Eureka Hunter Pipeline's existing revolving credit facility and capital contributions provided by both the Company and MSI. See "First and Second Amendments to MHR Senior Revolving Credit Facilities" for a description of our revolving credit facility, including a description of the restrictions under that facility on our ability to make investments in Eureka Hunter Holdings.

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First and Second Amendments to MHR Senior Revolving Credit Facility

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. The current ratio requirement increases 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.

Under the MHR Senior Revolving Credit Facility, as amended, the Company is required to satisfy certain financial covenants, including maintaining:

i. commencing with the fiscal quarter ending June 30, 2015 and for each fiscal quarter ending thereafter, a current ratio (as defined in the Credit Agreement) of not less than 1.0 to 1.0;

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

iii. the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement (see "Note 8 - Debt").

In addition, pursuant to the First Amendment, 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 may 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 may 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 cannot 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) 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.

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 shall automatically increase by 1.00% and the commitment fee shall automatically increase by 0.25% and such elevated rates shall continue until the day immediately preceding the date on which the Adjusted Period ends. 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 preceding sentence.

On and effective as of April 17, 2015, the Company entered into a Second Amendment to Credit Agreement and Limited Waiver (the "Second Amendment") by and among the Company, as borrower, Bank of Montreal, as administrative agent, and the several lenders and guarantors party thereto. 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 date of invoice from 90 days to 180 days for any day on or prior to May 29, 2015, after which the date the restriction will revert back to 90 days.

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

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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, ATM offerings of equity securities of the Company, had been declared effective by 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 will be permitted provided the Company has 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 are 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 failure by the Company to satisfy this waiver condition will constitute an event of default under the Credit Agreement.

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.

Amendment to MHR Second Lien Credit Agreement

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"). The Second Lien Amendment amended the Second Lien Credit Agreement by permanently extending the amount of time the Company and its Restricted Subsidiaries (as defined in the Second Lien Credit Agreement) may have accounts payable outstanding after the date of invoice 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.

Operational Update - First Quarter 2015

During the three-month period ended March 31, 2015, we finalized completion activities on the WVDNR and Stalder pads in our shale resource plays in the Marcellus and Utica Shales. Production for the three month period ended March 31, 2015 increased to an average of 163.6 Mcfe/d compared to 98.6 Mcfe/d during the three month period ended March 31, 2014 as a result of the completion of additional wells on pads where previously producing wells had been shut in. As of March 31, 2015 the majority of significant unfinished drilling activities had been completed and 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 further evaluate the timing of additional drilling and completion activities based upon anticipated reductions in service costs and potential improvement in commodity prices.

The following section provides a summary of key operational developments during the first quarter of 2015 for our pads that have had significant development and completion activities over the past year.

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U.S. Upstream

Operated Properties

Marcellus Shale and Utica Shale

WVDNR Pad - On our WVDNR Pad located in Wetzel County, West Virginia, the WVDNR #1207, #1208, and #1209 wells (~100% working interest) began flowing to sales on April 2, 2014 and were subsequently shut-in on May 31, 2014 to prepare for drilling four additional down-dip laterals off the existing WVDNR pad. These four additional down-dip laterals, the WVDNR #1410, #1411, #1412, and #1413 (~100% working interest), were drilled and cased with an approximate true vertical depth of 7,500 feet in 2014. Following completion activities in early 2015, all the WVDNR wells were flowing to sales as of mid-February 2015.

Ormet Pad - On our Ormet Pad located in Monroe County, Ohio, being our second Ormet Pad, we have planned five down-dip Marcellus Share wells and four down-dip Utica Shale laterals. Initial plans are to drill three of the four Utica laterals to an average vertical depth of 11,100 feet with a 4,700 foot average horizontal lateral. Each of the Ormet #8-15UH, #9-15UH and #10-15UH (~100% working interest) have been drilled and cased to the 9 5/8” casing point at a vertical depth of approximately 10,600 feet. As of December 31, 2014, the Ormet #8-15UH was flowing to sales at a rate in excess of 5 MMcf/d with a flowing pressure of 4,050 psi on a natural completion (no fracture stimulation). However, this well is currently not producing as we await further completion activities in the second half of 2015.

Stalder Pad - On our Stalder Pad located in Monroe County, Ohio, the Stalder #2MH (50% working interest), our first Marcellus Shale well, was drilled and cased to a true vertical depth of 6,070 feet with a 5,474 foot horizontal lateral. We have also drilled and completed the Stalder #3UH (47% working interest), our fist dry gas well in the Utica Shale, to a true vertical depth of 10,653 feet with a 5,050 foot horizontal lateral, which was successfully fraced with 20 stages. Initial flow tests on the Stalder #3UH tested at a peak rate of 32.5 MMcf of natural gas per day (~5,400 Boe/d) on an adjustable rate choke with 4,300 psi FCP. Three additional down-dip Utica Shale laterals have been drilled off the Stalder Pad; the Stalder #6UH, #7UH, and #8UH (~47% working interest). These three wells have been drilled and cased to a true vertical depth of 10,660, with 24, 25, and 26 successful fracture stimulation stages completed, respectively. As of mid-February 2015 all wells on the Stalder Pad were flowing to sales.

Everett Weese Pad - On our Everett Weese Pad located in Tyler County, West Virginia, we drilled and completed three Marcellus Shale wells (~100% working interest), the Everett Weese #1107, #1108, and #1109. These three wells were shut-in during mid-July 2014 in preparation for drilling and completing two additional Marcellus Shale wells on the Everett Weese Pad. We drilled and completed the two additional Marcellus Shale wells, the Everett Weese #1414 and #1415 wells, in December 2014. All of these Everett Weese Pad wells were turned to sales in January 2015.

Stewart Winland Pad - On our Steward Winland Pad located in Tyler County, West Virginia, we drilled and cased three ~100% owned Marcellus Shale wells, the Stewart Winland #1301M, #1302M, and #1303M, to a true vertical depth of 6,155 feet with a 5,750 foot average horizontal lateral. We drilled and cased the Steward Winland #1300 well (100% working interest), our second dry gas Utica Shale well, to a true vertical depth of 10,825 feet with a 5,289 foot horizontal lateral. The Steward Winland #1300 tested at a peak rate of 46.5 MMcf of natural gas per day (~7,750 Boe/d) on an adjustable rate choke with 7,810 psi FCP. At March 31, 2015, all of the Stewart Winland wells were flowing to sales.

Farley Pad - On our Farley Pad located in Washington County, Ohio, we drilled and cased the Farley #1306H well in the Utica Shale to a true vertical depth of 7,850 feet with a 6,313 foot horizontal lateral. We have also drilled and cased the Farley #1304H well in the Utica Shale to a true vertical depth of 7,914 feet with a 5,400 foot horizontal lateral. These two wells, along with the Farley #1305H, drilled in 2013, are awaiting completion and evaluation. We expect to begin fracture stimulation of the Farley #1306H and #1304H wells in the second half of 2015 as part of our $100 million upstream capital expenditure budget.

Non-operated Properties

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

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Merlin Unit - The Merlin #10PPH Utica Shale lateral is being drilled and operated by EdgeMarc Energy. Triad Hunter owns a 13.56% working interest in the Merlin #10PPH. The Merlin #10PPH is located in Washington County, Ohio, approximately 5.1 miles southeast of Triad Hunter's Farley Pad. The Merlin #10PPH has an estimated true vertical depth of 8,050 feet and estimated lateral length of 7,200 feet. The estimated measured depth is 15,800 feet. The operator finished drilling and casing the well in August 2014. Fracture stimulation and initial flowback was completed in November 2014, and the well is currently awaiting connection to a sales flow line. The well was tested at a rate of 5,050 Mcf/d and 103 Bbl/d of condensate, with a flowing tubing pressure of 2,950 psi. This well is expected to be turned to production in April 2015.

Williston Basin/Bakken Shale

For the period ending March 31, 2015, Samson Resources Company ("Samson") has finished the completion of 7 gross (3.31 net) wells in Divide County, North Dakota. These 7 wells began flow back in early March with a combined average gross and net production of 3,798 Boe/d and 1,436 Boe/d, respectively. In light of our capital expenditure budget for Williston Basin and Bakken Shale, we have gone non-consent on the last 4 wells proposed by Samson at the end of 2014 and we will evaluate further projects in 2015 based upon our capital budget forecast and economics of each project.

A third-party has been engaged to gather and transport oil from certain of our non-operated wells in Divide County to the Colt Hub in Epping, North Dakota to eliminate trucking costs and minimize downtime during spring break-up. A truck terminal is expected to be constructed and connected to the gathering system to minimize oil hauling costs from wells not connected to the gathering system. All the equipment has been ordered and construction of the truck terminal started in October 2014. The facility is expected to be operational by mid-year 2015.

As of March 31, 2015, we have tied in approximately 4 of 8 producing wells into the Oneok gas gathering system.

U.S. Upstream Drilling and Capital Expenditures

In addition to the drilling and completion activities on our non-operated properties in the Williston Basin and Bakken Shale discussed above, a total of 7 gross (5.5 net) wells were turned to sales in the Utica Shale and Marcellus Shale, during the three-month period ended March 31, 2015

During the first half of the first quarter of 2015, we incurred related capital expenditures of $47.2 million comprised of $30.2 million in proved property additions, and $17.0 million in leasehold acquisitions. Much of the costs incurred related to the completion of wells developed during 2014 which were turned to sales during the first quarter of 2015. During the second half of the first quarter the Company suspended all drilling and completion operations to allow for service costs to decline and catch up with the current commodity pricing environment.

Eureka Hunter Holdings

We have a substantial equity investment in Eureka Hunter Holdings which we consider to be a strategic asset for the development and delineation of our acreage position in both the Utica Shale and Marcellus Shale plays. Eureka Hunter Pipeline, a wholly-owned subsidiary of Eureka Hunter Holdings, owns and operates the Eureka Hunter Gas Gathering System in West Virginia and Ohio. Given the substantial investment we continue to hold in Eureka Hunter Holdings and the importance the gas gathering assets of Eureka Hunter Pipeline have on our ongoing operations, we believe it is important to continue providing more informative details relative to the operational activities of Eureka Hunter Holdings and its subsidiaries.

On March 30, 2015, the Board of Managers of Eureka Hunter Holdings approved a capital budget for 2015 of $85.5 million in contemplation of certain growth opportunities.

Eureka Hunter Pipeline recently achieved a peak throughput rate of 623,713 MMBtu per day in March 2015. During the first quarter of 2015, Eureka Hunter's gas gathering pipeline system averaged 413,502 MMBtu per day. During the first quarter of 2015, Triad Hunter produced approximately 35.8% of the volumes that flowed through the Eureka Hunter Pipeline system.

Eureka Hunter Pipeline has turned on interconnects with Dominion Transmission, Rockies Express Pipeline, Spectra Energy, Blue Racer, and Blue Racer's Natrium plant, and has completed substantially all of the pipeline construction on the five distinct project fronts in which it was engaged during 2014, which include the Crescent Line, the REX-TEX, the Ormet Extension, the Stewart Winland, and the Mobley-TCO.

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Eureka Hunter Pipeline has recently completed its mainline compression effort and has lowered line pressures by approximately 150-200 psi across the system. This new compression will help to effect steady deliveries into MarkWest Energy Partners' Mobley gas processing facility. The reduced line pressure also helps producers move gas more easily into the Eureka Hunter Pipeline system. Eureka Hunter Pipeline is currently constructing a compressor station in Monroe County, Ohio that will move approximately 350,000 Mcf/d and is expandable to 1 Bcf/d, which will be in service by May 10, 2015.

Oilfield Services

Alpha Hunter Drilling

We own and operate portable, trailer-mounted drilling rigs capable of drilling to depths of between 6,000 to 19,000 feet, which are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin. The drilling rigs are used both for our Appalachian Basin operations and to provide drilling services to third parties. At March 31, 2015, our operating fleet consisted of five Schramm T200XD drilling rigs and one Schramm T500XD drilling rig.

As of March 31, 2015, four of the Schramm T200XD drilling rigs were under contract to EQT in the Appalachian Basin area for the top-hole drilling of multiple wells through December 2015. One Schramm T200XD drilling rig was previously contracted out on a project-by-project basis and is currently stacked. 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. All these contracts are term contracts. Rigs deployed under contracts with non-affiliated companies were running on contracted daily rates of $12,500 at March 31, 2015.

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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 months ended March 31, 2015 and 2014, respectively. The results of our Canadian operations 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.

	Three Months Ended   March 31,
	2015		2014
Oil and natural gas revenue and production
Revenues (in thousands, U.S. Dollars)
Oil	$	9,544	$	35,353
Natural gas	31,860		27,520
NGLs	7,987		13,092
Total oil and natural gas sales	$	49,391	$	75,965
Production
Oil (MBbl)	316		425
Natural gas (MMcf)	10,942		4,949
NGLs (MMcfe)	1,881		1,373
Total (MMcfe)	14,721		8,874
Mcfe/d	163,569		98,596
Average prices (U.S. Dollars)
Oil (per Bbl)	$	30.16	$	83.14
Natural gas (per Mcf)	$	2.91	$	5.56
NGLs (per Mcfe)	$	4.25	$	9.53
Total average price (per Mcfe)	$	3.36	$	8.56
Costs and expenses (per Mcfe)
Production costs	$	0.94	$	1.47
Severance tax and marketing	$	0.19	$	0.56
Transportation, processing, and other related costs	$	1.38	$	1.36
Exploration	$	0.58	$	1.79
Impairment of proved oil and natural gas property	$	0.94	$	1.89
Depletion, depreciation and accretion	$	3.92	$	3.31
General and administrative expense (1)	$	0.87	$	1.81
Other segments (in thousands)
Midstream natural gas gathering, processing and marketing revenues	$	458	$	31,723
Midstream natural gas gathering, processing and marketing expenses	$	494	$	29,999
Oilfield services revenues	$	4,865	$	5,621
Oilfield services expenses	$	4,211	$	3,947

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_________________________________

⁽¹⁾  General and administrative expense includes: (i) professional services expenses of $4.5 million ($0.30 per Mcfe) for the three months ended March 31, 2015 and $7.1 million ($0.80 per Mcfe) the three months ended March 31, 2014, and (ii) non-cash stock compensation of $3.2 million ($0.22 per Mcfe) for the three months ended March 31, 2015 and $1.1 million ($0.12 per Mcfe) for the three months ended March 31, 2014.

Three Months Ended March 31, 2015 and 2014

Oil and natural gas production.  Production increased by 65.9%, or 5,847 MMcfe, to 14,721 MMcfe for the three months ended March 31, 2015, compared to 8,874 MMcfe for the three months ended March 31, 2014. Our average daily production was 163,569 Mcfe/d during the 2015 period, representing an overall increase of 65.9%, or 64,973 Mcfe/d, compared to 98,596 Mcfe/d for the 2014 period. Natural gas production from the Appalachian Basin alone increased from 4,808 MMcf for the three months ended March 31, 2014 to 10,868 MMcf for the three months ended March 31, 2015, an increase of 126.0%. 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 three months ended March 31, 2015 was 316 MBbl versus 425 MBbl for the three months ended March 31, 2014, a decrease of 25.6%. Production of oil declined in 2015 as a result of our divestiture of non-core properties in the Williston/Bakken fields. Production from the Williston/Bakken fields decreased 31.6%, from 321 MBbl in oil production during the three months ended March 31, 2014 to 220 MBbl during the three months ended March 31, 2015.

Total production for the three months ended March 31, 2015, on an Mcfe basis, was 12.9% oil, 74.3% natural gas, and 12.8% NGLs compared to 28.7% oil, 55.8% natural gas, and 15.5% NGLs for the same period in 2014. 

Oil and natural gas sales.  Oil and natural gas sales decreased$26.6 million, or 35.0% for the three months ended March 31, 2015, to $49.4 million from $76.0 million for the three months ended March 31, 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 63.7%, 47.7%, and 55.4%, respectively. Our average realized natural gas price for three months ended March 31, 2015 was $2.91 per Mcf, a $0.04 positive differential to the average NYMEX price for the period primarily due to favorable pricing received for our natural gas sold through the Rockies Express interstate pipeline interconnect with the Eureka Hunter Pipeline System. Our average realized oil price for the three months ended March 31, 2015, was $30.16 per barrel, an $18.41 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, $55.7 million was attributable to decreases in prices received and was offset by an increase in production of $29.1 million. 

Midstream natural gas gathering, processing and marketing revenues.  During the three months ended March 31, 2014, the midstream operations segment consisted of Eureka Hunter Pipeline, TransTex, and Magnum Hunter Marketing operations. Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, we no longer hold a controlling financial interest in Eureka Hunter Holdings, of which Eureka Hunter Pipeline and TransTex are wholly-owned subsidiaries. The results of operations of Eureka Hunter Holdings, including Eureka Hunter Pipeline and TransTex, were included in our consolidated financial statements up to December 18, 2014. From December 18, 2014 and thereafter, the results of our midstream operations segment consist only of Magnum Hunter Marketing operations.

Revenue from the midstream operations segment decreased by $31.3 million, or 98.6%, for the three months ended March 31, 2015 to $0.5 million from $31.7 million for the three months ended March 31, 2014.  Of this decrease, $5.6 million relates to the decrease in revenues from Eureka Hunter Pipeline and TransTex due to the deconsolidation of Eureka Hunter Holdings. Magnum Hunter Marketing revenues decreased by $25.7 million to approximately $318,000 during the three months ended March 31, 2015 from $26.0 million during the three months ended March 31, 2014. Magnum Hunter Marketing revenues decreased 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.

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Oilfield services revenue.  Drilling services revenue decreased by $0.8 million, or 13.4%, for the three months ended March 31, 2015 to $4.9 million from $5.6 million for the three months ended March 31, 2014. This decrease was primarily attributable to lower utilization of the fleet of rigs caused by the downturn. During the three months ended March 31, 2015, our drilling rig revenue days decreased from 463 to 385 as compared to the three months ended March 31, 2014. For the three months ended March 31, 2015, the total effective equipment performance of our drilling rigs was 71%, and our rigs were 73% utilized. We have temporarily idled the largest drilling rig operating for Triad Hunter, a Schramm T500XD. However, four of our T200XD drilling rigs are deployed to a third party under firm contracts through the end of 2015. In addition, although our other T200XD drilling rig, which was under a pad-by-pad contract, is now being temporarily demobilized, we expect to utilize this rig as part of our top-hole drilling program during the second half of 2015. As a result, we do not expect any reduced capital spending by third party producers to have a material adverse effect on our oilfield services business during the remainder of 2015.

Gain (loss) on sale of assets.  We recorded a net gain on sale of assets in operating expenses of $1.7 million for the three months ended March 31, 2015, compared to a net loss on sale of assets of $4.1 million for the three months ended March 31, 2014. The gain on sale of assets during the three months ended March 31, 2015 consists primarily of 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 three months ended March 31, 2014, $3.9 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.

Production costs.  Our production costs increased $0.7 million, or 5.7% for the three months ended March 31, 2015, to $13.8 million ($0.94 per Mcfe) from $13.1 million ($1.47 per Mcfe) for the three months ended March 31, 2014.  The increase in production costs was comprised of $8.6 million attributable to increased production volumes offset by $7.8 million attributable to lower costs/Mcfe. Of the decrease in costs/Mcfe, $4.9 million was due to lower recurring costs in the Williston Basin, partially offset by a marginal increase in recurring costs of $0.5 million in the Appalachian Basin, and $3.4 million was due to lower non-recurring workover expenses primarily in the Williston Basin for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014.

Severance taxes and marketing.  Our severance taxes and marketing decreased$2.2 million, or 43.3%, for the three months ended March 31, 2015, to $2.8 million from $5.0 million for the three months ended March 31, 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 $8.3 million, or 69.0%, for the three months ended March 31, 2015 to $20.3 million ($1.38 per Mcfe) from $12.0 million ($1.36 per Mcfe) for the three months ended March 31, 2014. The increase was attributable primarily to increased natural gas and NGLs production from our Appalachian properties as additional wells began producing during 2015.

Exploration.  We record exploration costs, geological and geophysical costs, and unproved property impairments and leasehold expiration as exploration expense. We recorded $8.5 million of exploration expense for the three months ended March 31, 2015, compared to $15.9 million for the three months ended March 31, 2014.  During the 2015 period, the Company's exploration expense was primarily attributable to $7.6 million of leasehold impairments relating to leases in the Williston Basin region that expired undrilled during the three months ended March 31, 2015 or are expected to retire and that the Company does not plan to develop, and $0.2 million related to leases in the Appalachian Basin. The Company's exploration expense during the three months ended March 31, 2014 primarily related to $11.1 million of leasehold impairment related to leases in the Williston Basin and $4.5 million related to leases in the Appalachian Basin.

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

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During the three months ended March 31, 2015, we performed an impairment analysis and recorded impairment of proved oil and natural gas properties primarily related to the Appalachian Basin in continuing operations of $13.9 million to reduce the carrying value of these properties to their estimated fair values. 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 three months ended March 31, 2014, we recorded impairments on our proved oil and natural gas properties in western Kentucky of $16.8 million in order to reduce the carrying value of these properties owned by MHP to their estimated fair values, based upon developments in our marketing activities relating to MHP.

Midstream natural gas gathering, processing and marketing expenses. Expenses from the midstream operations decreased by $29.5 million, or 98.4% for the three months ended March 31, 2015, to $0.5 million from $30.0 million for the three months ended March 31, 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. Approximately $3.1 million of the decrease was due to decreased expenses from Eureka Hunter Pipeline and TransTex due to the deconsolidation of Eureka Hunter Holdings.

Oilfield services expenses.  Oilfield services expenses increased $0.3 million or 6.7% to $4.2 million for the three months ended March 31, 2015 from $3.9 million for the three months ended March 31, 2014. 

Depletion, depreciation, amortization, and accretion. Our DD&A increased $28.3 million, or 96.4%, to $57.8 million for the three months ended March 31, 2015, from $29.4 million for the three months ended March 31, 2014. Our DD&A/Mcfe increased by $0.61, or 18.4%, to $3.92 per Mcfe for the three months ended March 31, 2015, compared to $3.31 per Mcfe for the three months ended March 31, 2014.  These increases were due to increases in accumulated costs from our capital expenditure and acquisition programs during 2014, and increased production in 2015.

General and administrative.  Our G&A decreased$3.3 million, or 20.5%, to $12.8 million ($0.87 per Mcfe) for the three months ended March 31, 2015, from $16.1 million ($1.81 per Mcfe) for the three months ended March 31, 2014.  G&A expenses decreased overall mainly due to lower professional services expenses and salaries and personnel costs, partially offset by increases in non-cash stock compensation expense. Professional services expenses decreased by $2.6 million, to $4.5 million ($0.30 per Mcfe) for the three months ended March 31, 2015, from $7.1 million ($0.80 per Mcfe) for the three months ended March 31, 2014. Salaries and personnel costs decreased by $3.2 million, to $2.0 million ($0.13 per Mcfe) for the three months ended March 31, 2015, from $5.2 million ($0.59 per Mcfe) for the three months ended March 31, 2014. The decline in professional services expenses reflect lower legal costs, as well as a reduction in reliance on outside consultants and temporary staffing, and the lower salaries and personnel expenses reflect decreases due to the deconsolidation of Eureka Hunter Holdings, as well as our efforts to further reduce general and administrative expenses through the closing of our offices in Denver, Colorado and Calgary, Alberta, among other factors. Non-cash stock compensation expense increased by $2.1 million, to approximately $3.2 million ($0.22 per Mcfe) for the three months ended March 31, 2015, from $1.1 million ($0.12 per Mcfe) for the three months ended March 31, 2014.

Interest expense, net.  Our interest expense, net of interest income, decreased by 1.8%, to $23.4 million for the three months ended March 31, 2015, from $23.9 million for the three months ended March 31, 2014.  Our lower amortization and write-off of deferred financing costs accounted for $2.8 million of the decrease, offset by our higher average debt level which accounted for an increase of $2.4 million in the three months ended March 31, 2015 compared to the same period in 2014. We incurred a $2.2 million prepayment penalty through the early termination of credit agreements of Eureka Hunter Pipeline during the three months ended March 31, 2014. Interest expense was offset by capitalized interest of $0.6 million during the three months ended March 31, 2014, as part of the construction of Eureka Hunter Holdings' gas gathering system prior to the deconsolidation of Eureka Hunter Holdings on December 18, 2014. No interest was capitalized during the three months ended March 31, 2015. We capitalize interest on projects lasting six months or longer.

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Commodity and financial derivative activities.  Our commodity and financial derivative activity resulted in net gains of $3.1 million and $0.3 million for the three month periods ended March 31, 2015 and 2014, respectively. The following table summarizes the realized and unrealized gains and losses on change in fair value of our derivative contracts for the periods indicated:

	Three Months Ended   March 31,
	2015			2014
	(in thousands)
Commodity derivatives
Realized gain (loss) on settled transactions	$	4,311		$	(2,284	)
Unrealized loss on open contracts	(1,184		)	(3,261		)
Total commodity derivatives	3,127			(5,545		)
Financial derivatives
Gain (loss) on embedded derivatives	(25		)	5,892
Net gain	$	3,102		$	347

We do not designate our derivative instruments as hedges.

During the three months ended March 31, 2014, the Company had preferred stock embedded derivative liabilities resulting from certain conversion features, redemption options, and other features of our Eureka Hunter Holdings Series A Preferred Units. This embedded derivative instrument resulted in an unrealized gain of $5.9 million in the three months ended March 31, 2014. The Eureka Hunter Holdings Series A Preferred Units were converted at fair value to a new class of equity of Eureka Hunter Holdings on October 3, 2014, and the associated embedded derivative was extinguished upon conversion.

At March 31, 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. Unrealized losses of approximately $25,000 and $44,000 are recorded for this embedded derivative instrument in the three months ended March 31, 2015 and 2014, respectively. This derivative instrument originated in 2012 and has resulted in no cash outlays as of March 31, 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 on derivative contracts, net".

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 tax benefit.  We were in a net operating loss position as of March 31, 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 March 31, 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 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.

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The Company recognized no income or loss from discontinued operations for the three months ended March 31, 2015, compared to income of $3.4 million for the three months ended March 31, 2014. The following table summarizes the income from discontinued operations for the period indicated:

	Three Months Ended March 31,
	2014
	(in thousands)
Williston Hunter Canada	3,369
	$	3,369

Gain (loss) on disposal of discontinued operations, net of tax. The Company recognized no gain or loss on disposal of discontinued operations for the three months ended March 31, 2015 compared to a loss on disposal of discontinued operations of $8.5 million for the three months ended March 31, 2014. The following table summarizes the loss on disposal of discontinued operations for the period indicated:

	Three Months Ended March 31,
	2014
	(in thousands)
Eagle Ford Hunter	$	(4,319	)
Williston Hunter Canada	(4,194		)
	$	(8,513	)

Net loss attributable to non-controlling interest.  Net loss attributable to non-controlling interest of $0.1 million for the three months ended March 31, 2014 represented 2.5% of the net income or loss incurred by our then majority-owned subsidiary, Eureka Hunter Holdings and 12.5% of the gain 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 March 31, 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 ended March 31, 2015, and $14.9 million for the three months ended March 31, 2014. Dividends decreased between the comparable periods due to the conversion of the Eureka Hunter Holdings Series A Preferred Units into a new class of equity during the fourth quarter of 2014. The Series C Preferred Stock had a stated value of $100.0 million at both March 31, 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 March 31, 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 March 31, 2015 and December 31, 2014, and carries a cumulative dividend rate of 8.0% per annum.

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Related Party Transactions

The following table sets forth the related party transaction activities for the three months ended March 31, 2015 and 2014, respectively:

		Three Months Ended   March 31,
		2015		2014
		(in thousands)
GreenHunter
	Salt water disposal (1)	$	1,339	$	322
	Equipment rental (1)	$	45	$	122
	Gas gathering-trucking (1)	$	6	$	—
	Office space rental	$	4	$	22
	Interest income from note receivable (2)	$	31	$	45
	Dividends received from Series C shares (2)	$	55	$	55
	Unrealized gain/(loss) on investments (2)	$	376	$	235
Pilatus Hunter, LLC
	Airplane rental expenses (3)	$	11	$	70
Eureka Hunter (4)
	Transportation costs	$	5,606	$	—
	Disposal services	$	369	$	—
	Equipment rental	$	10	$	—
	Land usage fee	$	3	$	—
Classic Petroleum, Inc. (5)
	Land services	$	162	$	312

__________________________________

(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 $50,000, and $75,000 at March 31, 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".

(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 receives land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services.

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 is providing a 50% credit for all services performed under the agreement until the prepayment amount is utilized in full, which is anticipated to occur during the second half of 2015. As of March 31, 2015, the prepayment amount had been reduced to $461,000.

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As of March 31, 2015, the Company had a note receivable from GreenHunter with an outstanding principal balance of approximately $1.2 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 March 31, 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 three months ended March 31, 2015, the Company paid Mr. Trosclair $31,000, which includes reimbursement of expenses incurred on behalf of the Company and recognized $49,000 in stock compensation expense.

Commitments and Contractual Obligations

The following table presents our contractual obligations as of March 31, 2015:

Contractual Obligations	Total		2015		2016 - 2017		2018 - 2019		After 2019
Long-term debt (1)	$	963,317	$	7,701	$	18,075	$	334,715	$	602,826
Interest on long-term debt (2)	436,034		66,166		174,678		168,270		26,920
Gas transportation and compression contracts	164,226		11,100		29,545		29,522		94,059
Asset retirement obligations (3)	26,376		344		9,590		2,804		13,638
Operating lease obligations	1,919		619		1,093		207		—
Drilling rig installments	5,200		5,200		—		—		—
Total	$	1,597,072	$	91,130	$	232,981	$	535,518	$	737,443

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 March 31, 2015 on the debt facilities in place as of March 31, 2015. This results in a weighted average interest rate of 9.17%.

(3) See "Note 5 - Asset Retirement Obligations" to our consolidated financial statements for a discussion of our asset retirement obligations.

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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 similar to what was experienced during the first quarter of 2015.

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.

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.

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 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 March 31, 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.

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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.

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 flow 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 month period ended March 31, 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.  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 March 31, 2015, the Company had derivative instruments in place to reduce the price risk associated with future production of 11.0 Bcf of natural gas and 0.1 MMBbls of crude oil, representing a gross asset of $16.6 million and a gross liability of $1.3 million; or a net asset of $15.3 million. The table below shows the impact that a 10% increase or decrease in underlying commodity price index would have on the fair value of derivative instruments as of March 31, 2015:

	As of March 31, 2015
	Fair Value As Reported		Fair Value: 10% Price Increase			Fair Value: 10 % Price Decrease
	(in thousands)
Gas	$	14,319	$	11,574		$	17,066
Crude oil	1,007		935			1,046
Total Fair Value	$	15,326	$	12,509		$	18,112
Change in Fair Value			$	(2,817	)	$	2,786

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

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At March 31, 2015, we had the following commodity derivative positions outstanding:

			Weighted Average
Natural Gas	Period	MMBtu/day	Price per MMBtu
Swaps	Jan 2015 - Dec 2015	40,000	$4.09
			Weighted Average
Crude Oil	Period	Bbls/day	Price per Bbl
Collars (1)	Jan 2015 - Dec 2015	259	$85.00 - $91.25
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570	$120.00
Floors sold (put)	Jan 2015 - Dec 2015	259	$70.00

______________________________

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

At March 31, 2015, the fair value of our open commodity derivative contracts was an asset of $15.3 million.

The following table summarizes the gains and losses on settled and open commodity derivative contracts for the three months ended March 31, 2015 and 2014:

	Three Months Ended   March 31,
	2015			2014
	(in thousands)
Gain (loss) on settled transactions	$	4,312		$	(2,284	)
Loss on open transactions	(1,185		)	(3,261		)
Total gain (loss)	$	3,127		$	(5,545	)

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 less than $1,000 for the three months ended March 31, 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 March 31, 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 March 31, 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 March 31, 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

As disclosed in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" in Item 2. of this Quarterly Report on Form 10-Q, we are obligated to generate, by May 29, 2015, $65 million of net cash proceeds from certain specified liquidity transactions to avoid an event of default under our Credit Agreement and to be permitted to pay cash dividends on our preferred stock. We have already accomplished generating a portion of this required capital and we are actively pursuing certain liquidity enhancing transactions, as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." However, we cannot provide assurance as to whether or when we will be able to completely 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; maintain compliance with the financial covenants in our debt agreements; or satisfy the conditions to the payment of preferred stock dividends and the waivers set forth in the Second Amendment to our Credit Agreement.

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.

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Item 3.         Defaults upon Senior Securities

None.

Item 4.         Mine Safety Disclosures

Not applicable.

Item 5.         Other Information

None.

Item 6.        Exhibits

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

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SIGNATURES

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

	MAGNUM HUNTER RESOURCES CORPORATION
Date: May 11, 2015		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman and Chief Executive Officer
Date: May 11, 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+	Letter Agreement, dated March 30, 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 April 3, 2015).
10.1*	Letter Agreement, dated January 29, 2015, by and between Magnum Hunter Resources Corporation and R. Glenn Dawson (incorporated by reference from the Registrant's Annual Report on Form 10-K filed on March 2, 2015).
10.2*	Release and Confidentiality Agreement, dated January 29, 2015, by and between Magnum Hunter Resources Corporation and R. Glenn Dawson (incorporated by reference from the Registrant's Annual Report on Form 10-K filed on March 2, 2015).
10.3.1	First Amendment to Credit Agreement and Limited Waiver, dated February 24, 2015, by and among Magnum Hunter Resources Corporation, the guarantors party thereto, the lenders party thereto and Bank of Montreal (incorporated by reference from the Registrant's Annual Report on Form 10-K filed on March 2, 2015).
10.3.2	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).
10.4	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.
*	The referenced exhibit is a management contract, compensatory plan or arrangement.
+	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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