Magnum Hunter Resources 10-K 6 May 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Apr. 29, 2016	Jun. 30, 2015
Document And Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Entity Registrant Name	Magnum Hunter Resources Corp
Entity Central Index Key	1,335,190
Entity Filer Category	Accelerated Filer
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 385,477,813
Entity Common Stock, Shares Outstanding		260,563,308
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 40,871	$ 53,180
Oil and natural gas sales	20,578	21,514
Joint interests and other, net of allowance for doubtful accounts of $1,001 and $308 at December 31, 2015 and 2014, respectively	8,921	23,888
Related party	5,479	2,931
Derivative assets	0	16,586
Inventory	1,851	2,268
Investments	157	3,864
Prepaid expenses and other assets	5,691	4,091
Total current assets	83,548	128,322
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting	1,067,617	1,346,645
Accumulated depletion, depreciation, and accretion	(369,347)	(248,410)
Total oil and natural gas properties, net	698,270	1,098,235
Gas transportation, gathering and processing equipment and other, net	70,268	77,423
Total property, plant and equipment, net	768,538	1,175,658
OTHER ASSETS
Deferred financing costs, net of amortization of $15,099 as of December 31, 2014	0	22,856
Other assets	41,973	3,928
Investment in affiliates, equity method	166,099	347,191
Total assets	1,060,158	1,677,955
CURRENT LIABILITIES
Current portion of long-term debt	83,682	10,770
Debtor-in-possession financing	40,000	0
Accounts payable	7,215	135,697
Accounts payable to related parties	1,504	3,021
Accrued liabilities	12,029	20,277
Revenue payable	5	5,450
Other liabilities	1,465	1,356
Total current liabilities	145,900	176,571
Long-term debt, net of current portion	0	937,963
Asset retirement obligations, net of current portion	27,198	26,229
Other long-term liabilities	3,473	5,337
Total liabilities not subject to compromise	176,571	1,146,100
Liabilities subject to compromise	1,079,558	0
Liabilities subject to compromise - related party	16,513	0
Total liabilities subject to compromise	1,096,071	0
Total liabilities	$ 1,272,642	$ 1,146,100
COMMITMENTS AND CONTINGENCIES (Note 18)
SHAREHOLDERS' EQUITY:
Common stock	$ 2,614	$ 2,014
Additional paid in capital	975,041	909,783
Accumulated deficit	(1,602,235)	(784,546)
Accumulated other comprehensive income (loss)	(273)	(7,765)
Treasury Stock, at cost	(1,914)	(1,914)
Total shareholders' equity (deficit)	(312,484)	431,855
Total liabilities and shareholders’ equity	1,060,158	1,677,955
Series C Cumulative Perpetual Preferred Stock
REDEEMABLE PREFERRED STOCK
Redeemable preferred stock	100,000	100,000
Series D Cumulative Preferred Stock
SHAREHOLDERS' EQUITY:
Preferred stock	221,244	221,244
Series E Cumulative Convertible Preferred Stock
SHAREHOLDERS' EQUITY:
Preferred stock	95,069	95,069
Treasury Stock, at cost	$ (2,030)	$ (2,030)

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Accounts receivable, allowance for doubtful accounts (in dollars)	$ 308	$ 1,001	$ 308
Amortization of deferred financing costs (in dollars)	$ 15,099	$ 15,099	$ 15,099
Preferred Stock, shares authorized	10,000,000	10,000,000	10,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01
Common stock, shares authorized	350,000,000	350,000,000	350,000,000
Common stock, shares issued	201,420,701	261,397,232	201,420,701
Common stock, shares outstanding	200,505,749	260,482,280	200,505,749
Treasury stock, shares	914,952	914,952	914,952
Unearned common stock in KSOP	0	0	0
Series C Cumulative Perpetual Preferred Stock
Cumulative dividend rate for Series C Cumulative and Series A Convertible Preferred Stock (as a percent)		10.25%	10.25%
Preferred stock, shares authorized	4,000,000	4,000,000	4,000,000
Preferred stock, shares issued	4,000,000	4,000,000	4,000,000
Preferred Stock, shares outstanding	4,000,000	4,000,000	4,000,000
Preferred Stock, liquidation preference (in dollars per share)	$ 25	$ 25	$ 25
Cumulative dividend rate for cumulative preferred stock (as a percent)		10.25%
Series D Cumulative Preferred Stock
Preferred Stock, shares authorized	5,750,000	5,750,000	5,750,000
Cumulative dividend rate for cumulative preferred stock (as a percent)	8.00%	8.00%	8.00%
Preferred Stock, shares issued	4,424,889	4,424,889	4,424,889
Preferred Stock, shares outstanding	4,424,889	4,424,889	4,424,889
Preferred Stock, liquidation preference (in dollars per share)	$ 50	$ 50	$ 50
Series E Cumulative Convertible Preferred Stock
Preferred Stock, shares authorized	12,000	12,000	12,000
Cumulative dividend rate for cumulative preferred stock (as a percent)		8.00%	8.00%
Preferred Stock, shares issued	3,803	3,803	3,803
Preferred Stock, shares outstanding	3,722	3,722	3,722
Preferred Stock, liquidation preference (in dollars per share)	$ 25,000	$ 25,000	$ 25,000
Treasury stock, shares	81	81	81

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES AND OTHER
Oil and natural gas sales		$ 133,448	$ 268,501	$ 220,699
Midstream natural gas gathering, processing, and marketing		1,067	97,916	61,178
Oilfield services		18,229	23,134	18,431
Other revenue		1,380	1,918	4,230
Total revenue		154,124	391,469	304,538
OPERATING EXPENSES
Production costs		40,074	47,857	46,689
Severance taxes and marketing		6,917	17,344	18,282
Transportation, processing, and other related costs		65,606	43,292	22,549
Exploration		59,831	118,509	100,389
Midstream natural gas gathering, processing, and marketing		668	84,764	52,099
Oilfield services		13,984	15,686	14,825
Impairment of proved oil and gas properties		275,375	301,276	50,011
Depreciation, depletion, amortization and accretion		132,804	146,868	107,385
(Gain) loss on sale of assets, net		(31,358)	(2,456)	44,641
Loss on abandonment of drilling rig in progress		4,049	0	0
General and administrative	[1]	47,260	108,687	82,461
Total operating expenses		615,210	881,827	539,331
OPERATING LOSS		(461,086)	(490,358)	(234,793)
OTHER INCOME (EXPENSE)
Interest income		157	156	265
Interest expense		(99,559)	(86,463)	(72,621)
Gain (loss) on derivative contracts, net		4,886	(72,254)	(25,274)
Gain on deconsolidation of Eureka Midstream Holdings, LLC		0	509,563	0
Gain on dilution of interest in Eureka Midstream Holdings, LLC		4,601	0	0
Loss from equity method investments		(186,157)	(1,038)	(994)
Other income (expense)		(5,575)	2,561	15,897
Total other income (expense), net		(281,647)	352,525	(82,727)
LOSS FROM CONTINUING OPERATIONS PRIOR TO REORGANIZATION ITEMS AND INCOME TAX		(742,733)	(137,833)	(317,520)
Reorganization items, net		(41,139)	0	0
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(783,872)	(137,833)	(317,520)
Income tax benefit		0	0	85,407
LOSS FROM CONTINUING OPERATIONS, NET OF TAX		(783,872)	(137,833)	(232,113)
Income (loss) from discontinued operations, net of tax		0	4,561	(62,561)
Gain (loss) on disposal of discontinued operations, net of tax		0	(13,855)	71,510
NET LOSS		(783,872)	(147,127)	(223,164)
Net loss attributable to non-controlling interests		0	3,653	988
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION		(783,872)	(143,474)	(222,176)
Dividends on preferred stock		(33,817)	(54,707)	(56,705)
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units		0	(51,692)	0
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ (817,689)	$ (249,873)	$ (278,881)
Weighted average number of common shares outstanding, basic and diluted		225,458,301	189,135,500	170,088,108
Loss from continuing operations per share, basic and diluted		$ (3.63)	$ (1.27)	$ (1.69)
Income (loss) from discontinued operations per share, basic and diluted		0	(0.05)	0.05
NET LOSS PER COMMON SHARE, BASIC AND DILUTED		$ (3.63)	$ (1.32)	$ (1.64)
Loss from continuing operations, net of tax		$ (783,872)	$ (134,180)	$ (231,125)
Income (loss) from discontinued operations, net of tax		0	$ (9,294)	$ 8,949
Non-cash loss, downward adjustment of equity interests		$ 32,600
[1]	2014 includes the recognition of a $32.6 million non-cash loss related to the downward adjustment of the Company’s equity interest in Eureka Midstream Holdings, LLC related to excess capital expenditures in 2014. See “Note 4 - Eureka Midstream Holdings” in the accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
NET LOSS	$ (783,872)	$ (147,127)	$ (223,164)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation gain (loss)	99	(1,204)	(10,928)
Unrealized gain (loss) on available for sale securities	(2,771)	(7,401)	8,178
Amounts reclassified for other than temporary impairment of available for sale securities	10,183	0	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(19)	0	(8,262)
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	0	20,741	0
Total other comprehensive income (loss)	7,492	12,136	(11,012)
COMPREHENSIVE LOSS	(776,380)	(134,991)	(234,176)
Comprehensive loss attributable to non-controlling interests	0	3,653	988
COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	$ (776,380)	$ (131,338)	$ (233,188)

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Exchangeable Common Stock	Additional Paid in Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Non-controlling Interest	Series D Preferred Stock	Series D Preferred StockPreferred Stock	Series E Preferred StockPreferred Stock
BALANCE (in shares) at Dec. 31, 2012		170,033,000	506,000							4,209,000	4,000
BALANCE at Dec. 31, 2012	$ 711,652	$ 1,700	$ 5	$ 715,033	$ (307,484)	$ (8,889)	$ (3,664)	$ 10,139		$ 210,441	$ 94,371
Increase (Decrease) in Shareholders' Equity
Share based compensation (in shares)		183,000
Share based compensation	13,624	$ 2		13,622
Issued shares as Employer Match on 401K (in shares)		221,000
Issued shares as Employer Match on 401K	1,192	$ 2		1,190
Issued shares of Preferred Stock for Cash (in cash)		0								216,000	0
Issued shares of Preferred Stock for cash	10,181			(1,320)						$ 10,803	$ 698
Preferred dividends	(56,705)				(56,705)
Conversion of exchangeable common stock for common stock (shares)		506,000	(506,000)
Conversion of exchangeable common stock for common stock	0	$ 5	$ (5)
Shares of common stock issued upon exercise of common stock options (in shares)		1,466,000
Shares of common stock issued upon exercise of common stock options	5,352	$ 15		5,337
Net income (loss)	(223,164)				(222,176)			(988)
Foreign currency translation	(10,928)					(10,928)
Unrealized gain on available for sale securities	(84)					(84)
Depositary shares representing Series E Preferred Stock returned from escrow							(280)
Other	(1)							(1)
Fees on equity issuance	(109)
Amounts reclassified for other than temporary impairment of available for sale securities	0
BALANCE at Dec. 31, 2013	450,730	$ 1,724	$ 0	733,753	(586,365)	(19,901)	(3,944)	9,150		$ 221,244	$ 95,069
BALANCE (in shares) at Dec. 31, 2013		172,409,000	0							4,425,000	4,000
Increase (Decrease) in Shareholders' Equity
Share based compensation (in shares)		657,000
Share based compensation	11,363	$ 7		11,356
Issued shares as Employer Match on 401K (in shares)		250,000
Issued shares as Employer Match on 401K	1,593	$ 2		1,591
Issued shares of Preferred Stock for Cash (in cash)		1,000
Issued shares of Preferred Stock for cash	5			5
Preferred dividends	(54,707)				(54,707)
Issued shares of stock for cash (in shares)		25,729,000							216,068
Issued shares of Common Stock for cash	178,410	$ 257		178,153
Shares of common stock issued upon exercise of common stock options (in shares)		2,375,000
Shares of common stock issued upon exercise of common stock options	9,663	$ 24		9,639
Repurchase of non-controlling interest		0	$ 0	(5,111)				2,236
Net income (loss)	(147,127)				(143,474)			(3,653)
Foreign currency translation	(1,204)					(1,204)
Unrealized gain on available for sale securities	(7,401)					(7,401)
Depositary shares representing Series E Preferred Stock returned from escrow	(280)
Extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units	337,543							389,235
Forfeiture of Eureka Midstream Holdings, LLC Series A-1 Units				32,569			0
Issuance of Eureka Midstream Holdings, LLC Series A-2 Units	40,000							40,000
Fees on equity issuance				(109)
Deconsolidation of Eureka Midstream Holdings, LLC	(436,968)							(436,968)
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	20,741					20,741
Amounts reclassified for other than temporary impairment of available for sale securities	0
BALANCE at Dec. 31, 2014	431,855	$ 2,014	$ 0	909,783	(784,546)	(7,765)	(3,944)	0		$ 221,244	$ 95,069
BALANCE (in shares) at Dec. 31, 2014		201,421,000	0							4,425,000	4,000
Increase (Decrease) in Shareholders' Equity
Share based compensation (in shares)		1,383,000
Share based compensation	5,700	$ 14		5,686
Issued shares as Employer Match on 401K (in shares)		2,291,000
Issued shares as Employer Match on 401K	1,878	$ 23		1,855
Preferred dividends	(33,817)				(33,817)
Issued shares of stock for cash (in shares)		56,202,000
Issued shares of Common Stock for cash	58,229	$ 562		57,667						$ 0	$ 0
Shares of common stock issued upon exercise of common stock options (in shares)		100,000
Shares of common stock issued upon exercise of common stock options	51	$ 1		50
Repurchase of non-controlling interest	(2,875)
Net income (loss)	(783,872)				(783,872)			0
Foreign currency translation	99					99
Unrealized gain on available for sale securities	(2,771)					(2,771)
Extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units				(51,692)
Forfeiture of Eureka Midstream Holdings, LLC Series A-1 Units	32,569							0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(19)					(19)
Amounts reclassified for other than temporary impairment of available for sale securities	10,183					10,183
BALANCE at Dec. 31, 2015	$ (312,484)	$ 2,614	$ 0	$ 975,041	$ (1,602,235)	$ (273)	$ (3,944)	$ 0		$ 221,244	$ 95,069
BALANCE (in shares) at Dec. 31, 2015		261,397,000	0							4,425,000	4,000

CONSOLIDATED STATEMENTS OF SHA7

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2013USD ($)shares
Statement of Stockholders' Equity [Abstract]
Warrants issued for payment of dividend | shares	17,030,622
Warrants for payment of dividends on common stock, fair market value (in dollars) | $	$ 21.6

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
NET LOSS	$ (783,872)	$ (147,127)	$ (223,164)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	132,804	146,868	134,867
Share-based compensation	7,578	12,469	13,624
Impairment of proved oil and gas properties	275,375	301,276	89,041
Exploration	57,521	116,945	115,069
Impairment of other assets	10,183	730	0
Loss on abandonment of drilling rig in progress	4,049	0	0
Loss (gain) on sale of assets	(31,358)	11,399	(7,318)
Cash paid for plugging wells	(346)	(107)	(14)
Gain on deconsolidation of Eureka Midstream Holdings	0	(509,563)	0
Loss from capital account adjustment of Eureka Midstream Holdings	0	32,569	0
Gain on dilution of interest in Eureka Midstream Holdings	(4,601)	0	0
Loss from equity method investments	186,157	1,038	994
Loss (gain) on derivative contracts	(4,886)	(19,538)	25,274
Cash proceeds (payment) on settlement of derivative contracts	21,471	1,306	(8,216)
Loss on extinguished embedded derivative	0	91,792	0
Unrealized loss (gain) on investments	(67)	0	(8,003)
Amortization and write off of deferred financing cost and discount on Senior Notes included in interest expense	9,907	9,679	4,836
Deferred tax benefit	0	0	(84,527)
Noncash reorganization items	27,985	0	0
Changes in operating assets and liabilities:
Accounts receivable, net	14,103	8,533	22,781
Inventory	427	4,381	4,658
Prepaid expenses and other current assets	(2,150)	(3,071)	(1,073)
Accounts payable	64,526	(51,930)	42,050
Revenue payable	(173)	(2,953)	(11,589)
Accrued liabilities	40,393	(23,361)	2,421
Net cash provided by (used in) operating activities	25,026	(18,665)	111,711
CASH FLOWS FROM INVESTING ACTIVITIES
Change in restricted cash	0	5,000	(3,500)
Capital expenditures and advances	(167,545)	(562,324)	(631,511)
Deconsolidation of the cash of Eureka Midstream Holdings	0	(6,380)	0
Proceeds from sale of assets	39,219	193,139	506,297
Proceeds from partial sale of equity interest in Eureka Midstream Holdings	0	55,000	0
Change in deposits and other long-term assets	(37,615)	(2,554)	854
Net cash used in investing activities	(165,941)	(318,119)	(127,860)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings on debt	76,886	629,392	373,991
Proceeds from borrowings on debtor-in-possession financing	40,000	0	0
Principal repayments of debt	(16,192)	(467,745)	(380,923)
Proceeds from sale of Series A preferred units in Eureka Midstream Holdings	0	11,956	35,280
Issue Series A Common units of Eureka Midstream Holdings, net of costs	0	8,180	0
Issue Series A-2 Units of Eureka Midstream Holdings, net of costs	0	40,000	0
Net proceeds from sale of common stock	58,229	178,410	0
Net proceeds from sale of preferred shares	0	0	10,072
Net proceeds from sale of preferred shares	0	(2,875)	0
Proceeds from exercise of warrants and options	51	9,663	5,352
Change in other long-term liabilities	25	1,023	(1,222)
Payment of deferred financing costs	(3,823)	(14,208)	(1,246)
Preferred stock dividends paid	(26,542)	(45,601)	(40,648)
Net cash provided by financing activities	128,634	348,195	656
Effect of foreign exchange rate changes on cash	(28)	56	(417)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(12,309)	11,467	(15,910)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	53,180	41,713	57,623
CASH AND CASH EQUIVALENTS, END OF YEAR	$ 40,871	$ 53,180	$ 41,713

ORGANIZATION AND NATURE OF OPER

ORGANIZATION AND NATURE OF OPERATIONS	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND NATURE OF OPERATIONS	NOTE 1 - ORGANIZATION AND NATURE OF OPERATIONS Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter” or the “Company”), is an Irving, Texas based independent oil and gas company engaged primarily in the exploration for and the exploitation, acquisition, development and production of natural gas and natural gas liquids resources predominantly in specific shale plays in the United States, along with certain oil field service activities and a substantial equity method investment in a midstream operation. Chapter 11 Bankruptcy Filings On December 15, 2015 (the “Petition Date”), Magnum Hunter Resources Corporation and certain of its wholly owned subsidiaries, namely, Alpha Hunter Drilling, LLC (“Alpha Hunter Drilling”), Bakken Hunter Canada, Inc. (“Bakken Hunter Canada”), Bakken Hunter, LLC (“Bakken Hunter”), Energy Hunter Securities, Inc., Hunter Aviation, LLC, Hunter Real Estate, LLC, Magnum Hunter Marketing, LLC (“Magnum Hunter Marketing”), Magnum Hunter Production, Inc. (“MHP”), Magnum Hunter Resources GP, LLC, Magnum Hunter Resources, LP, Magnum Hunter Services, LLC, NGAS Gathering, LLC, NGAS Hunter, LLC (“NGAS Hunter”), PRC Williston LLC (“PRC Williston”), Shale Hunter, LLC (“Shale Hunter”), Triad Holdings, LLC, Triad Hunter, LLC (“Triad Hunter”), Viking International Resources Co., Inc. (“VIRCO”), and Williston Hunter ND, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Chapter 11 cases (the “Chapter 11 Cases”) are being jointly administered by the Bankruptcy Court under the caption In re Magnum Hunter Resources Corporation, et al. , Case No. 15-12533. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Company’s subsidiaries and affiliates excluded from the Chapter 11 Cases include wholly owned subsidiaries Magnum Hunter Management, LLC, Sentra Corporation, 54NG, LLC, and the Company’s 44.53% owned affiliate, Eureka Midstream Holdings, LLC, formerly known as Eureka Hunter Holdings, LLC (“Eureka Midstream Holdings”) (collectively, the “Non-Debtors”). See “Note 3 - Voluntary Reorganization under Chapter 11” for a discussion of the Chapter 11 Cases. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s payment obligations under its then outstanding debt obligations. The Company has classified all such debt as “ Current portion of long-term debt ” or “ Liabilities subject to compromise ”, as applicable, in the consolidated balance sheet as of December 31, 2015. See “Note 3 - Voluntary Reorganization under Chapter 11” for a discussion of liabilities subject to compromise. For additional description of the defaults present under the Company’s debt obligations, see “Note 11 - Long-Term Debt” . On April 18, 2016, the Bankruptcy Court approved the Company’s Chapter 11 plan of reorganization (as amended, the “Plan”), which, among other things, resolved the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity, and provided for corporate governance subsequent to exit from bankruptcy. The effective date of the Plan is expected to be May 6, 2016. Upon emergence from bankruptcy, the Company expects to apply fresh start accounting. Accordingly, the Company expects to make adjustments to the carrying values and classification of its assets and liabilities, and such adjustments could be material.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Presentation of Consolidated Financial Statements The consolidated financial statements include the accounts of the Company and entities in which it holds a controlling financial interest. The Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions have been eliminated. The consolidated financial statements have been prepared in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852, Reorganizations . This guidance requires that transactions and events directly associated with the Chapter 11 reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. See “Note 3 - Voluntary Reorganization under Chapter 11” . The Company deconsolidates entities in which it no longer holds a controlling financial interest as of the date control is lost. The results of operations and assets and liabilities of deconsolidated entities are included in the Company’s consolidated financial statements with all significant intercompany balances eliminated through the date of deconsolidation. Subsequently, retained interests in an entity, if any, are accounted for based on the nature of the retained interest in accordance with GAAP. The consolidated financial statements also reflect the interests of the Company’s wholly owned subsidiary, MHP, in various managed drilling partnerships. The Company accounts for the interests in these managed drilling partnerships using the proportionate consolidation method. Use of Estimates in the Preparation of Financial Statements Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant recurring items subject to such estimates and assumptions include those related to stock based compensation, the valuation of commodity and financial derivative instruments, embedded derivative assets and liabilities, asset retirement obligations and other liabilities and whether declines in the value of investments are other than temporary. The estimates of proved, probable and possible oil and gas reserves are used as significant inputs in determining the depletion of oil and gas properties and the impairment of proved and unproved oil and gas properties. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. The determination of whether declines in the value of investments are other than temporary involves the consideration of many factors including, but not limited to, the length of time and the extent to which market value has been less than cost, the financial condition and near-term prospects of the investee, and the intent and ability of the Company to retain its investment for a period of time sufficient to allow for any anticipated recovery in market value. Evaluating these factors requires significant judgment. Non-recurring items subject to significant estimates include the fair value of the Company’s retained financial interest in equity method investees and liabilities subject to compromise. Actual results could differ from the estimates and assumptions utilized. Non-Controlling Interest in Consolidated Subsidiaries 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 its previously consolidated affiliate, Eureka Midstream Holdings. Accordingly, the results of operations of Eureka Midstream Holdings were consolidated in the accompanying consolidated financial statements up to December 18, 2014. The Company held a 48.6% equity interest in Eureka Midstream Holdings at December 18, 2014 and December 31, 2014, and held a 44.5% equity interest at December 31, 2015. The Company accounts for this retained interest under the equity method of accounting with the Company’s share of Eureka Midstream Holdings’ earnings recorded in “Loss from equity method investment” in the accompanying consolidated statements of operations. See “Note 4 - Eureka Midstream Holdings” and “Note 10 - Investments and Derivatives” . Prior to July 24, 2014, the Company owned 87.5% of the equity interests in PRC Williston, which sold substantially all of its assets on December 30, 2013. On July 24, 2014, the Company executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a/ D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, the Company owns 100% of the equity interests in PRC Williston and has all rights and claims to its remaining assets and liabilities, which are not significant. The net loss attributable to non-controlling interest for PRC Williston is recorded through July 24, 2014. Changes in the non-controlling interests attributable to entities in which the Company held a controlling financial interest were accounted for as equity transactions, as they were considered investments by owners and distributions to owners acting in their capacity as owners. No gains or losses were recognized as the carrying value of the non-controlling interest was adjusted to reflect the change in the Company’s ownership interest in the subsidiary. Reclassification of Prior-Year Balances Certain prior period balances have been reclassified to correspond with current-period presentation. The Company has reclassified approximately $5.2 million of oil and gas transportation, processing and production tax payables from “Accounts receivable: oil and natural gas sales” to “Accounts payable” as of December 31, 2014 in the accompanying consolidated balance sheets. Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, notes receivable, payables and accrued liabilities, derivatives, and certain long-term debt instruments approximate fair value as of December 31, 2015 and 2014 . See “Note 9 - Fair Value of Financial Instruments”. Cash and Cash Equivalents Cash and cash equivalents include cash in banks and highly liquid investment securities that have original maturities of three months or less. At December 31, 2015 , the Company had cash deposits in excess of FDIC insured limits at various financial institutions. The Company has not experienced any losses in such accounts. Accounts Receivable The Company’s share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. Accounts receivable (oil and natural gas sales) consist of accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. At December 31, 2015 and 2014 , the Company did not have any allowance for doubtful accounts with respect to its oil and natural gas sales accounts receivable. Accounts receivable from joint interest owners and other consists primarily of joint interest owner obligations due within 30 days of the invoice date. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible. At December 31, 2015 and 2014 , the Company had approximately $1.0 million and $308,000 , respectively, in allowances for doubtful accounts with respect to its joint interest accounts receivable. Commodity and Financial Derivative Instruments At various times, the Company has used commodity and financial derivative instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices. Freestanding derivative instruments are recorded at fair value in the consolidated balance sheets as either an asset or liability, with those contracts maturing in the next twelve months classified as current, and those maturing thereafter as long-term. The Company recognizes changes in the fair value of derivatives in earnings, as it has not designated its oil and gas price derivative contracts as cash flow hedges. The Company recognizes the gains and losses on settled and open transactions on a net basis within the “Gain (loss) on derivative contracts, net” line item within the “Other Income (Expense)” section of the consolidated statements of operations. The Company may be party to contracts or purchase certain investments that contain embedded derivatives. If an embedded derivative is not clearly and closely related to the host contract, and as a separate instrument would qualify as a derivative, the derivative is separated from the host contract, held at fair value and reported separately from the host instrument in the consolidated balance sheets. The Company recognizes changes in the fair value of bifurcated derivatives in “ Gain (loss) on derivative contracts, net ”. Investments in Affiliates, Equity Method Investments in non-controlled affiliates over which the Company is able to exercise significant influence but not control are accounted for under the equity method of accounting. Under the equity method of accounting, the Company’s share of the investee’s underlying net income or loss is recorded as earnings (loss) from equity method investment. Distributions received from the investment reduce the Company’s investment balance. When an investee accounted for using the equity method issues its own equity or when the Company sells a portion of its interest in the investee that results in a reduction in the Company’s interest in the investee, a gain or loss is recognized equal to the proportionate change in the Company’s interest in the investee’s net assets. Investments in equity method investees are evaluated for impairment as events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If a decline in the value of an equity method investment is determined to be other-than-temporary, a loss is recorded. The Company evaluated its investment in Eureka Midstream Holdings and determined that while the investment had declined in value, the decline was not other-than-temporary; and no impairment was required as of December 31, 2015 . Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, the Company remeasured its retained interest in Eureka Midstream Holdings at fair value in accordance with the derecognition provisions of ASC Topic 810, Consolidation . See “Note 4 - Eureka Midstream Holdings” and “Note 9 - Fair Value of Financial Instruments” . Effective June 2015, the Company reclassified its equity method investment in Eureka Midstream Holdings to assets of discontinued operations. As of November 3, 2015, the Company determined that the planned divestiture no longer met the criteria for classification as a discontinued operation, and remeasured the carrying value of its equity method investment in Eureka Midstream Holdings at fair value. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” and “Note 9 - Fair Value of Financial Instruments” . Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip new development wells and related asset retirement costs are capitalized. Costs to acquire mineral interests and drill exploratory wells are also capitalized pending determination of whether the wells have proved reserves or not. If the Company determines that the wells do not have proved reserves, the costs are charged to exploration expense. Geological and geophysical costs, including seismic studies and related costs of carrying and retaining unproved properties are charged to exploration expense as incurred. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization as a normal retirement with no resulting gain or loss recognized in income if the amortization rate is not significantly affected; otherwise it is accounted for as the sale of an asset and a gain or loss is recognized. Leasehold costs attributable to proved oil and gas properties are depleted by the unit-of-production method over total proved reserves. Capitalized development costs are depleted by the unit-of-production method over proved developed producing reserves. Unproved oil and gas leasehold costs that are individually significant are periodically assessed for impairment of value by comparing current quotes and recent acquisitions, future lease expirations, and taking into account management’s intent, and a loss is recognized at the time of impairment by providing an impairment allowance recognized in “Exploration” expense in the consolidated statements of operations. Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment quarterly based on an analysis of undiscounted future net cash flows of proved and risk-adjusted probable and possible reserves. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows and other relevant market value data. Impairment of proved oil and gas properties is calculated on a field by field basis. It is common for operators of oil and gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically a provision of the joint operating agreement that working interest owners in a property adopt. The Company records these advance payments in the property accounts. If a lease associated with an unproved property expires without identifying proved reserves, the cost of the property is charged to the impairment allowance. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. If the Company sells its entire interest in an unproved property, the cost of the property and any proceeds received from the sale are charged to “ (Gain) loss on sale of assets, net ” in the consolidated statements of operations. The estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower market commodity prices, which may make it uneconomic to drill for and produce due to higher-cost fields. Gas Transportation, Gathering and Processing Equipment and Other The Company’s gas gathering system assets and field servicing assets are carried at cost. 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. Depreciation of gas gathering system assets is provided using the straight line method over an estimated useful life of fifteen years. Depreciation of field servicing assets is provided using the straight line method over various useful lives ranging from three to ten years. Gain or loss on retirement or sale of assets is included in “ (Gain) loss on sale of assets, net ” in the period of disposition or retirement. Furniture, fixtures and other equipment are carried at cost. Depreciation of furniture, fixtures and other equipment is provided using the straight-line method over estimated useful lives ranging from five to fifteen years. Gain or loss on retirement or sale of assets is included in “ (Gain) loss on sale of assets, net ” in the period of disposition or retirement. Deferred Financing Costs The Company may, from time to time, enter into or modify certain debt arrangements such as senior debentures, term loans, and lines of credit to fund capital expenditure plans and to fund other corporate expenses. Financing costs incurred as a result of these instruments are generally recorded as an asset and deferred over the life of the debt instrument using the straight line method for lines of credit and the effective interest method for term loans. As of the Petition Date, unamortized deferred financing costs associated with debt arrangements subject to compromise of approximately $18.2 million were reclassified as a reduction of the debt obligation recorded in liabilities subject to compromise and is no longer amortized. As of December 31, 2015 , the Company had no remaining net deferred financing costs relating to debt not subject to compromise, and recorded interest expense of $8.5 million related to the amortization and write-off of deferred financing costs for the year ended December 31, 2015 . The Company evaluates changes and modifications of debt instruments under the guidance provided in ASC Topic 470, Debt , which provides that unamortized deferred financing costs attributable to an extinguished debt instrument should be included in any gain or loss recognized on extinguishment. The Company records losses attributable to extinguished debt instruments as a component of interest expense. Intangible Assets Intangible assets consisted primarily of acquired gas treating agreements and customer relationships of Eureka Midstream Holdings. Such assets were being amortized over the estimated useful lives, which ranged from 2 to 13 years, up to December 18, 2014, when Eureka Midstream Holdings was deconsolidated. The Company assesses the carrying amount of its other intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. There was no amortization expense for intangible assets during the year ended December 31, 2015 as all intangible assets were related to Eureka Midstream Holdings, which was deconsolidated as of December 18, 2014. Amortization expense for intangible assets was $2.0 million and $2.5 million for the years ended December 31, 2014 and 2013 , respectively. Revenue Payable Revenue payable represents amounts collected from purchasers for oil and gas sales which are either revenues due to other working or royalty interest owners or severance taxes due to the respective state or local tax authorities. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received. Revenue payable of approximately $5.2 million is included in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015. See “Note 3 - Voluntary Reorganization under Chapter 11” . Asset Retirement Obligation Asset retirement obligations (“ARO”) primarily represent the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the projected end of their productive lives, in accordance with applicable federal, state and local laws. The Company determined its ARO by calculating the present value of estimated cash flows related to the obligation. The retirement obligation is recorded as a liability at its estimated present value as of the obligation’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as accretion expense in the accompanying consolidated statements of operations. ARO liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. The liability for current ARO is reported in other current liabilities. Revenue Recognition Revenues associated with sales of crude oil, natural gas, and natural gas liquids are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. Prices for production are defined in sales contracts and are readily determinable or estimable based on available data. Revenues from the production of natural gas and crude oil from properties in which the Company has an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on the Company’s net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant. Revenues from field servicing activities are recognized at the time the services are provided and earned as provided in the various contract agreements. Gas gathering revenues are recognized at the time the natural gas is delivered at the destination point. Production Costs Lease operating expenses, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, workovers and other operating expenses are expensed as incurred. Severance Taxes and Marketing Costs Severance taxes are comprised of production taxes charged by most states on oil, natural gas, and natural gas liquids produced. These taxes are computed on the basis of volumes and/or value of production or sales. These taxes are usually levied at the time and place the minerals are severed from the producing reservoir. Marketing costs are those directly associated with marketing the Company’s production and are based on volumes. Transportation, Processing, and Other Related Costs Transportation, processing, and other related costs are comprised of transportation and gathering expenses incurred to deliver natural gas to the processing plant and/or selling point, and are expensed as incurred. Exploration Exploration expense consists primarily of impairment reserves for abandonment costs associated with unproved properties for which the Company has no further exploration or development plans, exploratory dry hole costs, and geological and geophysical costs. Share-Based Compensation The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and matching contributions of stock to employees under its employee stock ownership plan, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. The Company estimated the fair value of each share-based award using the Black-Scholes option pricing model or a lattice model. These models are highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of the Company’s stock price, and the assessment of whether the achievement of performance criteria is probable. Income Taxes and Uncertain Tax Positions Income taxes are accounted for in accordance with ASC Topic 740, Income Taxes, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. Interest and penalties related to income taxes are recognized in “ Income tax benefit ” in the consolidated statement of operations. Under accounting standards for uncertainty in income taxes, a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” ( i.e. a likelihood greater than 50 percent ) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The Company had no uncertain tax positions at December 31, 2015 or 2014 . The Company applies the intra-period tax allocation rules, using the with and without approach, to allocate income taxes among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital when it meets the criteria as prescribed in the rules. Loss per Common Share Basic net income or loss per common share is computed by dividing the net income or loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. During the year ended December 31, 2015, net loss attributable to common shareholders does not include preferred stock dividends that accumulated subsequent to the Petition Date. See “Note 13 - Shareholders' Equity” and “Note 14 - Redeemable Preferred Stock” for additional discussion of preferred stock dividends. Diluted net income or loss per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from stock options, unvested restricted stock awards, stock warrants and any outstanding convertible securities. Potentially dilutive common share equivalents are not included in the computation of diluted earnings per share if they are anti-dilutive. Other Comprehensive Income (Loss) The functional currency of the Company’s operations in Canada is the Canadian dollar. The Company closed its Calgary, Alberta office effective January 31, 2015 due to the sales of all of its Canadian assets during 2014 (see “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” ), but maintained certain Canadian bank accounts through December 31, 2015. For purposes of consolidation, the Company translated the assets and liabilities of its Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses were translated at the average rates in effect for the period. The related translation gains and losses are included in accumulated other comprehensive income. Unrealized gains and losses on changes in fair value of common and preferred stock of publicly traded companies designated as available for sale securities, except those losses that are other-than-temporary and charged to earnings, are included in accumulated other comprehensive income. Upon the sale of available for sale securities, the related gain or loss in accumulated other comprehensive income is reclassified to “ Other income (expense) ” in the consolidated statements of operations. During the year ended December 31, 2014, the Company completed the sale of its Canadian subsidiary, Williston Hunter Canada, Inc. (“WHI Canada”) and reclassified $20.7 million of the accumulated comprehensive loss attributable to this entity to “ Gain (loss) on disposal of discontinued operations, net of tax ” in the accompanying consolidated financial statements. 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 ASC 980-605, Regulated Operations–Revenue Recognition , which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. During the years ended December 31, 2015 , 2014 , and 2013 , the Company had gas transmission, compression and processing revenue, reported in other revenue, which included gas utility sales from Sentra Corporation’s regulated operations aggregating $637,000 , $718,000 , and $216,000 , respectively. Recently Issued Accounting Standards Accounting standards-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its financial statements. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition , and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date , which defers the effective date of ASU 2014-09 for all entities by one year. As such, this amendment is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, and earlier application is permitted as of annual reporting periods beginning after December 14, 2016, including interim reporting periods within that reporting period. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern . This update requires an entity’s management to evaluate for each annual and interim reporting period whethe

VOLUNTARY REORGANIZATION UNDER

VOLUNTARY REORGANIZATION UNDER CHAPTER 11	12 Months Ended
	Dec. 31, 2015
Reorganizations [Abstract]
VOLUNTARY REORGANIZATION UNDER CHAPTER 11	NOTE 3 - VOLUNTARY REORGANIZATION UNDER CHAPTER 11 On the Petition Date, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code. Since the Petition Date, the Debtors have operated their business as “debtors-in-possession” pursuant to Sections 1107(a) and 1108 of the Bankruptcy Code, which allows the Company to continue operations in the ordinary course of business during their Chapter 11 Cases. Each Debtor remains in possession of its assets and properties, and its business and affairs will continue to be managed by its directors and officers, subject in each case to the supervision of the Bankruptcy Court. On April 18, 2016, the Bankruptcy Court approved the Chapter 11 plan of reorganization (as amended, the “Plan”), which, among other things, resolved the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity, and provided for corporate governance subsequent to exit from bankruptcy. The effective date of the Plan is anticipated to be May 6, 2016 (the “Effective Date”). Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petitions. Accordingly, although the filing of the Bankruptcy Petitions triggered defaults on the Debtors’ then-existing debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code. Restructuring Support Agreement and Plan of Reorganization Prior to filing the Chapter 11 Cases, on December 15, 2015, the Company and the other Debtors entered into a Restructuring Support Agreement (as amended, the “RSA”) with the following parties: • Substantially all of the Second Lien Lenders and Noteholders (each as defined herein) party to the Senior Secured Bridge Financing Facility (as defined in note “Note 11 - Long-Term Debt” ); • Lenders holding approximately 66.5% in principal amount outstanding under the Second Lien Term Loan Agreement (as described in “Note 11 - Long-Term Debt” ) (the “Second Lien Lenders”); and • Holders, in the aggregate, of approximately 79.0% in principal amount outstanding of the Company’s unsecured 9.750% Senior Notes due 2020 (the “Senior Notes”) (collectively, the “Noteholders”). The agreed terms of the restructuring of the Debtors, as contemplated in the RSA, were memorialized in the Plan. The RSA and the Plan contemplate the implementation of a restructuring of the Company through a conversion of substantially all of the Company’s funded debt into equity and also provides for a multi-draw debtor-in-possession financing facility in an aggregate principal amount of up to $200 million (the “DIP Facility”). The Plan represents a settlement of various issues, controversies, and disputes. The key terms of the restructuring, as contemplated in the RSA and the Plan, are as follows: • DIP Facility: A $200 million multi-draw DIP Facility entered into with certain Second Lien Lenders and Noteholders. The DIP Facility is expected to convert to new common equity of the reorganized Company at a discount to Plan value, upon the conditions in the RSA. • Substantial Deleveraging of Balance Sheet: The Senior Secured Bridge Facility was repaid in full from the proceeds of the DIP Facility upon entry of an order by the Bankruptcy Court on January 11, 2016 (the “Final DIP Order”) approving, on a final basis, the debtor-in-possession financing. On the Effective Date, the Second Lien Term Loan is expected to be converted into new common equity of the reorganized Company, receiving 36.87% of the new common equity. On the Effective Date, the Senior Notes are expected to be converted into new common equity of the reorganized Company, receiving 31.33% of the new common equity. On the Effective Date, the DIP Facility is expected to be converted into 28.80% of the new common equity. The general unsecured claims of the Company are projected to receive a blended recovery as specified in the RSA and the Plan, to be paid in cash, through a combination of payments to be made pursuant to Bankruptcy Court orders (lien claimant motion, taxes, etc.) and a cash pool of approximately $23.0 million included in the Plan. Holders of certain general unsecured claims of the Company elected to receive new common equity instead of cash, which is expected to dilute the new common equity issued to the holders of the Senior Notes and the lenders of the Second Lien Term Loan as described in the Plan. Holders of the Company’s preferred stock and common equity are expected to receive no recovery under the RSA and the Plan. The Other Secured Debt (as defined in the RSA and the Plan) is expected to be reinstated. • Business Plan: A business plan (the “Business Plan”) was developed jointly with the Debtors, the Second Lien Lenders that have backstopped the DIP Facility (the “Second Lien Backstoppers”) and the Noteholders that have backstopped the DIP Facility (the “Noteholder Backstoppers,” and together with the Second Lien Backstoppers, the “Backstoppers”). • Valuation for Settlement Purposes: For settlement purposes only, the Plan reflects a total enterprise value of the Company of $900 million . Such settlement value is not indicative of any party’s views regarding total enterprise value, but rather is a settled value for the purpose of determining equity splits and conversion rates for the various claimants. • Eureka Midstream Holdings: The Debtors restructured certain key agreements between Eureka Midstream Holdings and its subsidiaries, on the one hand, and the Debtors, on the other, with the consent of the Backstoppers. • Reorganized Company Status: The reorganized Company is expected to be a private company upon emergence from the Chapter 11 Cases and is expected to seek public listing of its new common equity when market conditions warrant and as determined by the New Board (as defined below) as informed by input from the Backstoppers. • Conditions Precedent to Emergence: The conditions precedent to emergence include the following, among others: (i) entry of a Bankruptcy Court order confirming the Plan and approving the disclosure statement of the Plan, in both instances in form and substance satisfactory to the Company and the Backstoppers (which has occurred), (ii) total administrative expenses paid by the Debtors shall not exceed the certain thresholds enumerated in the RSA without the consent of the Backstoppers, and (iii) the Debtors shall have entered into a new exit credit facility in the committed amount contemplated by the agreed Business Plan, on terms and conditions and with lenders, satisfactory to the Backstoppers and the Debtors. • Releases: The Plan provided for release, exculpation, and injunction provisions, including customary carve-outs, to the fullest extent permitted by applicable law and consistent with the terms of the RSA, and the Backstoppers have agreed not to “opt-out” of the consensual “third-party” releases granted to, among others, the Debtors’ current and former directors and officers. • Incentive Plans: The new board of directors of the reorganized Company shall be authorized to adopt management incentive programs to be paid exclusively with the funds of the reorganized Company. The management incentive plan will not give rise to any claims against the debtors or their estates. • Governance: The reorganized Company shall have a seven -person board of directors (the “New Board”), consisting of (i) the Chief Executive Officer, (ii) two directors selected by the Noteholder Backstoppers, (iii) two directors selected by the Second Lien Backstoppers, (iv) one director jointly selected by the Noteholder Backstoppers and the Second Lien Backstoppers, who shall serve as the non-executive chairman, and (v) one director selected by the Noteholder Backstoppers, based upon a slate of three candidates jointly determined by the Noteholder Backstoppers and the Second Lien Backstoppers. Members of the current management team of the Debtors have remained in place during the pendency of the Chapter 11 Cases and are expected to remain in place until the Company’s emergence from bankruptcy; however, on May 6, 2016, Mr. Evans tendered his voluntary resignation as the Company’s Chief Executive Officer and Chairman of the Board of Directors, which resignation is expected to be effective following the issuance of this report. The RSA also contains certain milestones for progress in the Bankruptcy Court proceedings (the “Milestones”), which include the following: • The Debtors shall have commenced the Chapter 11 Cases on December 15, 2015 (which has occurred); • On the Petition Date, the Debtors shall have filed with the Bankruptcy Court a motion seeking entry of an order by the Bankruptcy Court approving, on an interim basis, the debtor-in-possession financing (the “Interim DIP Order”) and the Final DIP Order (which has occurred); • No later than December 17, 2015, the Bankruptcy Court shall have entered the Interim DIP Order (which has occurred); • No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court a motion to reject executory contracts and set procedures regarding rejection damages (which has occurred); • No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court: (i) the Plan, (ii) the disclosure statement of the Plan, (iii) a motion seeking approval of the disclosure statement of the Plan and Plan as well as certain other items, and (iv) a motion seeking to assume the RSA (which has occurred); • No later than January 15, 2016, the Bankruptcy Court shall have entered the Final DIP Order (which has occurred); • No later than February 12, 2016, the Bankruptcy Court shall have entered an order approving assumption of the RSA (which has occurred); • No later than February 26, 2016, (i) the Bankruptcy Court shall have entered an order approving the disclosure statement with respect to the Plan (which has occurred) and (ii) no later than February 29, 2016, the Debtors shall have commenced solicitation on the Plan (which has occurred); • No later than April 18, 2016, the Bankruptcy Court shall have commenced the confirmation hearing on the Plan (which has occurred), and no later than April 19, 2016, the Bankruptcy Court shall have entered the Plan confirmation order (which has occurred); and • No later than May 6, 2016, the Debtors shall consummate the transactions contemplated by the Plan. The Company has met all Milestones thus far under the RSA. The remaining Milestone to be completed is the consummation of the transactions contemplated by the Plan no later than May 6, 2016. There can be no assurance that this Milestone will be achieved. The continuation of the Chapter 11 Cases, particularly if the Plan is not implemented within the timeframe currently contemplated, could adversely affect operations and relationships between the Company and its customers, suppliers, vendors, service providers, and other creditors and result in increased professional fees and similar expenses. Failure to implement the Plan could further weaken the Company’s liquidity position, which could jeopardize the Company’s exit from Chapter 11 reorganization. All of the Company’s existing equity securities, including shares of common stock and preferred stock and warrants and options, are expected to be canceled without receiving any distribution. On the Petition Date, the Company sought, and thereafter obtained, authority to take a broad range of actions, including, among others, authority to pay royalty interests and joint interest billings, certain employee obligations and pre-Petition contractor claims and taxes. Additionally, other orders were obtained, including adequate assurance of payment to utility companies as well as continued use of cash management systems. Liabilities Subject to Compromise Liabilities subject to compromise represent liabilities incurred prior to the commencement of the bankruptcy proceedings which may be affected by the Chapter 11 process. These amounts represent the Company’s allowed claims and its best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings. Such claims remain subject to future adjustments. Adjustments may result from negotiations, actions of the Bankruptcy Court, determination as to the value of any collateral securing claims, or other events. Differences between liability amounts estimated by the Company and claims filed by creditors are being investigated and the Bankruptcy Court will make a final determination of the allowable claims. Liabilities subject to compromise consist of the following: December 31, 2015 (in thousands) Debt Senior Notes $ 599,305 Second Lien Term Loan 335,853 Other notes payable 1,800 Total debt 936,958 Accounts payable 78,536 Accounts payable to related parties 16,513 Dividends payable 7,275 Accrued liabilities 48,364 Revenue payable 5,198 Other liabilities 3,227 Total liabilities subject to compromise $ 1,096,071 See “Note 11 - Long-Term Debt” for detailed discussion of debt related activity. Interest Expense The Debtors have discontinued recording interest on unsecured or under secured liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $2.8 million , representing interest expense from the Petition Date through December 31, 2015. Contracts Under the Bankruptcy Code, the Debtors have the right to assume or reject certain contracts, subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the assumption of a contract requires a debtor to satisfy pre-petition obligations under the contract, which may include payment of pre-petition liabilities in whole or in part. Rejection of a contract is typically treated as a breach occurring as of the moment immediately preceding the Chapter 11 filing. Subject to certain exceptions, this rejection relieves the debtor from performing its future obligations under the contract but entitles the counterparty to assert a pre-petition general unsecured claim for damages. Parties to contracts rejected by a debtor may file proofs of claim against that debtor’s estate for damages. On January 7, 2016, the Debtors filed a motion seeking entry of an order establishing procedures for the assumption or rejection of contracts pursuant to section 365 of the Bankruptcy Code (the “Contract Procedures Motion”). The court entered an order approving the Contract Procedures Motion on February 26, 2016. On March 14, 2016, the Debtors filed the plan supplement, which included a schedule of assumed contracts and a schedule of rejected contracts, and since then have filed two amended plan supplements and additional motions with respect to assumed and rejected contracts. Through the contract assumption and rejection process, the Debtors were able to successfully negotiate approximately a dozen midstream and downstream contracts. The Debtors continue to review and analyze their contractual obligations and retain the right, until eight days following the Effective Date, to move contracts from the schedule of assumed contracts to the schedule of rejected contracts or from the schedule of rejected contracts to the schedule of amended contracts. Reorganization Items Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Unamortized deferred financing costs, premiums, and discounts associated with debt classified as liabilities subject to compromise are expensed to reorganization items in order to reflect the expected amounts of the probable allowed claims. Reorganization items consist of the following for the year ended December 31, 2015: December 31, 2015 (in thousands) Professional fees $ 4,118 Debt issuance costs 9,036 Loss on adjustments to carrying value of Senior Notes 12,533 Loss on adjustments to carrying value of Second Lien Term Loan 15,452 Total reorganization items $ 41,139 Debtors Condensed Combined Financial Statements Condensed combined financial statements of the Debtors are set forth below. These condensed combined financial statements exclude the financial statements of the Non-Debtors, but include the Company’s equity method investment in Eureka Midstream Holdings. Transactions and balances of receivables and payables between Debtors are eliminated in consolidation. However, the Debtors’ condensed combined balance sheet includes receivables from related Non-Debtors and payables to related Non-Debtors. Condensed Combined Balance Sheet For the Year Ended December 31, 2015 (in thousands) ASSETS Current assets $ 83,371 Intercompany accounts receivable 137 Property and equipment (using successful efforts accounting) 766,843 Investment in subsidiaries 1,214 Investment in affiliate, equity-method 166,099 Other assets 41,973 Total Assets $ 1,059,637 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities $ 145,860 Liabilities subject to compromise 1,096,071 Long-term liabilities 30,670 Redeemable preferred stock 100,000 Shareholders' equity (deficit) (312,964 ) Total Liabilities and Shareholders' Equity $ 1,059,637 Condensed Statement of Operations For the Year Ended December 31, 2015 (in thousands) Revenues $ 153,087 Operating expenses 614,383 Operating loss (461,296 ) Other Income (Expense) Interest income 157 Interest expense (99,559 ) Gain (loss) on derivative contracts, net 4,886 Loss from equity method investments (181,556 ) Reorganization items (41,139 ) Other income (expense) (5,568 ) Total other expense (322,779 ) Net loss (784,075 ) Dividends on preferred stock (33,817 ) Net loss attributable to common shareholders $ (817,892 ) Condensed Combined Statement of Comprehensive Income (Loss) For the Year Ended December 31, 2015 (in thousands) Net loss $ (784,075 ) Other comprehensive income (loss) Foreign currency translation loss 99 Unrealized gain (loss) on available for sale securities (2,771 ) Amounts reclassified for other than temporary impairment of available for sale securities 10,183 Amounts reclassified for available for sale securities (19 ) Total other comprehensive income (loss) 7,492 Comprehensive loss $ (776,583 ) Condensed Combined Statement of Cash Flows For the Year Ended December 31, 2015 (in thousands) Cash flow from operating activities $ 24,915 Cash flow from investing activities (165,941 ) Cash flow from financing activities 128,634 Effect of exchange rate changes on cash (28 ) Net increase (decrease) in cash (12,420 ) Cash at beginning of period 53,187 Cash at end of period $ 40,767

EUREKA HUNTER HOLDINGS

EUREKA HUNTER HOLDINGS	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interest [Abstract]
Eureka Hunter Holdings	As of January 1, 2013 and through December 18, 2014, the Company consolidated Eureka Midstream Holdings in which it owned a 48.6% interest as of December 18, 2014. Eureka Midstream Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Midstream, LLC, formerly known as Eureka Hunter Pipeline, LLC (“Eureka Midstream”), TransTex, LLC, formerly known as TransTex Hunter, LLC (“TransTex”), and Eureka Land, LLC, formerly known as Eureka Hunter Land, LLC. Eureka Midstream engages in midstream operations involving the gathering of natural gas through its ownership and operation of a gas gathering system located in northwestern West Virginia and southeastern Ohio, in the Marcellus and Utica Shale plays. TransTex sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating natural gas at the wellhead. Transaction Agreement On September 16, 2014, the Company entered into an agreement (the “Transaction Agreement”) with North Haven Infrastructure Partners II Buffalo Holdings LLC (formerly, MSIP II Buffalo Holdings LLC), an affiliate of Morgan Stanley Infrastructure, Inc. (“MSI”) and Eureka Midstream Holdings relating to a separate purchase agreement between MSI and Ridgeline Midstream Holdings, LLC (“Ridgeline”) providing for the purchase by MSI of all the Eureka Midstream Holdings Series A Preferred Units and Class A Common Units owned by Ridgeline. The Transaction Agreement contemplated two closings comprised of (i) the purchase by MSI of Ridgeline’s equity interests in Eureka Midstream Holdings and the execution of the Second Amended and Restated Limited Liability Company Agreement of Eureka Midstream Holdings (the “New LLC Agreement”) (the “First Closing”); and (ii) the purchase by MSI of an additional equity interest in Eureka Midstream Holdings from the Company as further described below. On October 3, 2014, the First Closing contemplated in the Transaction Agreement was consummated between MSI and Ridgeline. The Company was not a party to the transaction between MSI and Ridgeline. New LLC Agreement Contemporaneously with the First Closing, the New LLC Agreement for Eureka Midstream Holdings became effective. In accordance with the terms of the New LLC Agreement, all of the Eureka Midstream Holdings Series A Preferred Units and Class A Common Units of Eureka Midstream Holdings acquired by MSI from Ridgeline were converted into Series A-2 Common Units, a new class of equity interests of Eureka Midstream Holdings (the “Series A-2 Units”). Magnum Hunter’s Class A Common Units held on the date of the First Closing were also converted into a new class of common equity (the “Series A-1 Units”). The Series A-2 Units have preferential distribution rights over the Series A-1 Unit holders in the event a Sale Transaction or Initial Public Offering (both as defined in the New LLC Agreement) occurs subsequent to January 1, 2017. The Series A-2 Units also include certain veto rights with regards to a Sale Transaction or Initial Public Offering prior to January 1, 2017 unless certain thresholds are achieved (as provided in the New LLC Agreement). The preference on distribution rights provides the Series A-2 Unit members with downside protection through disproportionate distributions if certain specific internal rates of return are not achieved. Once the specified internal rates are achieved, however, then the Series A-1 Unit members will benefit from disproportionately larger distributions. As a result of the conversion of the Eureka Midstream Holdings Series A Preferred Units into Series A-2 Units, the features, terms, and cash flows associated with the Series A-2 Units are substantially different than those of the former Eureka Midstream Holdings Series A Preferred Units. Consequently, the conversion was treated as an extinguishment of a class of preferred equity, and an issuance of a new class of preferred equity that was recorded initially at fair value. Additionally, the accrued and unpaid dividends outstanding on the Eureka Midstream Holdings Series A Preferred Units and the fair value associated with the embedded derivative attached to the Eureka Midstream Holdings Series A Preferred Units, which was previously accounted for as a liability in the consolidated financial statements, was included in determining the total carrying value of the equity to be extinguished. See “Note 14 - Redeemable Preferred Stock”. The Transaction Agreement further provided that Magnum Hunter would sell to MSI in a second closing, that was expected to occur in January 2015 (the “Second Closing”), a portion of its Eureka Midstream Holdings Series A-1 Units, which, assuming completion of the full amount of additional capital contributions expected to be made by MSI, would constitute approximately 6.5% of the total common equity interests then outstanding in Eureka Midstream Holdings. Any Series A-1 Units purchased by MSI from the Company under a second closing would convert immediately into Series A-2 Units. The purchase price of such additional equity interests was expected to be approximately $65 million . Such closing, together with follow on capital contributions made by MSI in 2014, would result in the Company and MSI owning approximately equal equity interests in Eureka Midstream Holdings, which collectively would constitute an approximate 98% equity interest in Eureka Midstream Holdings. The Transaction Agreement and the Letter Agreement (described below) further provided that the Company had the right, under certain circumstances, to not make its portion of certain required future capital contributions to Eureka Midstream Holdings, and, if the Company validly exercises its right to do so, MSI would make the capital contributions which otherwise would be made by the Company, with the Company having the right to make catchup capital contributions before the earlier of one year from the date of the capital contribution or an MLP IPO (as defined in New LLC Agreement) that would bring the Company’s ownership interest back to the level prior to the capital call. The Company refers to this as the “carried interest” provided by MSI. This carried interest is at no cost to the Company but is subject to a maximum limit of $60 million . Letter Agreement On November 18, 2014, the Company, Eureka Midstream Holdings and MSI entered into a letter agreement (the “Letter Agreement”) amending certain provisions of the Transaction Agreement entered into on September 16, 2014, pursuant to which the Company, Eureka Midstream Holdings, and MSI agreed to reduce the Company’s capital account in Eureka Midstream Holdings by 1,227,182 Series A-1 Units with a fair value of $32.6 million , effective as of the date of the New LLC Agreement, to take into account certain excess capital expenditures incurred by Eureka Midstream in connection with certain of Eureka Midstream’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects. As a result of the reduction in the Company’s capital account, the Company recorded a loss of $32.6 million , which is reflected in “General and administrative expense”. In executing the Letter Agreement, the Company, Eureka Midstream Holdings and MSI also agreed to adjust the amount and timing of (i) certain capital contributions by the Company and MSI to Eureka Midstream Holdings and (ii) MSI’s purchase of a portion of the Company’s equity interests in Eureka Midstream Holdings pursuant to the Second Closing as follows: i. In connection with certain of Eureka Midstream’s capital projects for fiscal year 2014, on November 20, 2014, MSI made a $30 million capital contribution in cash to Eureka Midstream Holdings in exchange for additional Series A-2 Units. ii. On November 20, 2014, the Company made a $20 million capital contribution in cash to Eureka Midstream Holdings in exchange for additional Series A-1 Units. iii. In addition, in connection with a closing that occurred on December 18, 2014, MSI made a $10 million capital contribution in cash to Eureka Midstream Holdings in exchange for additional Series A-2 Units. iv. The Second Closing was accelerated to the date of the closing of MSI’s capital contribution referred to in item (iii) above, and, pursuant to the accelerated closing, the Company sold to MSI 5.5% of its Series A-1 Units (reduced from the amount originally provided to be sold to MSI at the Second Closing under the Transaction Agreement) for $55 million in cash (correspondingly reduced from the amount originally provided to be received by the Company from MSI at the Second Closing). The Series A-1 Units sold to MSI by the Company were converted into Series A-2 Units upon receipt by MSI on a one-for-one basis, as provided in the Transaction Agreement and the New LLC Agreement. v. The Company also agreed to make a $13.3 million capital contribution in cash to Eureka Midstream Holdings on or before March 31, 2015 in exchange for additional Series A-1 Units. However, the Company and MSI subsequently entered into an additional letter agreement (the “March 2015 Letter Agreement”) regarding Eureka Midstream Holdings’ 2015 capital expenditure budget, including the amount, timing and expected funding of the various anticipated capital expenditures. Loss of Controlling Financial Interest in Eureka Midstream Holdings The Transaction Agreement also provided MSI with certain substantive participation rights which allow MSI to participate in the management and operation of Eureka Midstream Holdings. As a result of MSI acquiring additional Series A-2 Units, which brought their total equity interest in Eureka Midstream Holdings to 49.84% as of December 18, 2014, the board of managers of Eureka Midstream Holdings was expanded from five to six members and MSI appointed the sixth manager, so that the board of managers of Eureka Midstream Holdings consists of three representatives of Magnum Hunter and three representatives of MSI. Prior to the expansion of the board of managers, the Company had majority representation on the board of managers of Eureka Midstream Holdings. As a result of the loss of majority representation on the board of managers as well as certain substantive participation rights granted to MSI in the New LLC Agreement, the Company determined it no longer held a controlling financial interest in Eureka Midstream Holdings and, therefore, the Company deconsolidated Eureka Midstream Holdings from the Company’s consolidated financial statements effective December 18, 2014. Upon loss of control and deconsolidation, the Company’s retained equity interest in Eureka Midstream Holdings was 48.6% , which is accounted for using the equity method of accounting following deconsolidation. Upon deconsolidation on December 18, 2014, the Company recognized its retained interest in Eureka Midstream Holdings at fair value of $347.3 million in accordance with the derecognition provisions of ASC Topic 810, Consolidation . The Company recognized a pre-tax gain of $509.6 million on the deconsolidation, measured as the sum of i) the fair value of the consideration received for the 5.5% equity interest sold by the Company to MSI, ii) the fair value of the Company’s retained investment, and iii) the carrying amount of the non-controlling interest prior to deconsolidation, less the carrying amount of the net assets of Eureka Midstream Holdings at December 18, 2014. Approximately $187.2 million of the pre-tax gain was attributable to the remeasurement of the retained investment in the former subsidiary to fair value. See “Note 9 - Fair Value of Financial Instruments” for the method used to determine the fair value of the Company’s retained interest in Eureka Midstream Holdings. Eureka Midstream Holdings is considered an affiliate and a related party subsequent to the deconsolidation as a result of the Company’s continued investment in and transactions with Eureka Midstream Holdings. March 2015 Letter Agreement On March 30, 2015, the Company, Eureka Midstream Holdings and MSI entered into 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 Midstream 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 Midstream Holdings as follows: i. On March 31, 2015, MSI made a capital contribution in cash to Eureka Midstream Holdings of approximately $27.2 million (the “2015 Growth CapEx Projects Contribution”) in exchange for additional Series A-2 Units in Eureka Midstream Holdings with the proceeds of such capital contribution to be used to fund certain of Eureka Midstream’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 Midstream Holdings (the “LLC Agreement”)). ii. On March 31, 2015, MSI made an additional capital contribution in cash to Eureka Midstream Holdings of approximately $37.8 million (the “Additional Contribution”) in exchange for additional Series A-2 Units in Eureka Midstream Holdings with the proceeds of such Additional Contribution to be used to fund certain of Eureka Midstream’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 Midstream 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 had the right, in its discretion, to fund as a capital contribution to Eureka Midstream Holdings, all or a portion (in specified minimum amounts) of its pro-rata share of the Additional Contribution, which pro-rata share equaled approximately $18.7 million (the “MHR Additional Contribution Component”), before June 30, 2015 (as extended, the “MHR Contribution Deadline”), in exchange for additional Series A-1 Units in Eureka Midstream Holdings (the “MHR 2015 Make-up Contribution”). July 2015 Letter Agreement On July 27, 2015, the Company entered into an additional letter agreement (the “July 2015 Letter Agreement”) with Eureka Midstream Holdings and MSI pursuant to which the parties memorialized an agreement in principle which had been reached prior to June 30, 2015, to extend the MHR Contribution Deadline to the earlier of (i) September 30, 2015 or (ii) the day immediately preceding the date on which the Company disposes, in a sale transaction or otherwise, its equity ownership interest in Eureka Midstream Holdings. The Company did not fund the MHR Additional Contribution Component, and as such, the Company’s Series A-1 Units in Eureka Midstream Holdings were adjusted downward by 529,190 units, which was 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. As a result of the downward adjustment to its Series A-1 Units, the Company recognized a loss of $7.7 million reported net of tax in “ Loss from equity method investments ” on the consolidated statements of operations during the year ended December 31, 2015. The loss included the Company’s proportionate decrease in its equity method basis difference which was reduced by $4.0 million during the third quarter of 2015, based on the change in the Company’s ownership in the net assets of Eureka Midstream Holdings related to the downward adjustment in its Series A-1 Units. The Company continues to have the right to 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. As of December 31, 2015, the Company had deferred capital contributions of approximately $27.2 million , for which it had the right to make future catch-up contributions. During the pendency of the Chapter 11 Cases, the payment of any such capital contributions is subject to the approval of the Bankruptcy Court. The Company accounted for the March 31, 2015 MSI capital contributions, the issuance of additional Series A-2 Units by Eureka Midstream Holdings, and the September 30, 2015 expiration of the MHR Contribution Deadline 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 Midstream Holdings. During the year ended December 31, 2015, the Company recognized a gain of $4.6 million reported net of tax in “Gain on dilution of interest in Eureka Midstream Holdings, LLC, net of tax” in the consolidated statements of operations based on the difference between the carrying value of the Company’s Series A-1 Units and the proceeds received by Eureka Midstream 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 Midstream Holdings. The gain included the Company’s proportionate decrease in its equity method basis difference which was reduced by $7.5 million during the year ended December 31, 2015, based on the change in the Company’s ownership in the net assets of Eureka Midstream Holdings after giving effect to the dilution of the Company’s interest as a result of the unit issuance. As of November 3, 2015, the Company recorded impairment of $180.3 million included in “ Loss from equity method investments ” in the consolidated statements of operations in order to write down the carrying value of its equity interest in Eureka Midstream Holdings to fair value as a result of the Company’s determination that the investment no longer met the criteria for classification as a discontinued operation as of that date. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” . Accordingly, the Company reduced its equity method basis difference by $180.3 million as of November 3, 2015. As of December 31, 2015 , the Company and MSI owned 44.53% and 53.98% , respectively, of the Class A Common Units of Eureka Midstream Holdings. As of December 31, 2014 , the Company and MSI owned 48.60% and 49.84% , respectively, of the equity interests of Eureka Midstream Holdings. The carrying value of the Company’s equity interest in Eureka Midstream Holdings was $166.1 million and $347.2 million at December 31, 2015 and 2014 , respectively. The recognition of the Company’s retained interest in Eureka Midstream Holdings at fair value upon deconsolidation resulted in a basis difference between the carrying value of the Company’s investment in Eureka Midstream Holdings and its proportionate share in net assets of Eureka Midstream Holdings. In accordance with ASC Topic 323, Investments - Equity Method, the difference (the “basis difference”) between the initial fair value of the Company’s investment and the proportional interest in the underlying net assets of Eureka Midstream Holdings was accounted for using the acquisition method of accounting, which requires that the basis difference be allocated to the identifiable assets and liabilities of Eureka Midstream 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 estimated that the amortization of the basis difference allocable to the 14 day period from December 18, 2014 to December 31, 2014 was not material. During the second quarter of 2015, the Company completed its valuation of the identifiable assets to which the basis is attributable and recorded amortization based on this valuation for the year ended December 31, 2015. The Company initially recognized a basis difference of $201.9 million upon deconsolidation related to its investment in Eureka Midstream Holdings which has been allocated to the following identifiable assets of Eureka Midstream Holdings: Identifiable Assets Ending Basis December 31, 2014 Basis Amortization Basis Reduction Ending Basis December 31, 2015 (in thousands) Fixed assets $ 5,088 $ (208 ) $ (4,785 ) $ 95 Intangible assets 155,189 (6,057 ) (146,252 ) 2,880 Goodwill 41,597 — (40,750 ) 847 Total basis difference $ 201,874 $ (6,265 ) $ (191,787 ) $ 3,822 The components of the Company’s basis difference, excluding goodwill, are being amortized over their estimated useful lives ranging from 3 to 39 years. Amortization of the basis difference is reflected as a component of “Income (loss) from equity method investment” in the accompanying consolidated statements of operations. Summarized balance sheet information for Eureka Midstream Holdings as of December 31, 2015 and 2014 is as follows: December 31, 2015 December 31, 2014 (in thousands) Current assets $ 86,910 $ 17,113 Non-current assets $ 507,201 $ 445,450 Current liabilities $ 20,683 $ 63,313 Non-current liabilities $ 182,561 $ 100,037 Summarized income information for Eureka Midstream Holdings for the year ended December 31, 2015 and the period from December 18, 2014 through December 31, 2014 is as follows: Year Ended December 31, 2015 Fourteen Days Ended December 31, 2014 (in thousands) Operating revenues $ 77,022 $ 2,124 Operating income $ 23,250 $ 74 Net income (loss) $ 18,979 $ (207 ) Magnum Hunter’s interest in Eureka Midstream Holdings net income (loss) $ 8,490 $ (101 ) Basis difference amortization (6,265 ) — Loss on downward adjustment of units (7,664 ) — Impairment upon reclassification from discontinued operations to continuing operations (180,254 ) — Magnum Hunter’s equity in earnings (loss), net $ (185,693 ) $ (101 )

ACQUISITIONS, DIVESTITURES, AND

ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS	NOTE 5 - ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS Acquisitions The Company recognized $2.8 million of transaction expenses related to acquisitions in its general and administrative expenses for the year ended December 31, 2013. The Company’s transaction expenses related to acquisitions were insignificant for the years ended December 31, 2015 and 2014. Substantially all of the Company’s acquisitions contained a significant amount of unproved acreage, as is consistent with the Company’s business strategy. Agreements to Purchase Utica Shale Acreage On August 12, 2013, Triad Hunter entered into an asset purchase agreement (the “MNW 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 years ended December 31, 2015 , 2014 , and 2013 , Triad Hunter purchased 2,665 , 16,456 and 5,922 net leasehold acres, respectively, from MNW for an aggregate purchase price of $12.0 million , $67.3 million , and $24.6 million , respectively. The Company listed the MNW Purchase Agreement on its Schedule of Rejected Executory Contracts that it filed with the Bankruptcy Court, as an exhibit to a supplement to the Plan, on March 14, 2016. Accordingly, on the Effective Date the MNW Purchase Agreement is expected to be terminated, and the Company does not expect that any of the remaining net leasehold acres will be acquired by Triad Hunter. See “Note 18 - Commitments and Contingencies” . Ormet Asset Acquisition On June 18, 2014, the Company entered into an Asset Purchase Agreement (“Ormet Asset Purchase Agreement”) with Ormet Corporation for the purchase of certain mineral interests in approximately 1,700 net acres, consisting of 1,375 net acres in Monroe County, Ohio and 325 net acres in Wetzel County, West Virginia. Prior to the execution of the Ormet Asset Purchase Agreement, the Company held leasehold interests in a portion of the subject acreage, which leasehold interests covered only the Marcellus zone and were subject to a 12.5% royalty on production to Ormet Corporation. On July 24, 2014, the Company closed on the purchase of the sub-surface mineral rights, including any royalty interests, in the underlying acreage, giving the Company an approximate 100% net revenue interest in and rights to oil, natural gas, and other minerals located in or under and that may be produced from the property, at any depth. The total purchase price for this transaction was approximately $22.7 million cash. Discontinued Operations Withdrawn Plan for the Divestiture of Eureka Midstream Holdings In June 2015, the Company announced its decision to pursue the sale of all of its equity ownership interest in Eureka Midstream Holdings in order to improve the Company’s liquidity position. The Company determined that the planned divestiture met the criteria for assets held for sale and classification as a discontinued operation. Effective June 30, 2015, the Company reclassified its equity method investment in Eureka Midstream Holdings to assets of discontinued operations. On November 3, 2015, the Company entered into the Senior Secured Bridge Financing Facility with certain lenders, certain holders of the Company’s Senior Notes, and certain holders of the loans outstanding under the Second Lien Term Loan Agreement. Under the Senior Secured Bridge Financing Facility, the Company has restrictions on sales of assets, including among other things, restrictions on the sale of the Company’s equity ownership interests in Eureka Midstream Holdings. The Company was required to cease marketing the sale of its equity ownership interests in Eureka Midstream Holdings, other than with bidders that contact the Company without prior solicitation and other than any bidders that were already engaged in such marketing efforts with the Company as of November 3, 2015. See “Note 11 - Long-Term Debt” for further discussion of the Senior Secured Bridge Financing Facility. As the Company was prohibited from actively marketing its equity ownership interests in Eureka Midstream Holdings, the Company determined as of November 3, 2015 that the planned divestiture no longer met the criteria for classification as a discontinued operation. Furthermore, under the RSA, the Company may not market its interest in Eureka Midstream Holdings without the consent of the Backstoppers. As of November 3, 2015, the Company measured the carrying value of its equity method investment in Eureka Midstream Holdings at the lesser of its carrying value and its fair value at the date the planned divestiture no longer met the criteria for classification as a discontinued operation. As a result of this assessment, the Company recorded impairment of $180.3 million to the carrying value of its equity method investment in Eureka Midstream Holdings, which is included in “Loss from equity method investments” in the consolidated statements of operations. The Company reclassified the results of Eureka Midstream Holdings’ operations related to periods prior to December 18, 2014, and all subsequent equity method losses through December 31, 2015, are reflected in continuing operations for all periods presented in these consolidated financial statements. The Company’s equity method investment in Eureka Midstream Holdings is included in “Investments in affiliates, equity method” as of December 31, 2015 and 2014. Withdrawn Plan for the Divestiture of Magnum Hunter Production In September 2013, the Company adopted a plan to divest all of its interests in MHP, whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and the Company determined that the planned divestiture met the assets held for sale criteria and the criteria for classification as a discontinued operation. The Company determined at each interim and annual period subsequent to September 30, 2013, and until September 30, 2014, that the planned divestiture continued to meet the criteria for classification as a discontinued operation based upon its ongoing marketing activities and assessed impairment of MHP based on the discontinued operations classification. During the year ended December 31, 2013, the Company recorded an impairment expense of $18.5 million , net of tax, to record MHP at the estimated selling price less costs to sell. Based upon additional information on estimated selling prices obtained through active marketing of the assets, the Company recorded an additional impairment expense during the quarter ended March 31, 2014 of $18.6 million , net of tax, to reflect the net assets at their estimated selling prices, less costs to sell. The Company did not record any impairment for MHP for the three month period ended June 30, 2014. Effective September 2014, the Company withdrew its plan to divest MHP to further evaluate the oil and natural gas exploration and development upside opportunities underlying the acreage the Company has access to through MHP’s leasehold and mineral interest rights. As a result of this decision the Company ceased all marketing activities for MHP, and consequently MHP no longer met the criteria for classification as a discontinued operation as of September 30, 2014. As of September 30, 2014, the Company measured the carrying value of MHP’s individual long-lived assets previously classified as held for sale at the lesser of (i) their carrying amount before each asset was classified as held for sale, adjusted for any depreciation or amortization expense that would have been recognized had it been continuously classified as held and used, and (ii) their fair value at the date of the subsequent decision not to sell. As a result of this assessment, the Company recorded additional impairments of $1.9 million to the carrying amount of MHP’s unproved oil and natural gas properties and $17.0 million to the carrying amount of MHP’s proved oil and natural gas properties, which were recorded in exploration expense and impairment of proved oil and gas properties, respectively. In addition, the Company recorded depreciation expense of $1.7 million related to long-lived assets, whose fair value exceeded book value, adjusted for depreciation expense, as of September 30, 2014. In total, the Company recorded approximately $67.6 million of impairment related to MHP from September 30, 2013 through December 31, 2014. Williston Hunter Canada, Inc. In September 2013, the Company adopted a plan to divest all of its interests in the Canadian operations of Williston Hunter Canada, Inc. (“WHI Canada”), which was a wholly owned subsidiary of the Company. Williston Hunter Canada Asset Sale On April 10, 2014, WHI Canada closed on the sale of certain oil and natural gas properties and assets located in Alberta, Canada for cash consideration of CAD $9.5 million in cash (approximately U.S. $8.7 million at the exchange rate as of the close of business on April 10, 2014). The effective date of the sale was January 1, 2014. The Company recognized a gain of $6.1 million which is recorded in gain (loss) on disposal of discontinued operations. Sale of Williston Hunter Canada On May 12, 2014, the Company closed on the sale of 100% of its ownership interest in the Company’s Canadian subsidiary, WHI Canada, whose assets consisted primarily of oil and natural gas properties located in the Tableland Field in Saskatchewan, Canada, for a purchase price of CAD $75.0 million (approximately U.S. $68.8 million at the exchange rate as of the close of business on May 12, 2014), prior to customary purchase price adjustments, with an effective date of March 1, 2014, of which CAD $18.4 million was placed in escrow pending final approval from the Canadian Revenue Authority. The Company received the cash held in escrow in July 2014. The Company recognized a loss of $12.9 million which is recorded in gain (loss) on disposal of discontinued operations. The loss on disposal of WHI Canada for the year ended December 31, 2014 includes $20.7 million in foreign currency translation adjustment which was reclassified out of accumulated other comprehensive income upon closing the sale of the Company’s foreign operation. Sale of Eagle Ford Hunter On April 24, 2013, the Company closed on the sale of all of its ownership interest in its wholly owned subsidiary, Eagle Ford Hunter, to an affiliate of Penn Virginia for a total purchase price of approximately $422.1 million paid to the Company in the form of $379.8 million in cash (after estimated customary initial purchase price adjustments) and 10.0 million shares of common stock of Penn Virginia valued at approximately $42.3 million (based on the closing market price of the stock of $4.23 as of April 24, 2013). The effective date of the sale was January 1, 2013. Upon closing of the sale, $325.0 million of sale proceeds were used to pay down outstanding borrowings under Magnum Hunter’s senior revolving credit facility. During the third quarter of 2013, the Company had completed the sale of all of its Penn Virginia common stock for gross proceeds of $50.6 million , recognizing a gain of $8.3 million in other income. Initially, the Company recognized a gain on the sale of $172.5 million , net of tax. In the months that followed closing, the Company and Penn Virginia were unable to agree upon the final settlement of the working capital adjustments as called for in the purchase and sale agreement and the disagreement was subsequently submitted to arbitration. The determination by the arbitrator was received by the Company on July 25, 2014 and resulted in a downward adjustment of the cash portion of the purchase price of $33.7 million plus accrued interest of $1.3 million . This liability was settled in cash on July 31, 2014. The Company had previously reserved and recognized substantially all of this obligation in its financial statements as of December 31, 2013. For the years ended December 31, 2014 and 2013, the Company recorded downward adjustments to the gain on sale of Eagle Ford Hunter of $7.1 million and $28.1 million , respectively. The Company included the results of operations of WHI Canada, which has historically been the only member of the Company’s Canadian Upstream segment, through May 12, 2014, and Eagle Ford Hunter, which has historically been included as part of the U.S. Upstream segment, through April 24, 2013 in discontinued operations as follows: Year Ended December 31, 2014 2013 (in thousands) Revenues $ 8,533 $ 67,490 Expenses (1) (3,975 ) (130,331 ) Other income (expense) 3 186 Income (loss) from discontinued operations before tax 4,561 (62,655 ) Income tax benefit (expense) (2) — 94 Income (loss) from discontinued operations, net of tax 4,561 (62,561 ) Gain (loss) on disposal of discontinued operations, net of taxes (3)(4) (13,855 ) 71,510 Income (loss) from discontinued operations, net of tax $ (9,294 ) $ 8,949 _____________________ (1) Includes impairment expense of $65.4 million for the year ended December 31, 2013 and exploration expense of $0.1 million and $19.9 million for the years ended December 31, 2014 and 2013, respectively, relating to the discontinued operations of WHI Canada, which is recorded in income (loss) from discontinued operations. (2) The Company’s 2013 effective tax rate on the loss from discontinued operations is 0.2% primarily due to the significant losses generated in WHI Canada, which has an overall lower statutory tax rate further lowered by the utilization of certain net operating losses. (3) Income tax expense associated with gain/(loss) on sale of discontinued operations was none and $11.9 million for the years ended December 31, 2014 and 2013, respectively. (4) The Company’s 2013 effective tax rate on the gain on disposal of discontinued operations is 14.23% primarily due to the anticipated utilization of a capital loss on the sale of WHI Canada against the capital gains included in discontinued operations. There were no assets or liabilities held for sale at December 31, 2015 or 2014. Other Divestitures Sale of Certain North Dakota Oil and Natural Gas Properties On September 2, 2013, Williston Hunter, Inc., a wholly owned subsidiary of the Company, entered into a purchase and sale agreement with Oasis Petroleum of North America LLC, (“Oasis”), to sell its non-operated working interest in certain oil and natural gas properties located in Burke County, North Dakota, to Oasis for $32.5 million in cash, subject to customary adjustments. The transaction closed on September 26, 2013, and was effective as of July 1, 2013. The Company recognized a loss of $38.1 million on the sale for the year ended December 31, 2013. On December 30, 2013, PRC Williston and Williston Hunter, subsidiaries of the Company, closed on the sale of certain assets to Enduro Operating LLC, (“Enduro”). The Enduro sale included certain oil and gas properties and assets located in Burke, Renville, Bottineau and McHenry Counties, North Dakota, including operated working interests in approximately 180 wells producing primarily from the Madison formation in the Williston Basin. The effective date of the sale was September 1, 2013. The total purchase price, after initial purchase price adjustments, was $44.1 million in cash. The Company recognized a loss on the sale of $7.1 million . On September 30, 2014, Bakken Hunter, a wholly owned subsidiary of the Company, closed on the sale of certain non-operated working interests in oil and natural gas properties located in Divide County, North Dakota for cash consideration of $23.5 million , subject to customary purchase price adjustments. The effective date of the sale was April 1, 2014. The Company recognized a gain on the sale of $7.2 million . On October 15, 2014, Bakken Hunter closed on the sale of certain non-operated working interests in oil and natural gas properties located in Divide County, North Dakota for cash consideration of approximately $84.8 million , subject to customary purchase price adjustments. During the year ended December 31, 2014, the Company recorded an impairment expense of $15.2 million to record these assets at the estimated selling price less costs to sell. The effective date of the sale was August 1, 2014. The Company recognized a loss on the sale of $3.1 million . Sale of Certain Other Eagle Ford Shale Assets On January 28, 2014, the Company, through its wholly owned subsidiary Shale Hunter and certain other affiliates, closed on the sale of certain of their oil and natural gas properties and related assets located in the Eagle Ford Shale in South Texas to New Standard Energy Texas LLC (“NSE Texas”), a subsidiary of New Standard Energy Limited (“NSE”), an Australian Securities Exchange-listed Australian company. The assets sold consisted primarily of interests in leasehold acreage located in Atascosa County, Texas and working interests in five horizontal wells, of which four were operated by the Company. The effective date of the sale was December 1, 2013. As consideration for the assets sold, the Company received aggregate purchase price consideration of $15.5 million in cash, after customary purchase price adjustments, and 65,650,000 ordinary shares of NSE with a fair value of approximately $9.4 million at January 28, 2014 (based on the closing market price of $0.14 per share on January 28, 2014). These investment holdings represented approximately 17% of the total shares outstanding of NSE as of the closing date, and were designated as available for sale securities (see “Note 10 - Investments and Derivatives” ). The Company recognized a loss on the sale of the Shale Hunter assets of $4.5 million during the first quarter of 2014. Sale of Certain West Virginia Assets On November 3, 2014, Triad Hunter closed on the sale of certain non-core working interests in oil and gas properties located primarily in Calhoun and Roane Counties, West Virginia for cash consideration of $1.2 million , subject to customary purchase price adjustments. During the three months ended September 30, 2014, the Company recorded an impairment expense of $5.7 million to record these assets at the estimated selling price less costs to sell. The effective date of the sale was August 1, 2014. The Company recognized a gain on the sale of approximately $0.8 million . On May 22, 2015, Triad Hunter entered into a Purchase and Sale Agreement with Antero Resources Corporation (“Antero”) pursuant to which Triad Hunter agreed to sell to Antero all of Triad Hunter’s right, title and interest in certain undeveloped and unproven leasehold acreage located in Tyler County, West Virginia. The sale transaction closed on June 18, 2015 and Triad Hunter received cash consideration of $33.6 million , subject to post-closing adjustments for any title defects and for remediation of asserted title defects. During the third quarter of 2015, the Company received $4.2 million of additional consideration for title defects cured or removed. The properties sold consisted of ownership interests in approximately 5,210 net leasehold acres. The Company recognized a gain on the sale of approximately $31.7 million .

OIL & NATURAL GAS SALES

OIL & NATURAL GAS SALES	12 Months Ended
	Dec. 31, 2015
Oil and Natural Gas Sales [Abstract]
OIL & NATURAL GAS SALES	NOTE 6 - OIL & NATURAL GAS SALES During the years ended December 31, 2015 , 2014 , and 2013 , the Company recognized sales from oil, natural gas, and natural gas liquids (“NGLs”) as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Oil $ 42,805 $ 131,109 $ 147,798 Natural gas 69,533 91,277 53,821 NGLs 21,110 46,115 19,080 Total oil and natural gas sales $ 133,448 $ 268,501 $ 220,699

PROPERTY, PLANT, & EQUIPMENT

PROPERTY, PLANT, & EQUIPMENT	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, & EQUIPMENT	NOTE 7 - PROPERTY, PLANT, & EQUIPMENT Oil and Natural Gas Properties Capitalized Costs The following sets forth the net capitalized costs under the successful efforts method for oil and natural gas properties as of: December 31, 2015 2014 (in thousands) Mineral interests in properties: Unproved leasehold costs $ 398,302 $ 481,643 Proved leasehold costs 198,458 257,185 Wells and related equipment and facilities 469,578 560,060 Uncompleted wells, equipment and facilities — 46,346 Advances to operators for wells in progress 1,279 1,411 Total costs 1,067,617 1,346,645 Less accumulated depreciation, depletion, and amortization (369,347 ) (248,410 ) Net capitalized costs $ 698,270 $ 1,098,235 Depreciation, depletion, and amortization expense for proved oil and natural gas properties was $122.2 million , $121.9 million , and $69.0 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. During the years ended December 31, 2015 , 2014 and 2013 , the Company recorded proved property impairments as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Williston Basin $ 64,165 $ 261,270 $ 8,498 Appalachian Basin $ 207,340 6,001 1,151 Western Kentucky $ 3,783 33,811 40,043 South Texas $ 87 194 319 $ 275,375 $ 301,276 $ 50,011 Impairment of proved oil and gas properties related to Western Kentucky during the years ended December 31, 2014 and 2013 included write-downs to fair value of MHP’s proved oil and gas property of $33.8 million and $26.9 million , respectively. Exploration The following table provides the Company’s exploration expense for 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in thousands) Geological and geophysical $ 2,317 $ 1,564 $ 1,402 Leasehold impairments: Williston Basin 45,811 103,147 89,167 Appalachian Basin 11,501 9,978 6,773 Western Kentucky 75 3,820 3,047 South Texas 127 — — $ 59,831 $ 118,509 $ 100,389 The Company did not drill any dry holes during the years ended December 31, 2015 , 2014 , or 2013 . All wells drilled were completed as commercially productive wells. 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 December 31, 2015 and 2014 , is summarized as follows: December 31, 2015 2014 (in thousands) Gas transportation, gathering and processing equipment and other $ 100,916 $ 100,436 Less accumulated depreciation (30,648 ) (23,013 ) Net capitalized costs $ 70,268 $ 77,423 Depreciation expense for other property and equipment was $8.0 million , $22.1 million , and $15.6 million , for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Depreciation expense for the years ended December 31, 2014 and 2013 includes depreciation expense relating to Eureka Midstream Holdings of $14.4 million and $9.9 million , respectively.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 8 - ASSET RETIREMENT OBLIGATIONS The Company’s ARO liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and its risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. Revisions to the ARO are recorded with a corresponding change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of the Company’s wells, the costs to ultimately retire its wells may vary significantly from prior estimates. The Company’s liability for its ARO was approximately $28.7 million and $26.5 million at December 31, 2015 and 2014 , respectively. The following table summarizes the changes in the Company’s ARO balances during the years ended December 31, 2015 and 2014 : December 31, 2015 2014 (in thousands) Asset retirement obligation at beginning of period $ 26,524 $ 16,216 Liabilities incurred 40 218 Liabilities settled (346 ) (107 ) Liabilities sold (254 ) (2,598 ) Accretion expense 2,597 1,478 Revisions in estimated liabilities 101 3,208 Reclassified from liabilities associated with assets held for sale — 8,109 Asset retirement obligation at end of period 28,662 26,524 Less: current portion (1,464 ) (295 ) Asset retirement obligation at end of period $ 27,198 $ 26,229

FAIR VALUE OF FINANCIAL INSTRUM

FAIR VALUE OF FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	NOTE 9 - 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: i. Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets; ii. 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; iii. Level 3 — Significant inputs to the valuation model are unobservable. Transfers between levels of the fair value hierarchy occur at the end of the reporting period in which it is determined that the observability of significant inputs has increased or decreased. There were no transfers between levels of the fair value hierarchy during 2015 and 2014 . The Company used the following fair value measurements for certain of its assets and liabilities at December 31, 2015 and 2014 : Level 1 Classification: Available for Sale Securities At December 31, 2015 and 2014 , the Company held common and preferred stock of publicly traded companies with quoted prices in an active market. Accordingly, the fair market value measurements of these securities have been classified as Level 1. Level 2 Classification: Commodity Derivative Instruments The Company had commodity derivative financial derivatives in place at December 31, 2014 , but no open contracts remaining at December 31, 2015 . 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 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 derivative instruments are valued using public indices, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange. See “Note 10 - Investments and Derivatives”. Level 3 Classification: Convertible Security Embedded Derivative At December 31, 2014, the Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with a convertible note from GreenHunter Resources, Inc. (“GreenHunter”), a related party. The convertible security embedded derivative was valued using a Black-Scholes model valuation of the conversion option. At December 31, 2015, the embedded derivative had no remaining fair value. The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2015 and 2014 : Fair Value Measurements on a Recurring Basis December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Available for sale securities $ 157 $ — $ — Total assets at fair value $ 157 $ — $ — Fair Value Measurements on a Recurring Basis December 31, 2014 (in thousands) 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 the fair value of the derivative assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31, 2015 , 2014 and 2013 : Embedded Derivatives Series A Preferred Units Convertible Security (in thousands) Fair value at December 31, 2012 $ (43,548 ) $ 264 Issuance of embedded liability (14,645 ) — Change in fair value recognized in loss on derivative contracts, net (17,741 ) (185 ) Fair value at December 31, 2013 $ (75,934 ) $ 79 Issuance of redeemable preferred stock (5,479 ) — Change in fair value recognized in loss on derivative contracts, net (91,792 ) (4 ) Conversion of Eureka Midstream Holdings Series A Preferred Units to Series A-2 Units 173,205 — Fair value at December 31, 2014 $ — $ 75 Change in fair value recognized in loss on derivative contracts, net — (75 ) Fair value at December 31, 2015 $ — $ — During the year ended December 31, 2014, the valuation of the conversion feature embedded in the Eureka Midstream Holdings Series A Preferred Units increased the fair value of the embedded derivative liability by approximately $91.8 million as a result of changes in the total enterprise value of Eureka Midstream Holdings and the Company’s estimate of the expected remaining term of the conversion feature up to and prior to conversion. Management’s estimate of the expected remaining term of the conversion option shortened the time horizon previously estimated by management, resulting in a higher fair value of the conversion feature. Management’s estimates were based upon several factors, including market prices for like-kind transactions, an estimate of the likelihood of each of the possible settlement options, which included redemption through a call or put option, or a liquidity event that triggers conversion to Class A Common Units of Eureka Midstream Holdings. Other Fair Value Measurements The following table presents the carrying amounts and fair values categorized by fair value hierarchy level of the Company’s financial instruments not carried at fair value: Fair Value December 31, 2015 December 31, 2014 Hierarchy Level Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value (in thousands) Senior Notes Level 2 $ 599,305 $ 161,520 $ 597,355 $ 498,000 Second Lien Term Loan Level 3 355,853 211,588 329,140 329,140 Equipment notes payable Level 3 15,482 15,482 22,238 22,150 Senior Secured Bridge Financing Facility Level 3 70,000 70,000 — — Debtor-in-Possession Credit Facility Level 3 40,000 40,000 — — 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 fair value of the Company’s Second Lien Term Loan as of December 31, 2015 is based upon the anticipated recovery value of the loan per the RSA. The carrying value of the Company’s Second Lien Term Loan as of December 31, 2014 approximated fair value based upon the limited passage of time since being issued at a 3% discount and the Company’s credit rating remaining stable since entering into the Second Lien Term Loan on October 22, 2014. The carrying value of the Senior Secured Bridge Financing Facility approximates fair value as of December 31, 2015 due to the limited passage of time since entering into the agreement on November 3, 2015 and the subsequent payment in full of the outstanding balance on January 14, 2016. The carrying value of the Debtor-in-Possession Credit Facility approximates fair value as of December 31, 2015 due to the limited passage of time since entering into the agreement on December 17, 2015. 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 Magnum Hunter, 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 the fair value of retained interests in deconsolidated subsidiaries, measurements of oil and natural gas property impairments, and the initial recognition of AROs, 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, Magnum Hunter has designated these measurements as Level 3. A reconciliation of the beginning and ending balances of Magnum Hunter’s ARO is presented in “Note 8 - Asset Retirement Obligations” . Other fair value measurements made on a non-recurring basis during the years ended December 31, 2015 , 2014 , and 2013 consist of the following: Fair Value Measurements on a Non-recurring Basis (Level 1) (Level 2) (Level 3) (in thousands) Year ended December 31, 2015 Fair value of proved properties impaired $ — $ — $ 298,689 Fair value of interest in Eureka Midstream Holdings — — 163,362 Year ended December 31, 2014 Fair value of proved properties impaired $ — $ — $ 584,895 Fair value of long-lived assets of MHP — — 28,443 Fair value of retained interest in Eureka Midstream Holdings — — 347,291 Year ended December 31, 2013 Fair value of proved properties impaired $ — $ — $ 329,409 Fair value of acquisitions — — 87,149 Proved Properties Impairment The Company recorded impairment charges from continuing operations of $275.4 million , $301.3 million , and $50.0 million during the years ended December 31, 2015 , 2014 and 2013 , respectively, as a result of writing down the carrying value of certain properties to fair value. See “Note 7 - Property, Plant, & Equipment” for a summary of impairment charges by region. 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, risk-adjusted probable, and risk-adjusted 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 market-based 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. Impairment of Long-Lived Assets of MHP During 2014, the Company measured the carrying value of certain long-lived assets of MHP previously classified as held for sale at their fair value in connection with their reclassification to assets held and used. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” . The fair value of these assets was derived using a variety of assumptions including market precedent transactions for similar assets, analyst pricing, and risk-adjusted discount rates for similar transactions. The Company has designated these valuations as Level 3. Retained Interest in Eureka Midstream Holdings On December 18, 2014, the Company sold to MSI a common equity interest in Eureka Midstream Holdings comprising approximately 5.5% of the total common equity interests in Eureka Midstream Holdings pursuant to the Transaction Agreement and Letter Agreement. The closing of this transaction, and other transactions contemplated by the Transaction Agreement and Letter Agreement, resulted in the Company’s investment in Eureka Midstream Holdings changing from a controlling financial interest in a consolidated subsidiary to an equity method investment in Eureka Midstream Holdings. As a result, the Company remeasured its retained interest in Eureka Midstream Holdings at fair value. See “Note 4 - Eureka Midstream Holdings”. The fair value of the Series A-2 Units issued to MSI upon extinguishment of its Class A Common Units and Series A Preferred Units, the downward adjustment of the Company’s Series A-1 Units and the Company’s retained interest was determined by utilizing a hybrid of a probability-weighted expected return model and an option pricing model. This methodology involves an analysis of future values for the enterprise under a range of different scenarios and corresponding allocations of the enterprise value outcomes to the various securities having a claim on value. The key assumptions used in the model to determine fair value were as follows: (i) the pricing to be achieved upon a liquidating event or initial public offering, (ii) the cost of equity for Eureka Midstream Holdings, (iii) the timing and probability of an initial public offering as contemplated in the New LLC Agreement of Eureka Midstream Holdings at discreet points in time, and (iv) the expected volatility of the equity of Eureka Midstream Holdings. On November 3, 2015, the Company measured the carrying value of its interest in Eureka Midstream Holdings previously classified as assets of discontinued operations at fair value. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” . The fair value was determined by utilizing a combination of income and market approaches, as well as an option pricing model considering the differing rights and preferences of the various securities having a claim on value. Key assumptions used in the model to determine fair value included the cost of capital of Eureka Midstream Holdings and the expected volatility of the equity of Eureka Midstream Holdings.

INVESTMENTS AND DERIVATIVES

INVESTMENTS AND DERIVATIVES	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
INVESTMENTS AND DERIVATIVES	NOTE 10 - INVESTMENTS AND DERIVATIVES Investment Holdings - Available for Sale Securities The Company owns 2,619,981 shares of common stock of Redstar Gold Corp., which is publicly traded on the TSX Venture Exchange. During the third quarter of 2015, the Company reviewed the business outlook and market conditions for this investment and recorded an other-than-temporary impairment of $0.4 million which was reclassified from accumulated other comprehensive income into Other income (expense) on the consolidated statements of operations. The investment in common stock of Redstar Gold Corp. had a fair value of $75,581 and $90,120 at December 31, 2015 and 2014 , respectively. The Company owns 88,000 shares of GreenHunter 10% Series C Preferred Stock, which is publicly traded. During the third quarter of 2015, the Company reviewed the business outlook and market conditions for this investment and recorded an other-than-temporary impairment of $0.8 million which was reclassified from accumulated other comprehensive income into Other income (expense) on the consolidated statements of operations. The Series C Preferred Stock had a fair value of $80,961 and $1.3 million at December 31, 2015 and 2014 , respectively. On April 24, 2013, the Company received 10.0 million shares of common stock of Penn Virginia Corporation valued at approximately $42.3 million as partial consideration for the sale of its wholly owned subsidiary, Eagle Ford Hunter. As of September 30, 2013, the Company had sold all of the shares of Penn Virginia common stock, for total gross proceeds of approximately $50.6 million in cash, recognizing a gain of $8.3 million reclassified from accumulated other comprehensive income into “ Other income (expense) ” on the consolidated statements of operations. On January 28, 2014, the Company acquired 65,650,000 common shares of NSE valued at approximately $9.4 million (based on the closing market price of $0.14 per share on January 28, 2014) in partial consideration of an asset sale. During the first quarter of 2015, 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 income (expense) ” on the consolidated statements of operations, related to the decline in value of its investment in NSE. Effective October 20, 2015, the Company sold its entire investment in NSE for cash consideration of approximately AUD $0.7 million (approximately $0.5 million USD). The Company recognized a gain on the sale of approximately $0.1 million . Investment Holdings - Equity Method Investments GreenHunter The Company holds an equity method investment in 1,846,722 restricted common shares of GreenHunter. The GreenHunter common stock investment is accounted for under the equity method and had no carrying value as of December 31, 2015 or 2014 . The GreenHunter common shares are publicly traded and have a fair value of $0.2 million and $1.3 million at December 31, 2015 and 2014 , respectively, which is not reflected in the carrying value since the Company’s investment is accounted for using the equity method. Eureka Midstream Holdings As discussed in “Note 4 - Eureka Midstream Holdings”, on December 18, 2014, the Company no longer held a controlling financial interest in Eureka Midstream Holdings as a result of capital contributions made by MSI to Eureka Midstream Holdings and a subsequent sale by the Company of a portion of its equity interest in Eureka Midstream Holdings to MSI. The Company continues to exercise significant influence through its retained equity interest of 44.53% as of December 31, 2015 and through representation on Eureka Midstream Holdings’ board of managers. As a result, the Company uses the equity method to account for its retained interest. The carrying value of the Company’s equity interest in Eureka Midstream Holdings was $166.1 million and $347.2 million as of December 31, 2015 and 2014 , respectively. Below is a summary of changes in investments for the years ended December 31, 2015 , 2014 , and 2013 : Available for Sale Securities Equity Method Investments (in thousands) Carrying value at December 31, 2012 $ 1,958 $ 2,072 Securities received as consideration 42,300 — Sales of securities (50,562 ) — Realized gain recognized in net income 8,262 — Decrease in carrying amount return of capital — (138 ) Loss from equity method investment — (994 ) Other adjustments (55 ) — Change in fair value recognized in other comprehensive loss (84 ) — Carrying value at December 31, 2013 $ 1,819 $ 940 Securities received as consideration 9,446 — Fair value of retained interest in Eureka Midstream Holdings — 347,292 Loss from equity method investment — (1,038 ) Other adjustments — (3 ) Change in fair value recognized in other comprehensive loss (7,401 ) — Carrying value at December 31, 2014 $ 3,864 $ 347,191 Sales of securities (472 ) — Gain on dilution of interest in Eureka Midstream Holdings — 4,601 Loss from equity method investment (1) (464 ) (185,693 ) Other adjustments — — Change in fair value recognized in other comprehensive loss (2,771 ) — Carrying value at December 31, 2015 $ 157 $ 166,099 _________________ (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 December 31, 2015 and December 31, 2014 as follows: December 31, 2015 (in thousands) Available for Sale Securities Equity Method Investments Total Investments - Current $ 157 $ — $ 157 Investments - Non-current — 166,099 166,099 Carrying value as of December 31, 2015 $ 157 $ 166,099 $ 166,256 December 31, 2014 (in thousands) Available for Sale Securities Equity Method Investments Total Investments - Current $ 3,864 $ — $ 3,864 Investments - Non-current — 347,191 347,191 Carrying value as of December 31, 2014 $ 3,864 $ 347,191 $ 351,055 The cost for equity securities and their respective fair values as of December 31, 2015 and 2014 are as follows: December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (in thousands) Securities available for sale, carried at fair value: Equity securities $ 78 $ — $ (2 ) $ 76 Equity securities - related party (see “Note 17 - Related Party Transactions”) 465 — (384 ) 81 Total Securities available for sale $ 543 $ — $ (386 ) $ 157 December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (in thousands) Securities available for sale, carried at fair value: Equity securities $ 9,876 $ — $ (7,323 ) $ 2,553 Equity securities - related party (see “Note 17 - Related Party Transactions”) 2,200 — (889 ) 1,311 Total Securities available for sale $ 12,076 $ — $ (8,212 ) $ 3,864 Commodity and Financial Derivative Instruments The Company has no remaining open commodity derivative contracts as of December 31, 2015. On May 7, 2015, the Company obtained consent under the MHR Senior Revolving Credit Facility to terminate the Company’s open commodity derivative positions. The Company received approximately $11.8 million in cash proceeds from the termination of the majority of its open commodity derivative positions that were terminated on May 7, 2015. On November 2, 2015, the Company terminated its open commodity derivative positions with Bank of Montreal and received approximately $0.9 million in cash proceeds. On December 31, 2015, the Company’s commodity derivative positions with Citibank, N.A. expired. The Company has in the past periodically entered into certain commodity derivative instruments such as futures contracts, swaps, collars, and basis swap contracts, which are effective in mitigating commodity price risk associated with a portion of its future monthly natural gas and crude oil production and related cash flows. The Company has not designated any of its past commodity derivatives as hedges. In a commodities swap agreement, the Company has in the past traded 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 helps reduce exposure to price risk and improves 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 agreed to pay the counterparty is expected to be offset by the increased amount it received for its production. Occasionally, the Company has in the past also entered into three-way collars with third parties. These instruments typically establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any amounts. If the index price is above the ceiling, the Company pays the excess over the ceiling price. The advantage to the Company of the three-way collar is that the proceeds from the second floor allow us to lower the total cost of the collar. As further discussed in “Note 11 - Long-Term Debt” , as of October 8, 2015, the Company had an event of default under the MHR Senior Revolving Credit Facility and its Second Lien Term Loan Agreement which resulted in a cross-default under the Company’s derivative contracts with Bank of Montreal, and which could have resulted in a cross-default under the Company’s derivative contracts with Citibank, N.A. if the outstanding loan obligations under the related credit agreements had been accelerated. Under the Company’s derivative contracts, upon a cross-default the non-defaulting party may designate an early termination date for all outstanding transactions. The counterparties to the Company’s derivative contracts did not designate early termination dates for any of the Company’s outstanding commodities derivatives. At December 31, 2014 , the Company had recognized an embedded derivative asset associated with the conversion feature of the promissory note receivable from GreenHunter received as partial consideration for the sale of Hunter Disposal. As of December 31, 2015 the Company recognized no remaining fair value associated with this embedded derivative asset. See “Note 9 - Fair Value of Financial Instruments” and “Note 17 - Related Party Transactions” . The following table summarizes the fair value of the Company’s derivative contracts as of December 31, 2014: Derivatives not designated as hedging instruments December 31, 2014 Commodity (in thousands) Derivative assets $ 16,511 Total commodity $ 16,511 Financial Derivative assets $ 75 Total financial $ 75 Total derivatives $ 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 Company had no remaining open commodity derivatives contracts as of December 31, 2015. The table below summarizes the Company’s commodity derivatives and the effect of master netting arrangements on the presentation in the Company’s consolidated balance sheets as of December 31, 2014. 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 — Total fair value of derivative contracts $ 16,511 $ — $ 16,511 The following table summarizes the net gain (loss) on all derivative contracts included in other income (expense) on the consolidated statements of operations for the years ended December 31, 2015 , 2014 and 2013 : For the Year Ended December 31, 2015 2014 2013 (in thousands) Gain (loss) on settled transactions $ 2,449 $ 1,306 $ (8,216 ) Gain (loss) on open contracts 2,437 18,232 (17,058 ) Loss on extinguished embedded derivative — (91,792 ) — Total gain (loss), net $ 4,886 $ (72,254 ) $ (25,274 )

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
DEBT	NOTE 11 - LONG-TERM DEBT Notes payable at December 31, 2015 and 2014 consisted of the following: As of December 31, 2015 2014 (in thousands) MHR Senior Revolving Credit Facility $ — $ — Senior Secured Bridge Financing Facility, interest rate of 4.2% at December 31, 2015 70,000 — Debtor-in-Possession Credit Facility, interest rate of 9.00% at December 31, 2015 40,000 — Second Lien Term Loan due October 22, 2019, interest rate of 8.5%, net of unamortized discount of $10.0 million at December 31, 2014 335,853 329,140 Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.6 million at December 31, 2014 599,305 597,355 Various equipment and real estate notes payable with maturity dates April 2016 - November 2017, interest rates of 4.25% - 8.70% 15,482 22,238 $ 1,060,640 $ 948,733 Less: current portion (83,682 ) (10,770 ) Less: debtor-in-possession financing (40,000 ) — Less: liabilities subject to compromise (see “Note 3 - Voluntary Reorganization under Chapter 11”) (936,958 ) — Total long-term debt obligations not subject to compromise, net of current portion $ — $ 937,963 The following table presents the approximate annual maturities of debt: (in thousands) 2016 $ 1,060,640 2017 — 2018 — 2019 — 2020 — Thereafter — $ 1,060,640 MHR Senior Revolving Credit Facility At various times, the Company maintained an asset-based, senior secured revolving credit facility (the “MHR Senior Revolving Credit Facility”) by and among the Company, Bank of Montreal, as Administrative Agent, the lenders party thereto and the agents party thereto. The borrowing base was generally derived from the Company’s proved crude oil and natural gas reserves and was subject to regular semi-annual redeterminations. The MHR Senior Revolving Credit Facility was amended in 2013 and 2014 to, among other things, amend the borrowing base, include letters of credit in the facility, and amend financial covenants. On October 22, 2014 all amounts outstanding under the MHR Senior Revolving Credit Facility were converted to a $340 million Second Lien Term Loan and the MHR Senior Revolving Credit Facility was reduced to an initial borrowing base of $50 million subject to semi-annual borrowing base redeterminations derived from the Company’s proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base could be decreased or increased up to a maximum commitment level of $250 million . The terms of the October 22, 2014 amendment provided that the MHR Senior Revolving Credit Facility could be used for loans, and subject to a $50 million sublimit, letters of credit. The October 22, 2014 amendment provided for a commitment fee of 0.5% of the unused portion of the borrowing base. Borrowings under the MHR Senior Revolving Credit Facility, at the Company’s election, bore interest at either (i) an ABR equal to the higher of (a) the Prime Rate (as determined by the Bank of Montreal), (b) the overnight federal funds effective rate, plus 0.50% per annum, and (c) the adjusted one-month LIBOR plus 1.00% or (ii) the adjusted LIBO Rate (which is based on LIBOR), plus, in each of the cases described in clauses (i) and (ii), an applicable margin ranging from 1.00% to 2.00% for ABR loans and from 2.00% to 3.00% for adjusted LIBO Rate loans. Accrued interest on each ABR loan was payable in arrears on the last day of each March, June, September and December and accrued interest on each adjusted LIBO Rate loan was payable in arrears on the last day of the interest period. The October 22, 2014 amendment contained various negative covenants, as well as financial covenants relating to the Company’s current ratio, leverage ratio, and the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement described below. Subject to certain exceptions, the MHR Senior Revolving Credit Facility was secured by substantially all of the assets of the Company and its restricted subsidiaries, including, without limitation, no less than 90% of the present value (with a discount rate of 10% ) of the proved oil and gas reserves of the Company and its restricted subsidiaries. Additionally, any collateral pledged as security for the Second Lien Term Loan (as defined below) was required to be pledged as security for the MHR Senior Revolving Credit Facility. On February 24, 2015, April 17, 2015, May 28, 2015, June 19, 2015 and July 10, 2015 the MHR Senior Revolving Credit Facility was amended to, among other things, waive or amend certain financial covenants, limit certain capital expenditures, increase the interest rate, limit dividends on preferred stock, and terminate the Company’s open commodity derivatives positions. Defaults under the MHR Senior Revolving Credit Facility On July 27, 2015, the Company became aware of a default under the MHR Senior Revolving Credit Facility relating to the aging of the Company’s accounts payable. In accordance with the terms of the MHR Senior Revolving Credit Facility agreement, the Company was not permitted to have accounts payable outstanding (subject to certain permissible amounts) in excess of 180 days from the invoice date for any day on or prior to the earlier of (a) December 31, 2015 or (b) the date that is ten business days following the date on which the Company consummates the sale of all or substantially all of the Company’s equity ownership interest in Eureka Midstream Holdings, after which earlier date the restriction reverted back to 90 days. The Company cured the default on August 26, 2015. On September 8, 2015, the Company became aware of an additional default under the MHR Senior Revolving Credit Facility because the Company had approximately $1.4 million in accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date. Under the MHR Senior Revolving Credit Facility, the Company had 30 days to cure this default. As of October 8, 2015, the Company continued to have accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date, resulting in an event of default. Due to the event of default, the lenders under the MHR Senior Revolving Credit Facility were permitted to, but did not, declare the outstanding loan amounts immediately due and payable. The event of default described above under the MHR Senior Revolving Credit Facility resulted in an event of default under the Second Lien Term Loan Agreement and the Equipment Note Payable (as defined below). Furthermore, the event of default regarding accounts payable under the Second Lien Term Loan Agreement, as described below, resulted in a cross-default under the MHR Senior Revolving Credit Facility. The event of default under the MHR Senior Revolving Credit Facility also resulted in a cross-default under the Company’s then-outstanding derivatives contracts with Bank of Montreal. However, the Company did not receive any notice of cross-default from Bank of Montreal with respect to such derivatives contracts. In addition, on November 2, 2015, the Company chose to terminate all of its open commodity derivative positions with Bank of Montreal and received approximately $0.9 million in cash proceeds. See “Note 10 - Investments and Derivatives” . On and effective as of November 3, 2015, the Company entered into a Senior Secured Bridge Financing Facility which replaced the MHR Senior Revolving Credit Facility. Senior Secured Bridge Financing Facility On and effective as of November 3, 2015, the Company entered into a Senior Secured Bridge Financing Facility with certain holders of its Senior Notes and lenders under its Second Lien Term Loan (the “New First Lien Lenders”). The Senior Secured Bridge Financing Facility, among other things, replaced the MHR Senior Revolving Credit Facility and provided the Company with additional capital as follows: i. All borrowings outstanding under the MHR Senior Revolving Credit Facility, which were approximately $5.0 million , were effectively paid off; ii. Certain outstanding letters of credit in an aggregate amount of approximately $39.0 million issued under the MHR Senior Revolving Credit Facility were cash collateralized (and are included in “Other assets” in the accompanying consolidated balance sheet as of December 31, 2015); and iii. The Company was provided with cash proceeds of approximately $16 million , which was used to pay for expenses associated with the Senior Secured Bridge Financing Facility as well as for general corporate purposes. As a result, the MHR Senior Revolving Credit Facility with Bank of Montreal was effectively paid off and canceled and replaced with the Senior Secured Bridge Loan Financing Facility with the New First Lien Lenders as creditors. The aggregate amounts outstanding under the Senior Secured Bridge Loan Facility as of November 3, 2015 totaled approximately $60 million . In addition, the Senior Secured Bridge Financing Facility included an uncommitted incremental credit facility for up to an additional $10.0 million aggregate principal amount of term loans to be provided to the Company, if and to the extent requested by the Company and agreed to by a specified percentage of the New First Lien Lenders. Effective as of November 30, 2015, the Company entered into the Seventh Amendment to Credit Agreement whereby the Company requested and received an aggregate principal amount of $10 million in new borrowings under the Senior Secured Bridge Financing Facility. Borrowings under the Senior Secured Bridge Financing Facility were due and payable on the earlier of: (a) December 30, 2015, (b) in the case of an event of default under the Senior Secured Bridge Financing Facility, the acceleration of the payment of the term loans, as determined by the requisite percentage of the New First Lien Lenders, or (c) the filing of a Chapter 11 case (or cases) by the Company or any of its subsidiaries. The Senior Secured Bridge Financing Facility bore interest, at the Company’s option, at either the London Interbank Offered Rate, plus an applicable margin of 4.0% , or a specified prime rate of interest, plus an applicable margin of 3.0% . The Senior Secured Bridge Financing Facility contained the same covenants as the amended MHR Senior Revolving Credit Facility, subject to customary adjustments consistent with financings of this type and duration and subject to the following additional changes: i. Removal of all financial covenants in effect under the amended MHR Senior Revolving Credit Facility (including the current ratio, leverage ratio, proved reserves coverage ratio and proved developed producing reserves coverage ratio covenants); ii. Removal of restrictions against trade payables being outstanding for more than 180 days from the date of invoice; and iii. Inclusion of budgetary and reporting requirements consistent with financings of this type and duration, including a cumulative budget variance covenant tested every other week, in accordance with the terms of the Senior Secured Bridge Financing Facility. The Senior Secured Bridge Financing Facility also contained restrictions on the sale of assets by the Company and its restricted subsidiaries, which restrictions, among other things, prohibited (i) the Company from selling its equity ownership interests in Eureka Midstream Holdings (the “EHH Interests”) and (ii) the Company and its restricted subsidiaries from engaging in certain farm-outs of undeveloped acreage, without, in each case, first obtaining the requisite consent of the New First Lien Lenders. Additionally, the Senior Secured Bridge Financing Facility contained a standstill on any marketing by the Company of the sale of the EHH Interests, other than with bidders that contacted the Company without prior solicitation and other than any bidders that had already been engaged in such marketing efforts with the Company as of the closing date of the Senior Secured Bridge Financing Facility. As of December 31, 2015, the balance outstanding under the Senior Secured Bridge Financing Facility was $70.0 million and is included in “Current portion of long-term debt” in the accompanying consolidated balance sheet. On January 14, 2016, the Senior Secured Bridge Financing Facility and outstanding interest was paid in full with proceeds from borrowings under the Debtor-in-Possession Credit Facility. Debtor-in-Possession Credit Facility In connection with the Chapter 11 Cases, on the Petition Date the Company filed a motion seeking Bankruptcy Court approval of debtor-in-possession financing on the terms set forth in a Debtor-in-Possession Credit Agreement (as amended from time to time, the “DIP Credit Agreement”). On December 16, 2015, the Bankruptcy Court entered an order approving, on an interim basis, the financing to be provided pursuant to the DIP Credit Agreement ( i.e. , the Interim DIP Order) and, on December 17, 2015, the DIP Credit Agreement was entered into by and among the Company, as borrower, the Filing Subsidiaries, as guarantors, the DIP Lenders (as defined below) and Cantor Fitzgerald Securities, as administrative agent and as collateral agent for the DIP Lenders. The DIP Credit Agreement provides for senior secured term loans in the aggregate principal amount of up to $200 million (the “DIP Facility”), which consists of: i. a term loan in the principal amount of $40 million (the “First DIP Draw”); ii. a term loan in the principal amount of $100 million (the “Second DIP Draw”); and iii. a term loan in the principal amount of $60 million (the “Third DIP Draw”). The First DIP Draw was funded, net of certain fees and expenses, on December 17, 2015. The net proceeds from the First DIP Draw were used to fund (a) payments in accordance with the orders approved on the Petition Date, (b) adequate protection payments, and (c) working capital, in each case, in accordance with the budget variance financial covenant. The Second DIP Draw was fully funded on January 14, 2016 following the Bankruptcy Court’s entry of an order approving, on a final basis, the financing provided pursuant to the DIP Credit Agreement ( i.e. , the Final DIP Order). Approximately $70.2 million of the net proceeds from the Second DIP Draw was used to repay in full all loans outstanding under the Company’s Senior Secured Bridge Financing Facility and approximately $25.5 million was made available to the Company to be used for general corporate purposes, subject to the DIP Facility budget. The Third DIP Draw was fully funded on April 21, 2016, following the satisfaction of certain conditions pursuant to the DIP Credit Agreement. Subject to certain conditions, the maturity date of the DIP Facility is the earlier of: i. Nine months from the closing date of the DIP Facility; ii. 31 days after entry of the Interim DIP Order if the Final DIP Order had not been entered into by the Bankruptcy Court; iii. The effective date of the Plan; iv. The consummation of a sale of all or substantially all of the assets of the Company and its subsidiaries pursuant to Section 363 of the Bankruptcy Code; and v. The date of termination of the DIP Lenders’ Commitments (as defined in the DIP Credit Agreement) and the acceleration of any outstanding extensions of credit, in each case, under the DIP Facility in accordance with the terms of the Loan Documents (as defined in the DIP Credit Agreement). Interest on the outstanding principal amount of the term loans under the DIP Facility will be payable monthly in arrears and on the maturity date at a per annum rate equal to LIBOR plus 8.00% , subject to a 1.00% floor. Upon an event of default under the DIP Facility, all obligations under the DIP Credit Agreement will bear interest at a rate equal to the then current interest rate plus an additional 2% per annum. The principal amount of the term loans under the DIP Facility is payable in full at maturity. The Company paid to the lenders under the DIP Credit Agreement a commitment fee equal to 2% of the lenders’ respective commitments thereunder upon entry of the Final DIP Order. Additionally, if the Plan is consummated, the Debtors will pay a backstop fee equal to 3% of the lenders’ respective commitments in the form of new common equity of the reorganized Company, and if the Plan is not consummated, the Company will pay such fee in cash, which shall not take into account the Third DIP Draw amount unless such Third DIP Draw is actually funded. Pursuant to the terms of the DIP Credit Agreement and related guaranty, the Filing Subsidiaries have guaranteed the obligations of the Company, as borrower under the DIP Facility. The obligations under the DIP Credit Agreement are secured by liens on substantially all of the Company’s assets as follows: i. (a) up to $70 million of obligations under the DIP Facility are secured by perfected first priority “priming liens” on the Company’s prepetition liens (including prepetition liens securing the Second Lien Term Loan), and (b) other obligations under the DIP Facility are secured by perfected junior liens on the Company’s prepetition liens (including liens securing the Second Lien Term Loan), subject to certain exceptions and intercreditor arrangements; and ii. the obligations under the DIP Facility are secured by perfected first priority liens on the Company’s unencumbered assets, subject to certain exceptions, including an exception for the Company’s equity interest in Eureka Midstream Holdings as noted below. The DIP Credit Agreement is not secured by the Company’s equity interest in Eureka Midstream Holdings. However, the DIP Credit Agreement is secured by the Company’s economic interest in Eureka Midstream Holdings. The DIP Lenders can take ownership of such economic interest in Eureka Midstream Holdings in the event of a liquidation of the Debtors, but will not have the ability to foreclose on such economic interest solely as a result of an event of default occurring under the DIP Credit Agreement. Upon an event of default under the DIP Credit Agreement, the DIP Lenders shall be entitled to require the Debtors to sell such equity interest at a price and on terms as the DIP Lenders deem commercially reasonable, and the DIP Lenders shall be entitled to credit bid all or a portion of the outstanding DIP Credit Agreement obligations in such sale. The security interests and liens under the DIP Credit Agreement are subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement. The Debtors are subject to certain covenants under the DIP Facility, including, without limitation, restrictions on the incurrence of additional debt, liens, and the making of restricted payments, and compliance with certain bankruptcy-related covenants, in each case as set forth in the DIP Credit Agreement and any order of the Bankruptcy Court approving the DIP Credit Agreement. The DIP Credit Agreement contains customary representations of the Debtors, and provides for certain events of default customary for similar DIP financings. Additionally, the DIP Credit Agreement contains a specific event of default based upon the occurrence of a consecutive 15 -day trading period during which natural gas prices as published by NYMEX are less than $1.65 per MMBtu. Furthermore, each of the following Milestones is included in the DIP Credit Agreement, and any failure to comply with these Milestones will constitute an event of default: i. No later than December 17, 2015, the Bankruptcy Court shall have entered the Interim DIP Order (which has occurred); ii. No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court a motion to reject executory contracts and set procedures regarding rejection damages (which has occurred); iii. No later than January 7, 2016, the Debtors shall have filed with the Bankruptcy Court: (i) the Plan, (ii) the disclosure statement of the Plan, (iii) a motion seeking approval of the disclosure statement of the Plan and the Plan as well as certain other items, and (iv) a motion seeking to assume the RSA (which has occurred); iv. No later than January 15, 2016, the Bankruptcy Court shall have entered the Final DIP Order (which has occurred); v. No later than February 12, 2016, the Bankruptcy Court shall have entered an order approving assumption of the RSA (which has occurred); vi. No later than February 26, 2016, (i) the Bankruptcy Court shall have entered an order approving the disclosure statement with respect to the Plan (which has occurred) and (ii) no later than February 29, 2016, the Debtors shall have commenced solicitation on the Plan (which has occurred); vii. No later than April 18, 2016, the Bankruptcy Court shall have commenced the confirmation hearing on the Plan (which has occurred), and no later than April 19, 2016, the Bankruptcy Court shall have entered the Plan confirmation order (which has occurred); and viii. No later than May 6, 2016, the Debtors shall consummate the transactions contemplated by the Plan. The Company has met all Milestones thus far. The remaining Milestone to be completed is the consummation of the transactions contemplated by the Plan no later than May 6, 2016. There can be no assurance that this Milestone will be achieved. The continuation of the Chapter 11 Cases, particularly if the Plan is not implemented within the timeframe currently contemplated, could adversely affect operations and relationships between the Company and its customers, suppliers, vendors, service providers, and other creditors and result in increased professional fees and similar expenses. Failure to implement the Plan could further weaken the Company’s liquidity position, which could jeopardize the Company’s exit from Chapter 11 reorganization. The DIP Facility is subject to certain prepayment events, including, upon the receipt of proceeds from certain asset sales, insurance and condemnation events and the issuance of post-petition debt or equity, subject in each case to customary exceptions as set forth in the DIP Credit Agreement and any order of the Bankruptcy Court approving the DIP Credit Agreement. The DIP Credit Agreement also provides for the payment of certain adequate protection payments with respect to the Bridge Financing Facility and Second Lien Facility, and includes a budget variance financial covenant which permits a variance of up to 20% on receipts (excluding royalties), disbursements (subject to certain adjustments) and capital expenditures. Upon any termination of the RSA, the Tranche A Lenders have the right to buy from the Tranche B Lenders up to 15% of such Tranche B Lenders’ portion of the funded and unfunded DIP Facility by delivering an irrevocable notice of intent to purchase within 10 days of the date of termination (provided that the purchase is complete within 5 business days). Pursuant to the terms of the RSA, the DIP Facility converts into new common equity of the reorganized Company at a 25% discount to Plan value. Second Lien Term Loan In conjunction with the October 22, 2014 amendment to the MHR Senior Revolving Facility, the Company also entered into a Second Lien Credit Agreement (the “Second Lien Term Loan Agreement”), by and among the Company, as borrower, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, the lenders party thereto and the agents party thereto. The Second Lien Term Loan Agreement provides for a $340 million term loan facility (the “Second Lien Term Loan”), secured by, subject to certain exceptions, a second lien on substantially all of the assets (except unproved leases) of the Company and its restricted subsidiaries. The entire $340 million Second Lien Term Loan was drawn on October 22, 2014, net of a discount of $10.2 million . The Company used the proceeds of the Second Lien Term Loan to repay amounts outstanding under the MHR Senior Revolving Facility, to pay transaction expenses related to the MHR Senior Revolving Facility and the Second Lien Term Loan Agreement, and for working capital and general corporate purposes. Amounts borrowed under the Second Lien Term Loan that are repaid or prepaid may not be reborrowed. The Second Lien Term Loan has a maturity date of October 22, 2019 and will amortize (beginning December 31, 2014) in equal quarterly installments in an aggregate annual amount equal to 1.00% of the original principal amount of the Second Lien Term Loan. Borrowings under the Second Lien Term Loan, at the Company’s election, bore interest at either (i) an alternate base rate (which is equal to the higher of (a) the prime rate (as determined by Credit Suisse AG), (b) the overnight federal funds effective rate, plus 0.50% per annum, and (c) the adjusted one-month LIBOR plus 1.00% ) plus 6.50% or (ii) the adjusted LIBO Rate, which means an interest rate per annum equal to the greater of (a) 1.00% per annum and (b) the product of (i) the LIBO Rate in effect for such Interest Period and (ii) the Statutory Reserve Rate, plus 7.50% . The Second Lien Term Loan Agreement contains negative covenants and financial covenants substantially similar to those in the MHR Senior Revolving Facility that, among other things, restrict the ability of the Company and its restricted subsidiaries to, with certain exceptions: (i) incur indebtedness; (ii) grant liens; (iii) dispose of all or substantially all of its assets or enter into mergers, consolidations, or similar transactions; (iv) change the nature of its business; (v) make investments, loans, or advances or guarantee obligations; (vi) pay cash dividends or make certain other payments; (vii) enter into transactions with affiliates; (viii) enter into sale and leaseback transactions; (ix) enter into hedging transactions; and (x) amend its organizational documents or the MHR Senior Revolving Facility. The Second Lien Term Loan Agreement limited the amount of indebtedness that the Company could have incurred under the MHR Senior Revolving Facility to the greater of (i) the sum of $50 million plus the aggregate amount of loans repaid or prepaid under the Second Lien Term Loan Agreement and (ii) an amount equal to 25% of Adjusted Consolidated Net Tangible Assets (as defined in the Second Lien Term Loan Agreement) of the Company and its restricted subsidiaries; provided, in the case of clause (ii), after giving effect to such incurrence of indebtedness and the application of proceeds therefrom, aggregate secured debt may not exceed 25% of the Adjusted Consolidated Net Tangible Assets of the Company and its restricted subsidiaries as of the date of such incurrence. The Second Lien Term Loan Agreement also requires the Company to satisfy certain financial covenants, including maintaining: i. a ratio of 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 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 ended 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. In connection with the Second Lien Term Loan Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Second Lien Term Loan is unconditionally guaranteed by such restricted subsidiaries. On and effective as of April 17, 2015, the Company entered into a First Amendment to Credit Agreement and Limited Waiver (the “First 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 First Amendment amended the Second Lien Term Loan Agreement by permanently extending the amount of time the Company and its Restricted Subsidiaries (as defined in the Second Lien Term Loan Agreement) may have accounts payable outstanding after the invoice date from 90 days to 180 days. In addition, pursuant to the First 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 First Amendment. On November 3, 2015, the Company entered into a Forbearance Agreement and Second Amendment (the “Second Amendment”) to the Second Lien Credit Agreement. The Second Amendment provided for a forbearance by the lenders under the Second Lien Term Loan Agreement that entered into the Senior Secured Bridge Financing Facility with respect to exercising remedies regarding any default or event of default that results from the failure of the Company to make any interest payment under the Second Lien Term Loan Agreement, the failure to meet certain financial covenants thereunder, and certain other matters (including the default that arose on account of trade payables being outstanding for more than 180 days). The Second Amendment also amends certain other terms of the Second Lien Term Loan Agreement as necessary to permit the Senior Secured Bridge Financing Facility and to make certain covenants in the Second Lien Term Loan Agreement consistent with the revised covenants in the Senior Secured Bridge Financing Facility. The covenants under the Second Lien Term Loan Agreement otherwise remain substantially the same, subject to customary adjustments for such financings described herein. Under the Second Amendment, the lenders under the Second Lien Term Loan Agreement that entered into the Senior Secured Bridge Financing Facility agreed to forbear from exercising remedies under the Second Lien Term Loan Agreement with respect to any failure by the Company to make the October 30, 2015 interest payment under the Second Lien Term Loan Agreement and certain other defaults and events of default (including the default that arose on account of trade payables being outstanding for more than 180 days). The forbearance included in the Second Amendment terminated upon the filing of the Chapter 11 cases by the Debtors. Defaults under the Second Lien Term Loan Agreement On July 27, 2015, the Company became aware of a default under the Second Lien Term Loan Agreement relating to the aging of the Company’s accounts payable. In accordance with the terms of the Second Lien Term Loan Agreement the Company may not have accounts payable outstanding (subject to certain permissible amounts) in excess of 180 days from the invoice date. The Company cured the default in accordance with the Second Lien Term Loan Agreement on August 26, 2015. On September 8, 2015, the Company became aware of an additional default under the Second Lien Term Loan Agreement because the Company had approximately $1.4 million in accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date. Under the Second Lien Term Loan Agreement, the Company had 30 days to cure this default. As of October 8, 2015, the Company continued to have accounts payable outstanding (in excess of permissible amounts) in excess of 180 days from the invoice date, resulting in an event of default. Due to the event of default, the lenders under the Second Lien Term Loan Agreement were permitted to, but did not, declare the outstanding loan amounts immediately due and payable. As described above, under the Second Amendment, the lenders under the Second Lien Term Loan Agreement that entered into the Senior Secured Bridge Financing Facility agreed to forbear from exercising remedies under the Second Lien Term Loan Agreement with respect to any failure by the Company to make the October 30, 2015 interest payment under the Second Lien Term Loan Agreement and certain other defaults (including the default that arose on account of trade payables being outstanding for more than 180 days). The forbearance included in the Second Amendment terminated upon the filing of the Chapter 11 cases by the Debtors. As of December 31, 2015, the balance outstanding under the Second Lien Term Loan Agreement was $335.9 million and is included in “Liabilities subject to compromise” in the accompanying consolidated balance sheet. See “Note 3 - Voluntary Reorganization under Chapter 11” . Under the Bankruptcy Code, the creditors under the Second Lien Term Loan Agreement are stayed from taking any action against the Debtors as a result of any

SHARE-BASED COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
SHARE-BASED COMPENSATION	NOTE 12 - SHARE-BASED COMPENSATION Employees, officers, directors and certain other persons 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 December 31, 2015 , 27,500,000 shares of the Company’s common stock are authorized to be issued under the plan, and 11,539,043 shares have been issued as of December 31, 2015 , of which 3,389,896 shares remained unvested at December 31, 2015 . Additionally, 7,314,751 options to purchase shares were outstanding as of December 31, 2015 , of which 592,801 remained unvested at December 31, 2015 . The Company recognized share-based compensation expense of $6.0 million , $11.4 million , and $13.6 million for the years ended December 31, 2015 , 2014 , and 2013 respectively. A summary of stock option and stock appreciation rights activity for the years ended December 31, 2015 , 2014 , and 2013 is presented below: 2015 2014 2013 Weighted-Average Exercise Price Weighted-Average Exercise Price Weighted-Average Exercise Price Shares Shares Shares Outstanding at beginning of the year 13,194,956 $ 5.91 16,891,419 $ 5.69 14,846,994 $ 6.01 Granted — $ — — $ — 4,937,575 $ 4.11 Exercised (100,000 ) $ 0.51 (2,375,273 ) $ 4.09 (1,466,025 ) $ 3.66 Forfeited or expired (5,780,205 ) $ 6.24 (1,321,190 ) $ 6.27 (1,427,125 ) $ 5.51 Outstanding at end of the year 7,314,751 $ 5.75 13,194,956 $ 5.91 16,891,419 $ 5.69 Exercisable at end of the year 6,721,950 $ 5.89 9,140,323 $ 6.22 9,983,743 $ 5.96 A summary of the Company’s non-vested common stock options and stock appreciation rights for the years ended December 31, 2015 , 2014 , and 2013 is presented below: Non-vested Options 2015 2014 2013 Non-vested at beginning of the year 4,054,633 6,907,476 6,163,372 Granted — — 4,937,575 Vested (1,635,365 ) (1,915,526 ) (3,133,700 ) Forfeited (1,826,467 ) (937,317 ) (1,059,771 ) Non-vested at end of the year 592,801 4,054,633 6,907,476 Total unrecognized compensation cost related to the non-vested common stock options and stock appreciation rights was $0.2 million , $3.2 million , and $14.1 million as of December 31, 2015 , 2014 , and 2013 , respectively. The unrecognized compensation cost at December 31, 2015 is expected to be recognized over a weighted-average period of 0.13 years. At December 31, 2015 , there was no aggregate intrinsic value for the outstanding options and stock appreciation rights; and the weighted average remaining contract life of the outstanding options was 5.33 years. No options or stock appreciation rights were granted during the years ended December 31, 2015 or 2014. The assumptions used in the fair value method calculations for the year ended December 31, 2013 are disclosed in the following table: Year Ended December 31, 2013 Weighted average fair value per option granted during the period (1) $2.52 Assumptions (2) : Weighted average stock price volatility (3) 80.61% Weighted average risk free rate of return 0.78% Weighted average estimated forfeiture rate 2.45% Weighted average expected term 4.65 years ________________________________ (1) Calculated using the Black-Scholes fair value based method for service and performance based grants and the Lattice Model for market based grants. (2) The Company has not paid cash dividends on its common stock. (3) The volatility assumption was estimated based upon a blended calculation of historical volatility and implied volatility over the life of the awards. During the years ended December 31, 2015 , 2014 , and 2013 , the Company granted 128,559 , 105,812 , and 182,994 fully vested shares of common stock, respectively, to the Company’s board members as payment of board and committee meeting fees and chairperson retainers. On January 8, 2014, the Company granted 1,312,575 restricted shares of common stock to officers, executives, and employees of the Company. The shares vest over a 3 -year period with 33% of the restricted shares vesting one year from the date of the grant. The Company also granted 123,798 restricted shares to the directors of the Company which vest 100% one year from the date of the grant. On November 6, 2014, the Company granted 1,451,500 restricted shares of common stock to officers, executives, and employees of the Company which vest over a 3 -year period with 33% of the restricted shares vesting one year from the date of the grant. The Company also granted 216,348 restricted shares to the directors of the Company on November 6, 2014 which vest one year from the date of the grant. The Company granted 65,000 additional restricted shares of common stock to officers, executives, and employees of the Company throughout the year ended December 31, 2014 for a total 3,275,033 restricted shares of common stock granted. The shares had a fair value at the time of grant of $18.5 million based on the stock price on grant date and estimated forfeiture rate of 3.4% . During December 2014 the Compensation Committee of the Board of Directors modified the restricted stock grant which occurred during November 2014. The modification was to fully vest the third tranche of the award which originally would have vested on November 6, 2017. Under the modified terms, the stock award vested one-third on December 19, 2014 and the remaining tranches will vest equally on November 6, 2015 and 2016. The Company recognized $2.6 million incremental compensation expense attributable to the modification. The method used to value the original award and the modified award were the same as described above with the only adjustments being to the expected forfeiture rate for the third tranche. On March 30, 2015, the Company granted 535,274 shares of common stock for 2014 bonuses to executives and officers of the Company. The shares had a fair value at the time of grant of $1.4 million based on the Company’s stock price on the grant date. On June 18, 2015, the Company granted 600,000 restricted shares of common stock to non-employee members of the board of directors of the Company which vest two years from the date of grant, or if earlier, (i) upon the death or disability of the director or (ii) upon a change in control of the Company that occurs at least six months following the date of grant. The shares had a fair value of $0.7 million based on the Company’s stock price on the grant date and an estimated forfeiture rate of 5.6% . On September 1, 2015, the Company granted 2,000,000 restricted shares of common stock outside of the Company’s Amended and Restated Stock Incentive Plan to a newly hired executive officer. These restricted shares will vest in equal amounts on March 31, 2016, September 1, 2017, and September 1, 2018. The shares had a fair value of $1.5 million based on the Company’s stock price on the grant date and an estimated forfeiture rate of 5.6% . During the year ended December 31, 2015, the Company also granted an additional 205,000 restricted shares of common stock to certain newly hired officers. These 205,000 shares will vest over a 3 -year period and had a fair value of $0.3 million based on the Company’s stock price on the grant date and an estimated forfeiture rate of 5.6% . A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2015 , 2014 , and 2013 is presented below: 2015 2014 2013 Weighted-Average Share Price Weighted-Average Share Price Weighted-Average Share Price Non-vested Shares Shares Shares Shares Non-vested at beginning of the year 2,352,013 $ 5.99 27,500 $ 7.24 65,025 $ 6.09 Granted 3,468,833 $ 1.24 3,239,796 $ 5.66 210,494 $ 4.66 Forfeited (847,514 ) $ 5.92 (135,000 ) $ 7.26 — $ — Vested (1,583,436 ) $ 4.51 (780,283 ) $ 4.48 (248,019 ) $ 4.75 Non-vested at end of the year 3,389,896 $ 2.92 2,352,013 $ 5.99 27,500 $ 7.24 Total unrecognized compensation cost related to the above non-vested shares amounted to $5.2 million , $9.7 million , and $0.2 million as of December 31, 2015 , 2014 , and 2013 , respectively. The unrecognized compensation cost at December 31, 2015 is expected to be recognized over a weighted-average period of 2.03 years. Eureka Midstream Holdings, LLC Management Incentive Compensation Plan On May 12, 2014, the Board of Directors of Eureka Midstream Holdings approved the Eureka Midstream Holdings, LLC Management Incentive Compensation Plan (the “Eureka Midstream Holdings Plan”) to provide long-term incentive compensation to attract and retain officers and employees of Eureka Midstream Holdings and its affiliates and allow such individuals to participate in the economic success of Eureka Midstream Holdings and its affiliates. The Eureka Midstream Holdings Plan consists of (i) 2,336,905 Class B Common Units representing membership interests in Eureka Midstream Holdings (“Class B Common Units”), and (ii) 2,336,905 Incentive Plan Units issuable pursuant to a management incentive compensation plan, which represent the right to receive a dollar value up to the baseline value of a corresponding Class B Common Unit (“Incentive Plan Units”). The Eureka Midstream Holdings Plan is administered by the board of managers of Eureka Midstream Holdings, and, as administrator of the Eureka Midstream Holdings Plan, the board may from time to time make awards under the Eureka Midstream Holdings Plan to selected officers and employees of Eureka Midstream Holdings or its affiliates (“Award Recipients”). Upon approval of the plan on May 12, 2014, the board of managers of Eureka Midstream Holdings granted 894,102 Class B Common Units and 894,102 Incentive Plan Units to key employees and officers of Eureka Midstream Holdings and its subsidiaries. During the fourth quarter of 2014, the board of managers granted an additional 413,110 Class B Common Units and 413,110 Incentive Plan Units to key employees and officers of Eureka Midstream Holdings and its subsidiaries. The Class B Common Units and Incentive Plan Units are accounted for in accordance with ASC 718, Compensation - Stock Compensation . In accordance with ASC 718, compensation cost is accrued when the performance condition ( i.e. a liquidity event) is probable of being achieved. The Company assessed the probability of a liquidity event up to and including the date of deconsolidation of Eureka Midstream Holdings and concluded that as of December 18, 2014, a liquidity event, as defined, was not probable, and therefore, no compensation cost was recognized.

SHAREHOLDERS' EQUITY

SHAREHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
SHAREHOLDERS' EQUITY	NOTE 13 - SHAREHOLDERS' EQUITY Common Stock During the years ended December 31, 2015 , 2014 , and 2013 , the Company issued: i. 1,383,449 , 657,317 , and 182,994 shares, net of shares withheld for taxes, respectively, of the Company’s common stock in connection with share-based compensation which had fully vested to certain senior management and officers of the Company. ii. 100,000 , 2,375,273 , and 1,466,025 shares, respectively, of the Company’s common stock upon the exercise of warrants and options for total proceeds of approximately $0.1 million , $9.7 million , and $5.4 million , respectively. On March 31, 2014, the Company issued 4,300,000 shares of the Company’s common stock in a private placement at a price of $7.00 per share, with net proceeds to the Company of $28.9 million after deducting sales agent commissions and other issuance costs. The Company subsequently filed a Form S-1 Registration Statement with the SEC which was declared effective on July 23, 2014 to register the resale of these shares by the holders thereof to satisfy the Company’s registration obligations under the private placement. A post-effective amendment filed to convert the Form S-1 Registration Statement to a Form S-3 Registration Statement was declared effective by the SEC on September 11, 2014. On May 9, 2014, the Company issued 21,428,580 shares of the Company’s common stock, together with warrants to purchase up to an aggregate of 2,142,858 shares of common stock at an exercise price of $8.50 per share, in a private placement at a price of $7.00 per share, with net proceeds to the Company of $149.7 million after deducting issuance costs. The Company subsequently filed a Form S-1 Registration Statement with the SEC to register the resale of these shares by the holders thereof to satisfy the Company’s registration obligations under the private placement. A pre-effective amendment filed to convert the Form S-1 Registration Statement to a Form S-3 Registration Statement was declared effective by the SEC on August 22, 2014. 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 $500.0 million of debt and equity securities. The Company filed amendments to this Form S-3 Registration Statement on April 15, 2015 and April 20, 2015 and the Form S-3 Registration Statement became effective on April 22, 2015. On April 23, 2015, the Company entered into an “At the Market” Sales Agreement with a sales agent to conduct ATM offerings of its equity securities. As of December 31, 2015 , the Company had sold an aggregate of 56,202,517 shares of its common stock for aggregate proceeds of $58.2 million , net of $1.3 million in sales commissions and other fees, through this ATM offering under the Form S-3 Registration Statement. As a result of the suspension of monthly cash dividends on its preferred stock issuances and the bankruptcy filing, the Company became ineligible to issue securities, including issuances of common stock in ATM offerings, under its universal shelf Registration Statement on Form S-3, which was declared effective on April 22, 2015. See further discussion below related to each series of preferred stock for additional information regarding the Company’s suspension of monthly cash dividends. The Plan contemplates no recovery for, and cancellation of, the Company’s outstanding common stock. As a result, the Company believes that it is highly likely that the shares of its existing common stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery. Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan During the years ended December 31, 2015 , 2014 , and 2013 , the Company issued an aggregate of 2,290,565 , 249,531 , and 221,170 shares, respectively, of the Company’s common stock as “safe harbor” and discretionary matching contributions to the Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan (“KSOP” or the “Plan”). The Plan was established effective October 1, 2010 as a defined contribution plan. At the discretion of the Board of Directors, the Company may elect to contribute discretionary contributions to the Plan either as profit sharing contributions or as employee stock ownership plan contributions. It is the intent of the Company to review and make discretionary contributions to the Plan in the future; however, the Company has no further obligation to make future contributions to the Plan as of December 31, 2015 , except for statutorily required “safe harbor” matching contributions. Shares issued to and held by the Plan are included in the Company’s EPS calculation. During the years ended December 31, 2015 , 2014 , and 2013 , the Company recognized $1.9 million , $1.6 million and $1.2 million , respectively, in compensation attributable to its KSOP. As of December 31, 2015 the KSOP held 2,797,554 shares of the Company’s common stock. Exchangeable Common Stock On May 3, 2011, in connection with a previous acquisition, the Company issued 4,275,998 exchangeable shares of MHR Exchangeco Corporation, which are exchangeable for shares of the Company at a one for one ratio. The shares of MHR Exchangeco Corporation were valued at approximately $31.6 million . Each exchangeable share was exchangeable for one share of the Company’s common stock at any time after issuance at the option of the holder and was redeemable at the option of the Company, through Exchangeco, after one year or upon the earlier of certain specified events. During the year ended December 31, 2013, the remaining 505,835 of the exchangeable shares were exchanged for common shares of the Company. As of December 31, 2015 and 2014 , there were no exchangeable shares outstanding. Common Stock Warrants On August 26, 2013, the Company declared a dividend on its outstanding shares of common stock in the form of 17,030,622 warrants to purchase shares of the Company’s common stock at $8.50 per share with such warrants having a fair value of $21.6 million as of the declaration date of August 26, 2013. The warrants were issued on October 15, 2013 to shareholders of record on September 16, 2013. Each shareholder of record received one warrant for every ten shares owned as of the record date (with the number of warrants rounded down to the nearest whole number). Each warrant entitles the holder to purchase one share of the Company’s common stock at an exercise price of $8.50 per share, subject to certain anti-dilution adjustments, and will expire on April 15, 2016. The warrants are not currently exercisable. The warrants are subject to redemption at the option of the Company at $0.001 per warrant upon not less than thirty days’ notice to the holders. On May 9, 2014, the Company issued 2,142,858 warrants to purchase common stock with an exercise price of $8.50 per share, subject to certain anti-dilution adjustments, in conjunction with the May 2014 private placement sales of common stock. The warrants became exercisable beginning on May 29, 2014, and will expire on April 15, 2016. The warrants are subject to redemption at the option of the Company at $0.001 per warrant upon not less than thirty days’ notice to the holders, only if the Company also redeems the warrants it previously issued pursuant to that certain Warrants Agreement, dated October 15, 2013, by and between the Company and American Stock Transfer & Trust Company, Inc. The warrants were issued in connection with the May 2014 sale of 21,428,580 common shares, and the proceeds for the sale of the common shares and the warrants have been reflected in the Company’s capital accounts as increases to common stock and additional paid in capital. During the year ended December 31, 2013 , 13,237,889 of the Company’s $10.50 common stock warrants expired. During the year ended December 31, 2014 , 97,780 of the Company’s $15.13 common stock warrants and 40,608 of the Company’s $19.04 common stock warrants expired. A summary of warrant activity for the years ended December 31, 2015 , 2014 , and 2013 is presented below: 2015 2014 2013 Weighted - Weighted - Weighted - Average Average Average Shares Exercise Price Shares Exercise Price Shares Exercise Price Outstanding at beginning of year 19,173,480 $ 8.50 17,169,010 $ 8.56 13,376,277 $ 10.56 Granted — $ — 2,142,858 $ 8.50 17,030,622 $ 8.50 Exercised, forfeited, or expired — $ — (138,388 ) $ 16.28 (13,237,889 ) $ 10.50 Outstanding at end of year 19,173,480 $ 8.50 19,173,480 $ 8.50 17,169,010 $ 8.56 Exercisable at end of year 2,142,858 $ 8.50 2,142,858 $ 8.50 138,388 $ 16.28 At December 31, 2015 , the warrants had no aggregate intrinsic value; and the weighted average remaining contract life was 0.3 years . Series D Preferred Stock Each share of Series D Preferred Stock, par value $0.01 per share, has a liquidation preference of $50.00 per share and a dividend rate of 8.0% per annum (based on stated liquidation preference). The Series D Preferred Stock is not convertible into common stock of the Company but may be redeemed by the Company, at the Company’s option, on or after March 14, 2014 for par value or $50.00 per share or in certain circumstances prior to such date as a result of a change in control of the Company. During the year ended December 31, 2013, the Company issued under an ATM sales agreement 216,068 shares of its Series D Preferred Stock for net proceeds of approximately $9.6 million , which included sales agent commissions and other issuance costs of approximately $1.2 million . On October 9, 2015, the Company announced that it had suspended monthly cash dividends on all of its outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. The Company accrued dividends for its Series D Preferred Stock of approximately $3.6 million for the period from October 1, 2015 through the Petition Date. The Company ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015. The Plan contemplates no recovery for, and cancellation of, the Company’s existing preferred stock. As a result, the Company believes that it is highly likely that the shares of its existing preferred stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery. Series E Preferred Stock Each share of Series E Preferred Stock, par value $0.01 per share, has a stated liquidation preference of $25,000 and a dividend rate of 8.0% per annum (based on stated liquidation preference), is convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to anti-dilution adjustments in the case of stock dividends, stock splits and combinations of shares), and is redeemable by the Company under certain circumstances. The Series E Preferred Stock is junior to the Company’s 10.25% Series C Preferred Stock and 8.0% Series D Preferred Stock in respect of dividends and distributions upon liquidation. Each Depositary Share is a 1/1000 th interest in a share of Series E Preferred Stock. Accordingly, the Depositary Shares have a stated liquidation preference of $25.00 per share and a dividend rate of 8.0% per annum (based on stated liquidation preference), are similarly convertible at the option of the holder into a number of shares of the Company’s common stock equal to the stated liquidation preference (plus accrued and unpaid dividends) divided by a conversion price of $8.50 per share (subject to corresponding anti-dilution adjustments), and are redeemable by the Company under certain circumstances. During the year ended December 31, 2013, the Company issued under an ATM sales agreement an aggregate of 27,906 Depositary Shares. The Depositary Shares were sold to the public at an average price of $24.24 per Depositary Share, and net proceeds to the Company were $590,000 after deducting sales agent commissions and other issuance costs. On October 9, 2015, the Company announced that it had suspended monthly cash dividends on all of its outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. The Company accrued dividends for its Series E Preferred Stock of approximately $1.5 million for the period from October 1, 2015 through the Petition Date. The Company ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015. The Plan contemplates no recovery for, and cancellation of, the Company’s existing preferred stock. As a result, the Company believes that it is highly likely that the shares of its existing preferred stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery. Non-controlling Interests In connection with a Williston Basin acquisition in 2008, the Company entered into equity participation agreements with certain of its lenders pursuant to which the Company agreed to pay to the lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which equity participation agreements, for accounting purposes, are treated as non-controlling interests in PRC Williston, and consequently, PRC Williston is treated as a majority owned subsidiary of the Company and is consolidated by the Company. The equity participation agreements had a fair value of $3.4 million upon issuance and were accounted for as a non-controlling interest in PRC Williston. On December 30, 2013, PRC Williston sold substantially all of its assets. On July 24, 2014, the Company executed a settlement and release agreement with the holders of the equity participation rights. 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 December 31, 2014. On April 2, 2012, Eureka Midstream Holdings, then a majority owned subsidiary, issued 622,641 Class A Common Units representing membership interests in Eureka Midstream Holdings, with a value of $12.5 million , as partial consideration for the assets acquired from TransTex. The value of the units transferred as partial consideration for the acquisition was determined utilizing a discounted future cash flow analysis. In October 2014, these Class A Common Units were converted to Series A-1 Units. In October 2014, all of the Eureka Midstream Holdings Series A Preferred Units and Class A Common Units held by Ridgeline were purchased by MSI and converted into Series A-2 Units (see “Note 14 - Redeemable Preferred Stock” ). The Series A-2 Units held by MSI and the Series A-1 Units issued in connection with the TransTex acquisition represented non-controlling interests in Eureka Midstream Holdings in the Company’s consolidated balance sheet. As a result of the deconsolidation of Eureka Midstream Holdings, the Company derecognized the non-controlling interests attributed to Eureka Midstream Holdings as part of the gain on deconsolidation (see “Note 4 - Eureka Midstream Holdings”). Preferred Dividends Incurred A summary of dividends incurred by the Company for the years ended December 31, 2015 , 2014 , and 2013 is presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Dividend on Eureka Midstream Holdings Series A Preferred Units $ — $ 12,760 $ 14,323 Eureka MidstreamAccretion of the carrying value of the Eureka Midstream Holdings Series A Preferred Units — 6,583 6,918 Dividend on Series C Preferred Stock 9,792 10,248 10,248 Dividend on Series D Preferred Stock 16,911 17,698 17,655 Dividend on Series E Preferred Stock 7,114 7,418 7,561 Total dividends on Preferred Stock $ 33,817 $ 54,707 $ 56,705 Net Income or Loss per Share Data The Company has issued potentially dilutive instruments in the form of its restricted common stock 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 Cumulative Convertible Preferred Stock. The Company did not include any of these instruments in its calculation of diluted loss per share during the years ended December 31, 2015 , 2014 , and 2013 because to include them would be anti-dilutive due to the Company’s loss from continuing operations during such periods. The following table summarizes the types of potentially dilutive securities outstanding as of December 31, 2015 , 2014 and 2013 : December 31, 2015 2014 2013 (in thousands of shares) Series E Preferred Stock 11,126 10,946 10,946 Warrants 19,173 19,173 17,169 Restricted shares granted, not yet issued 3,643 2,369 28 Common stock options 7,315 13,195 16,891 Total 41,257 45,683 45,034

REEDEMABLE PREFERRED STOCK

REEDEMABLE PREFERRED STOCK	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
REEDEMABLE PREFERRED STOCK	NOTE 14 - REDEEMABLE PREFERRED STOCK Series C Preferred Stock Each share of Series C Preferred Stock, par value $0.01 per share, has a liquidation preference of $25.00 per share and a dividend rate of 10.25% per annum (based on stated liquidation preference). The Series C Preferred Stock is not convertible into common stock of the Company, but may be redeemed by the Company, at the Company’s option, on or after December 14, 2011 for par value or $25.00 per share. In the event of a change of control of the Company, the Series C Preferred Stock will be redeemable by the holders at $25.00 per share, except in certain circumstances when the acquirer is considered a qualifying public company. The Series C Preferred Stock is recorded as temporary equity because a forced redemption, upon certain circumstances as a result of a change in control of the Company, is outside the Company’s control. On October 9, 2015, the Company announced that it had suspended monthly cash dividends on all of its outstanding series of preferred stock. The suspension commenced with the monthly cash dividend that would otherwise have been declared and paid for the month ending October 31, 2015 and will continue indefinitely. The Company accrued dividends for its Series C Preferred Stock of approximately $2.1 million for the period from October 1, 2015 through the Petition Date. The Company ceased accruing dividends subsequent to the Petition Date. Accrued dividends payable are presented in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015. The Plan contemplates no recovery for, and cancellation of, the Company’s existing preferred stock. As a result, the Company believes that it is highly likely that the shares of its existing preferred stock will be canceled in its Chapter 11 proceedings and will be entitled to no recovery. Eureka Midstream Holdings Series A Preferred Units On March 21, 2012, Eureka Midstream Holdings entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with Magnum Hunter and Ridgeline. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of Eureka Midstream Holdings Series A Preferred Units, of which $200 million were purchased through September 16, 2014. During the years ended December 31, 2014 and 2013 , Eureka Midstream Holdings issued 610,000 and 1,800,000 Eureka Midstream Holdings Series A Preferred Units, respectively, to Ridgeline for net proceeds of $12.0 million and $35.3 million , respectively, net of transaction costs. Eureka Midstream Holdings paid cumulative distributions quarterly on the Eureka Midstream Holdings Series A Preferred Units at a fixed rate of 8% per annum of the initial liquidation preference. The distribution rate was increased to 10% if any distribution was not paid when due. The board of managers of Eureka Midstream Holdings had the option to elect to pay up to 75% of the distributions owed for the period from March 21, 2012 through March 31, 2013 in the form of “paid-in-kind” units and had the option to elect to pay up to 50% of the distributions owed for the period from April 1, 2013 through March 31, 2014 in such units. The Eureka Midstream Holdings Series A Preferred Units were convertible into Class A Common Units of Eureka Midstream Holdings upon demand by Ridgeline or by Eureka Midstream Holdings upon the consummation of a qualified initial public offering. The conversion rate was 1 :1, subject to adjustment from time to time based upon certain anti-dilution and other provisions. Eureka Midstream Holdings was allowed to redeem all outstanding Eureka Midstream Holdings Series A Preferred Units at their liquidation preference, which involved a specified IRR hurdle, any time after March 21, 2017. Holders of the Eureka Midstream Holdings Series A Preferred Units could force the redemption of all outstanding Eureka Midstream Holdings Series A Preferred Units any time after March 21, 2020. The Eureka Midstream Holdings Series A Preferred Units were recorded as temporary equity because a forced redemption by the holders of the preferred units was outside the control of Eureka Midstream Holdings. During the years ended December 31, 2014 and 2013 , the Company paid cash distributions of $10.2 million and $5.2 million , respectively. The Company accrued distributions not yet paid of $3.9 million during the year ended December 31, 2013 to the holder of the Eureka Midstream Holdings Series A Preferred Units. During such years, distributions in the amount of $1.9 million and $8.2 million , respectively, were paid-in-kind to the holder of the Eureka Midstream Holdings Series A Preferred Units, and the Company issued 97,492 and 412,157 Eureka Midstream Holdings Series A Preferred Units, respectively, as payment. The Company evaluated the Eureka Midstream Holdings Series A Preferred Units and determined that they should be considered a “debt host” and not an “equity host”. This evaluation was necessary to determine if any embedded features require bifurcation and, therefore, would be required to be accounted for separately as a derivative liability. The Company’s analysis followed the “whole instrument approach,” which compares an individual feature against the entire preferred instrument that includes that feature. As a result of the Company’s determination that the preferred unit is a “debt host,” the Company determined that the embedded conversion option, redemption options and other features of the preferred units required bifurcation and separate accounting as embedded derivatives. The fair value of the embedded features were determined at the issuance dates and were bifurcated from the issuance values of the Eureka Midstream Holdings Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was $173.2 million at October 3, 2014. The embedded derivative associated with the Eureka Midstream Holdings Series A Preferred Units was extinguished upon conversion as discussed in “Note 4 - Eureka Midstream Holdings”. On October 3, 2014, the outstanding Eureka Midstream Holdings Series A Preferred Units were purchased from Ridgeline by MSI and converted into Series A-2 Units of Eureka Midstream Holdings. As a result of the conversion of the Eureka Midstream Holdings Series A Preferred Units into Series A-2 Units, the Company recognized a new preferred interest which was considered a permanent equity interest in Eureka Midstream Holdings. The Series A-2 Units non-controlling interest was derecognized upon deconsolidation and included as part of the gain on deconsolidation. See “Note 4 - Eureka Midstream Holdings”. Extinguishment of Eureka Midstream Holdings Series A Preferred Units On October 3, 2014, in connection with the Transaction Agreement and Letter Agreement between the Company and MSI and the effectiveness of the New LLC Agreement, the conversion feature associated with the Eureka Midstream Holdings Series A Preferred Units was modified. Specifically, the conversion feature was modified to allow for settlement through the issuance of Series A-2 Units, a form of preferred equity of Eureka Midstream Holdings. The Company has accounted for the modification to the conversion feature as an extinguishment of the old preferred units and issuance of new preferred units due to the liquidation preference and other substantive features and veto rights provided to the holders of the Series A-2 Units. At the date of conversion, the Company determined the Series A-2 Units had a fair value of $389.0 million and recognized a loss on extinguishment of the Eureka Midstream Holdings Preferred Series A Units of $51.7 million for the difference between the fair value of the Series A-2 Units and the carrying amount of the Eureka Midstream Holdings Series A Preferred Units, including the embedded derivative liability and accrued dividends at October 3, 2014. The loss on extinguishment is reflected as an adjustment to the net loss available to common stockholders in accordance with ASC Topic 260, Earnings per Share . See “Note 9 - Fair Value of Financial Instruments” for the method used to determine the fair value of the Series A-2 Units.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	NOTE 15 - INCOME TAXES The total provision for income taxes applicable to continuing operations consists of the following: Year Ended December 31, 2015 2014 2013 (in thousands) Deferred income tax benefit Federal $ — $ — $ (78,743 ) State — — (6,664 ) Total deferred tax benefit $ — $ — $ (85,407 ) Total income tax benefit $ — $ — $ (85,407 ) At December 31, 2015 , the Company had net operating loss carry forwards (“NOLs”) available for U.S. federal income tax purposes of approximately $1,031 million , which expire in varying amounts during the tax years 2018 through 2035. The deferred tax asset recorded for the U.S. NOLs does not include $38.1 million of deductions for excess stock-based compensation (tax effected $14.8 million ). The Company will recognize the NOLs tax assets associated with excess stock-based compensation tax deductions only when all other components of the NOLs tax assets have been fully utilized and a cash tax benefit is realized. Upon realization, the excess stock-based compensation deduction will reduce taxes payable and will be credited directly to equity. At December 31, 2015 , the Company was not under examination by any federal taxing jurisdiction. The Company has various state audits in the initial stages of examination which the Company does not believe will have a material impact to its financial condition or results of operations. The Company has approximately $2.8 million (tax effected $1.1 million ) of depletion carryover which has no expiration. The Company has no unremitted earnings in Canada. The Company has recorded a valuation allowance of $509.1 million against the net deferred tax assets of the Company at December 31, 2015 . The Company is uncertain on a more likely than not basis that the NOLs and other deferred tax assets will be utilized in the future. Management evaluated all available positive and negative evidence in making this assessment. The assessment included objectively verifiable information such as historical operating results, future projections of operating results, future reversals of existing taxable temporary differences and anticipated capital expenditures. Management placed a significant amount of weight on the historical results. The following is a reconciliation of the reported amount of income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2015 , 2014 , and 2013 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income: Year Ended December 31, 2015 2014 2013 (in thousands) Income tax benefit at statutory U.S. rate $ (274,355 ) $ (48,242 ) $ (111,132 ) State income taxes (net of federal benefit) (28,930 ) (3,616 ) (4,331 ) Tax effect of permanent differences 224 (498 ) 750 Provision to return adjustment — (11,736 ) — Foreign statutory tax rate differences (9 ) 297 — Tax effect of loss attributable to non-controlled interest — 1,279 346 Tax benefit recognized as tax expense in discontinued operations — — (28,989 ) Change in valuation allowance 302,373 63,341 58,341 Other 697 (825 ) (392 ) Total continuing operations — — (85,407 ) Discontinued operations — — 11,773 Total tax benefit $ — $ — $ (73,634 ) Income (loss) before income taxes was as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Domestic $ (783,963 ) $ (134,853 ) $ (317,520 ) Foreign 91 (2,980 ) — Loss from continuing operations (783,872 ) (137,833 ) (317,520 ) Gain (loss) from discontinued operations — 4,561 (62,655 ) Gain (loss) on disposal of discontinued operations — (13,855 ) 83,378 Loss before income tax $ (783,872 ) $ (147,127 ) $ (296,797 ) Deferred Tax Assets and Liabilities The tax effects of temporary differences that gave rise to the Company’s deferred tax assets and liabilities are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Deferred tax assets: Net operating loss carry forwards $ 371,531 $ 263,452 $ 155,507 Property and equipment 162,236 63,823 — Capital loss carry forward 76,955 38,401 — Share-based compensation 17,293 15,035 10,156 Depletion carry forwards 1,047 1,047 1,047 Tax credits 53 53 53 US investment in Canada — — 74,148 Other 15,354 1,562 561 Deferred tax liabilities: Property and equipment — — (90,950 ) Investment in Eureka Midstream Holdings (135,331 ) (176,606 ) — Valuation allowance Tax credits (53 ) (53 ) (53 ) Depletion carry forwards (1,047 ) (1,047 ) (1,047 ) Capital loss carry forward (76,955 ) (38,401 ) — Net operating losses (371,531 ) (263,452 ) (155,507 ) Other (59,552 ) 96,186 80,233 US investment in Canada — — (74,148 ) Net deferred tax asset (liability) $ — $ — $ — As of December 31, 2015 , the Company provided for a liability of $3.9 million for unrecognized tax benefits related to various federal tax matters, which were netted against the Company’s net operating loss. Settlement of the uncertain tax position is expected to occur in the next twelve months and will have no effect on income tax expense (benefit). The Company has elected to classify interest and penalties related to uncertain income tax positions in income tax expense. Due to available NOLs, as of December 31, 2015 , the Company has accrued no amounts for potential payment of interest and penalties. Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in thousands) Unrecognized tax benefits at January 1 $ 3,879 $ 3,879 $ 3,879 Change in unrecognized tax benefits taken during a prior period — — — Change in unrecognized tax benefits taken during the current period (netted against the US net operating loss) — — — Decreases in unrecognized tax benefits from settlements with taxing authorities — — — Reductions to unrecognized tax benefits from lapse of statutes of limitations — — — Unrecognized tax benefits at December 31 $ 3,879 $ 3,879 $ 3,879

MAJOR CUSTOMERS

MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
MAJOR CUSTOMERS	NOTE 16 - MAJOR CUSTOMERS The Company’s share of oil and gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The following purchasers individually accounted for ten percent or more of the Company’s consolidated continuing oil and gas revenues in at least one of the three years ended December 31, 2015 , 2014 and 2013 . The loss of any one significant purchaser could have a material, adverse effect on the ability of the Company to sell its oil and gas production. In September 2015, one of the Company’s purchasers, Samson Resources Company, filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code. The table below provides the percentages of the Company’s consolidated oil, NGLs and gas revenues from continuing operations represented by its major purchasers during the periods presented: Year Ended December 31, 2015 2014 2013 Samson Resources Company (1) 22 % 24 % 31 % Markwest Liberty Midstream 14 % 15 % 6 % Tenaska Marketing Ventures 11 % 17 % 10 % Baytex Energy USA LTD — % 7 % 11 % _________________ (1) See “ Note 18 - Commitments and Contingencies - Samson Matter”

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	NOTE 17 - RELATED PARTY TRANSACTIONS The following table sets forth the related party balances as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in thousands) GreenHunter (1) Accounts receivable, net of reserve $ — $ 21 Accounts payable $ (24 ) $ (249 ) Liabilities subject to compromise $ (635 ) $ — Derivative assets (2) $ — $ 75 Investments (2) $ 81 $ 1,311 Notes receivable, net of reserve (2) $ — $ 1,224 Prepaid expenses $ 5 $ 1,000 Eureka Midstream Holdings (3) Accounts receivable $ 5,467 $ 2,898 Accounts payable $ (1,480 ) $ (2,776 ) Liabilities subject to compromise $ (15,827 ) $ — Equity method investment $ 166,099 $ 347,191 Pilatus Hunter (4) Accounts receivable $ 12 $ 12 Classic Petroleum, Inc. (5) Liabilities subject to compromise $ (51 ) $ — The following table sets forth the related party transaction activities for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in thousands) GreenHunter Production costs (1) $ 3,675 $ 4,973 $ 3,315 Midstream natural gas gathering, processing, and marketing (1) $ — $ 652 $ — Oilfield services (1) $ 298 $ — $ — General and administrative (1) $ 23 $ 44 $ 13 Interest income (2) $ 113 $ 154 $ 205 Miscellaneous income (expense) (2) $ (620 ) $ 220 $ 220 Loss from equity method investment (2) $ 464 $ 590 $ 730 Capitalized costs incurred (1) $ 508 $ 3,149 $ — Pilatus Hunter, LLC (4) General and administrative $ 143 $ 281 $ 166 Eureka Midstream Holdings (3) Oil and natural gas sales $ 347 $ — $ — Production costs $ 1,181 $ — $ — Transportation, processing, and other related costs $ 24,865 $ 353 $ — Oilfield services $ 34 $ — $ — General and administrative $ 8 $ 32,569 $ — Gain on deconsolidation of Eureka Midstream Holdings, LLC $ — $ 509,563 $ — Gain on dilution of interest in Eureka Midstream Holdings, LLC $ 4,601 $ — $ — Loss from equity method investment $ 185,693 $ 448 $ — Loss on extinguishment of Eureka Midstream Holdings Series A Preferred Units $ — $ 51,692 $ — Capitalized costs incurred $ 121 $ — $ — Classic Petroleum (5) Capitalized costs incurred $ 206 $ 1,495 $ — Kirk Trosclair Enterprises, LLC (6) General and administrative $ 169 $ — $ — _________________________________ (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 VIRCO, wholly owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and certain affiliated companies. The Company had approximately $66,000 of accounts receivable from GreenHunter which was fully reserved as of December 31, 2015. (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 9 - Fair Value of Financial Instruments”. 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. Miscellaneous income (expense) includes other than temporary impairment loss on the GreenHunter available for sale security of $0.8 million for the year ended December 31, 2015. See “Note 10 - Investments and Derivatives” for additional information. (3) Following a sequence of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Midstream Holdings. The Company deconsolidated Eureka Midstream Holdings and accounts for its retained interest as of December 31, 2015 and 2014 under the equity method of accounting. See “Note 4 - Eureka Midstream Holdings” and “Note 10 - 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 former Executive Vice President and President of the Company’s Appalachian Division. Triad Hunter received land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services. (6) On July 18, 2014, the Company entered into a consulting agreement with Kirk J. Trosclair, a former executive of Alpha Hunter Drilling, 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 year ended December 31, 2015, the Company paid Mr. Trosclair $169,000 , which includes reimbursement of expenses incurred on behalf of the Company, and recognized $163,423 in stock compensation expense. In connection with the sale of Hunter Disposal, Triad Hunter entered into agreements with Hunter Disposal and GreenHunter Water for wastewater hauling and disposal capacity in Kentucky, Ohio, and West Virginia and a five -year tank rental agreement with GreenHunter Water. On December 22, 2014, Triad Hunter entered into an Amendment to Produced Water Hauling and Disposal Agreement with GreenHunter Water to secure long-term water disposal at reduced rates through December 31, 2019. To ensure disposal capacity, in connection with the amendment on December 29, 2014 Triad Hunter made a prepayment of $1.0 million towards services to be provided under the Produced Water Hauling and Disposal Agreement. GreenHunter Water provided a 50% credit for all services performed under the agreement until the prepayment amount was utilized in full, which occurred during the first half of 2015. As of December 31, 2015 , the Company had a note receivable from GreenHunter with an outstanding principal balance of approximately $680,300 which was fully reserved as of December 31, 2015. 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 December 31, 2015, GreenHunter was current with its principal and interest payments on the promissory note; however, GreenHunter did not make the principal and interest payment due on February 17, 2016, and on March 1, 2016, GreenHunter and certain of its subsidiaries filed voluntary petitions for reorganization under the Bankruptcy Code. Amounts receivable under the promissory note have the status of a general unsecured claim in GreenHunter’s bankruptcy proceeding. As of December 31, 2013, Mr. Evans, the Company’s Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Midstream Holdings. On October 3, 2014, in connection with the New LLC Agreement, these Class A Common Units were converted into Series A-1 Units. As of December 31, 2014 and 2015, Mr. Evans also held 250,049 Class B Common Units of Eureka Midstream Holdings pursuant to the Eureka Midstream Holdings Plan, of which none were vested at December 31, 2014 and 50,009 of which were vested at December 31, 2015. Triad Hunter and Eureka Midstream 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 New LLC Agreement. Under the terms of the gathering agreement, Triad Hunter reserved throughput capacity in the gas gathering pipeline system of Eureka Midstream Holdings for which Triad Hunter has committed to minimum reservation fees of approximately $1.05 per MMBtu. As of October 31, 2015, Triad Hunter owed Eureka Midstream approximately $10.7 million in past due gathering fees under the Gas Gathering Services Agreement. On November 5, 2015, the Company received a demand notice from MSI, on behalf of Eureka Midstream, demanding adequate assurance of performance of security in the amount of approximately $20.8 million in connection with past due gathering fees. In accordance with the demand notice, Eureka Midstream suspended gas gathering services on November 10, 2015, requiring the Company to temporarily shut-in approximately 40 wells located in West Virginia. On November 19, 2015, the Company agreed to, among other things, pay $5.0 million to Eureka Midstream. Eureka Midstream lifted the suspension of gas gathering services and the Company began the process of returning all of the shut-in wells to production. In connection with the Chapter 11 Cases, the Company agreed to assume the gathering agreement with Eureka Midstream, subject to certain agreed upon amendments. These amendments will, among other things, modify certain of the reservation fees and commodity fees that Triad Hunter pays to Eureka Midstream and provide certain volume credits to Triad Hunter. See “Note 18 - Commitments and Contingencies” for further discussion of the gas gathering and processing agreements with Eureka Midstream. In addition, the Company and Eureka Midstream 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 Midstream 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 New LLC Agreement, certain specified employees of the Company that perform service for Eureka Midstream Holdings and its subsidiaries and for whom the Company bills a personnel services fee, are expected to become employees of Eureka Midstream Holdings or a subsidiary of Eureka Midstream Holdings. Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, Eureka Midstream Holdings and its subsidiaries became related parties of the Company.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 18 - COMMITMENTS AND CONTINGENCIES Legal Proceedings Securities Cases On April 23, 2013, Anthony Rosian, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against the Company and certain of its officers, two of whom, at that time, also served as directors, and one of whom continues to serve as a director. On April 24, 2013, Horace Carvalho, individually and on behalf of all other persons similarly situated, filed a similar class action complaint in the United States District Court, Southern District of Texas, against the Company and certain of its officers. Several substantially similar putative class actions were filed in the Southern District of New York and in the Southern District of Texas. All such cases are collectively referred to as the Securities Cases. The cases filed in the Southern District of Texas have since been dismissed. The cases filed in the Southern District of New York were consolidated and have since been dismissed. The plaintiffs in the Securities Cases had filed a consolidated amended complaint alleging that the Company made certain false or misleading statements in its filings with the SEC, including statements related to the Company’s internal and financial controls, the calculation of non-cash share-based compensation expense, the late filing of the Company’s 2012 Form 10-K, the dismissal of Magnum Hunter’s previous independent registered accounting firm, the Company’s characterization of the auditors’ position with respect to the dismissal, and other matters identified in the Company’s April 16, 2013 Form 8-K, as amended. The consolidated amended complaint asserted claims under Sections 10(b) and 20 of the Exchange Act based on alleged false statements made regarding these issues throughout the alleged class period, as well as claims under Sections 11, 12, and 15 of the Securities Act based on alleged false statements and omissions regarding the Company’s internal controls made in connection with a public offering that Magnum Hunter completed on May 14, 2012. The consolidated amended complaint demanded that the defendants pay unspecified damages to the class action plaintiffs, including damages allegedly caused by the decline in the Company’s stock price between February 22, 2013 and April 22, 2013. In January 2014, the Company and the individual defendants filed a motion to dismiss the Securities Cases. On June 23, 2014, the United States District Court for the Southern District of New York granted the Company’s and the individual defendants’ motion to dismiss the Securities Cases and, accordingly, the Securities Cases have now been dismissed. The plaintiffs subsequently appealed the decision dismissing the Securities Cases to the U.S. Court of Appeals for the Second Circuit. On June 23, 2015, the U.S. Court of Appeals for the Second Circuit entered a Summary Order unanimously affirming the Southern District of New York’s dismissal of the Securities Cases in favor of the Company and the individual defendants. It is possible that additional investor lawsuits could be filed over these events. On May 10, 2013, Steven Handshu filed a stockholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company’s directors and senior officers. On June 6, 2013, Zachariah Hanft filed another stockholder derivative suit in the Southern District of New York on behalf of the Company against the Company’s directors and senior officers. On June 18, 2013, Mark Respler filed another stockholder derivative suit in the District of Delaware on behalf of the Company against the Company’s directors and senior officers. On June 27, 2013, Timothy Bassett filed another stockholder derivative suit in the Southern District of Texas on behalf of the Company against the Company’s directors and senior officers. On September 16, 2013, the Southern District of Texas allowed Joseph Vitellone to substitute for Mr. Bassett as plaintiff in that action. On March 19, 2014 Richard Harveth filed another stockholder derivative suit in the 125th District Court of Harris County, Texas. These suits are collectively referred to as the Derivative Cases. The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company’s investors regarding the Company’s business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys’, accountants’ and experts’ fees and costs to the plaintiff. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the stockholder derivative case maintained by Joseph Vitellone and entered a final judgment of dismissal. The court held that Mr. Vitellone failed to plead particularized facts demonstrating that pre-suit demand on the Company’s board was excused. In addition, on December 13, 2013, the 151st Judicial District Court of Harris County, Texas dismissed the lawsuit filed by Steven Handshu for want of prosecution after the plaintiff failed to serve any defendant in that matter. On January 21, 2014, the Hanft complaint was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the United States District Judge for the District of Delaware granted the Company’s supplemental motion to dismiss the Derivative Case filed by Mark Respler. On July 22, 2014, the 125th District Court of Harris County, Texas issued an Order and Final Judgment granting the Company’s and the individual defendants’ motion for summary judgment in its entirety and entering a final judgment dismissing the suit filed by Richard Harveth. The plaintiffs may file an appeal. All of the Derivative Cases have now been dismissed. It is possible that additional stockholder derivative suits could be filed over these events. In addition, the Company 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 General Corporation Law of the State of Delaware. 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 sought 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 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. SEC Wells Notice In April 2013, the Company 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. In connection with the Staff’s inquiry, on March 24, 2015, the Company received a “Wells Notice” from the Staff, stating that the Staff had 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 (i) Gary C. Evans, the Company’s current Chairman and Chief Executive Officer, (ii) J. Raleigh Bailes, Sr., a former director of the Company and former Chairman of the Company’s Audit Committee, (iii) 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 (iv) 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 stated 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 did 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 Company and certain of the individual respondents (other than Mr. Evans and Mr. Bailes) thereafter negotiated a settlement with the SEC, which the SEC Commissioners approved on March 10, 2016. Pursuant to the settlement, without admitting or denying the SEC’s findings, the Company agreed to pay a civil penalty of $250,000 to the SEC (the “Civil Penalty”), subject to Bankruptcy Court approval, and was ordered to cease and desist from violating Sections 13(a), 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act and Rules 13a-1, 13a-13 and 13-15(a) thereunder. The two former officers referred to above, who oversaw the Company’s accounting department at the relevant times, as well as two former outside accounting professionals, were ordered to cease and desist from violating these provisions and were subjected to additional financial penalties or administrative suspensions in their individual capacities. On March 23, 2016, Mr. Evans, the Company’s current Chairman and Chief Executive Officer, and Mr. Bailes, a former director of the Company and former Chairman of the Company’s Audit Committee, received letters from the Staff stating that the Staff had concluded its investigations of Mr. Evans and Mr. Bailes and that, based on the information the Staff possessed as of that date, the Staff did not intend to recommend an enforcement action by the SEC against either of them. Furthermore, no other current officers or directors of the Company were required to pay any penalties or were subjected to any sanctions in their individual capacity pursuant to the settlement. On March 11, 2016, the Company filed a motion with the Bankruptcy Court seeking approval of the Company’s settlement with the SEC and authority to pay the Civil Penalty to the SEC. On March 29, 2016, the Bankruptcy Court entered an order approving the Company’s motion. Twin Hickory Matter On April 11, 2013, a flash fire occurred at Eureka Midstream’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 Midstream 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 Midstream seeking a declaratory judgment that Eureka Midstream 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 Midstream 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 alleged that Eureka Midstream 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 demanded judgments for an unspecified amount of compensatory, general and punitive damages. Various cross-claims were asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter 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 dismissed. A portion of the settlement was paid by an insurer of Eureka Midstream, and the remainder paid by unrelated third party co-defendants or their insurers. The cross-claims among the defendants in the Whisenhunt litigation have been resolved. In addition, the claims filed by Antoinette M. Miller and Karen S. Phipps have been successfully mediated and have been resolved and dismissed. Insurers providing coverage to Eureka Midstream, Magnum Hunter and other affiliated or related entities paid a portion of the settlements, with the remainder being paid by unrelated third party co-defendants or their insurers. Accordingly, all lawsuits relating to this matter have been resolved. Samson Matter In June 2015, Samson Resources Company (“Samson”) executed and filed ten oil and gas well liens in Divide County, North Dakota (the “Samson Liens”) to secure payments it contends were owed by Bakken Hunter. In July 2015, Bakken Hunter filed a complaint against Samson in a case styled Bakken Hunter, LLC v. Samson Resources Company, Case No. 4:15-cv-0008, in the United States District Court for the District of North Dakota, Northwestern Division. In its complaint, Bakken Hunter alleges that Samson breached certain agreements by, among other things, failing to promptly pay and discharge certain expenses resulting in third party liens, failing to keep accurate records, failing to make its accounts available to Bakken Hunter for audit and failing to respond to Bakken Hunter’s concerns about Samson’s billing and accounting practices. Bakken Hunter is seeking equitable relief and damages in an unliquidated amount and seeking a declaration that the Samson Liens are void. In August 2015, Samson filed and served its answer and counterclaims against Bakken Hunter, generally denying Bakken Hunter’s allegations and asserting its own claims for breach of contract, contending that Bakken Hunter failed to pay its proportionate share of certain expenses as a non-operator of certain oil and gas properties. In its counterclaims, among other relief, Samson sought a declaration that the Samson Liens were valid and sought in its counterclaims to foreclose on the Samson Liens. This matter has been stayed as a result of Samson’s bankruptcy filing in the United States Bankruptcy Court for the District of Delaware, Case No. 15-11942 (CSS). In November 2015, Bakken Hunter filed a Proof of Claim against Samson in the Samson bankruptcy; the Proof of Claim is based on the same facts alleged in Bakken Hunter’s complaint against Samson. During the pendency of these matters, Samson has continued to withhold all revenues owed to Bakken Hunter with respect to Bakken Hunter’s non-operated working interests in the oil and gas properties in Divide County, North Dakota as to which Samson is an operator under a theory of recoupment applicable to the expenses Samson claims Bakken Hunter, as a non-operated working interest owner, has failed to pay. Our Plan includes an agreed stipulation (the “Samson Stipulation”) between Bakken Hunter and Samson. Pursuant to the Samson Stipulation, among other things, (i) the joint operating agreement (the “Samson JOA”) between the parties will be assumed by Bakken Hunter in its bankruptcy proceeding, consistent with the terms of the Samson Stipulation; (ii) both parties reserved all rights of their respective claims against each other; (iii) the parties agreed to cooperate to complete Bakken Hunter’s ongoing audits under the Samson JOA for years 2013, 2014 and 2015; and (iv) so long as Bakken Hunter is not in default under the Samson JOA (including the current payment of joint interest billings), Samson shall cease offsetting Bakken Hunter’s revenue and timely remit such revenue to Bakken Hunter in the following manner: (a) each month, Samson shall remit all revenue due to Bakken under the Samson JOA up to the amount paid by Bakken Hunter to Samson in respect of the prior month’s joint interest billings plus any amounts for which Bakken Hunter properly reduced payment in accordance with the Samson JOA (such total, the “Prior Month’s Reimbursement”) and (b) any revenue in excess of the Prior Month’s Reimbursement will be placed into an escrow account pending resolution of the parties’ various claims. The Bankruptcy Court has not yet adjudicated the various claims asserted by Samson and Bakken Hunter against one another. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these lawsuits to have a material adverse effect on the Company’s consolidated financial condition or results of operations. Eclipse Matter In November 2015, Eclipse Resources I, LP (“Eclipse”) filed a complaint against Triad Hunter in a case styled Eclipse Resources I, LP v. Triad Hunter, LLC, Civil Action G.D. No. 2015-4589, in the Court of Common Pleas of Centre County, Pennsylvania. In its complaint, Eclipse alleged that Triad Hunter failed to honor its obligations under an Operating Agreement in constructing and operating a well located in Monroe County, Ohio, which experienced a blowout event in December 2014. Asserting purported claims for declaratory, common law and equitable relief, Eclipse is seeking recovery of its proportionate share of costs to remediate the well blowout event, legal fees in the action, removal of Triad Hunter as operator, and appointment of a receiver over the business and assets of Triad Hunter. Although the matter was initially stayed upon the filing of the Chapter 11 Cases, on January 21, 2016 the Bankruptcy Court approved a stipulation agreed to by the parties pursuant to which, among other things, the automatic stay was modified to allow the parties to proceed with the state court litigation. Pursuant to the stipulation, (i) Eclipse agreed to dismiss the pending action in the Court of Common Pleas of Centre County, Pennsylvania and refile the action in state court in Ohio; (ii) Eclipse is permitted to take or receive hydrocarbons from the affected wells in kind; (iii) Eclipse is required to fund up to $2.2 million in an escrow account pending the final and non-appealable resolution of the state court litigation; and (iv) Triad Hunter agreed to discontinue netting revenue otherwise owed to Eclipse from the sale of Eclipse hydrocarbons marketed by Triad Hunter. The prevailing party in the state court litigation will be entitled to recovery of the escrowed funds. The Company intends to mount a vigorous defense in the state court litigation. While the outcome of this matter cannot be predicted with certainty, management does not expect this matter to have a material adverse effect on the Company’s consolidated financial condition or results of operations. General The Company is 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 the Company’s consolidated financial condition or results of operations. Payable on Sale of Partnership On September 26, 2008, the Company sold its 5.33% limited partner interest in Hall-Houston Exploration II, L.P. pursuant to a Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership for cash consideration of $8.0 million and the purchaser’s assumption of the first $1.4 million of capital calls subsequent to September 26, 2008. The Company agreed to reimburse the purchaser for up to $754,255 of capital calls in excess of the first $1.4 million . The Company’s net gain on the sale of the asset is subject to future upward adjustment to the extent that some or all of the $754,255 is not called. The liability as of December 31, 2015 and 2014 was $640,695 and is included in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015. Gas Gathering and Processing Agreements On December 14, 2011, the Company entered into a 120 -month gas transportation contract with Equitrans, L.P. The contract became effective on August 1, 2012, and expires on July 31, 2022. The Company’s remaining obligation under the contract was approximately $16.8 million as of December 31, 2015 . With the Virco Acquisition on November 2, 2012, Triad Hunter assumed a 120 -month gas transportation contract with Dominion Field Services, Inc., which expires on December 31, 2022. The Company’s remaining obligation under the contract was $2.7 million as of December 31, 2015 . Effective October 3, 2014, the Company entered into a 15 -year gas transportation contract with Equitrans, L.P. which expires on October 31, 2029. The Company’s remaining obligation under the contract was $44.2 million as of December 31, 2015. Eureka Midstream Gas Gathering Agreement On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement (as amended, the “Gathering Agreement”) with Eureka Midstream. Under the terms of this agreement, Triad Hunter committed to the payment of monthly reservation fees for certain maximum daily quantities of gas delivered each day for transportation under various individual transaction confirmations. In previous periods, Eureka Midstream and Triad Hunter were both wholly owned subsidiaries of the Company. Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, Eureka Midstream became a related party (see “Note 4 - Eureka Midstream Holdings” and “Note 17 - Related Party Transactions” ). As of December 31, 2015 , Triad Hunter and Eureka Midstream were parties to seven individual transaction confirmations with terms ranging from eight to fourteen years. Triad Hunter’s maximum daily quantity committed was 260,000 MMBtu per day at an aggregate reservation fee of $1.05 per MMBtu. Triad Hunter’s remaining obligation under the individual transaction confirmations was $172.8 million as of December 31, 2015 . As of October 31, 2015, Triad Hunter owed Eureka Midstream approximately $10.7 million in past due gathering fees under the Gathering Agreement. On November 5, 2015, the Company received a demand notice (the “Demand Notice”) from MSI on behalf of Eureka Midstream, demanding, in connection with past due amounts, adequate assurance of performance of security in the amount of approximately $20.8 million on or before November 10, 2015. MSI further advised in the Demand Notice that it would suspend services under and terminate the Gathering Agreement if the Company had not provided the adequate assurance of performance and/or paid in full all amounts past due by November 20, 2015 (the “Deadline”). In accordance with the Demand Notice, on November 10, 2015, Eureka Midstream suspended gas gathering services under the Gathering Agreement requiring Triad Hunter to temporarily shut-in approximately 40 of Triad Hunter’s operated wells located in West Virginia. The shut-in wells were producing approximately 66,000 Mcfe/d of natural gas production (approximately 55,000 Mcfe/d net to Triad Hunter). Upon execution and delivery of the November 2015 Letter Agreement (as defined and described below), on November 19, 2015, Eureka Midstream lifted the suspension of gas gathering services under the Gathering Agreement, and Eureka Midstream and Triad Hunter collectively began the process of returning all of the shut-in back to production. All of the shut-in wells were returned to production and flowing to sales on or before November 21, 2015. In response to the Demand Notice, North Haven Infrastructure Partners II Buffalo Holdings LLC (formerly, MSIP II Buffalo Holdings LLC) (“NHIP II”) (on its behalf and on behalf of Eureka Midstream Holdings and its subsidiaries, including Eureka Midstream (collectively the “EHH Group”)), Triad Hunter and the Company (collectively, the “Parties”) entered into a new letter agreement, dated November 19, 2015 (the “November 2015 Letter Agreement”), in connection with the Demand Notice, pursuant to which the Parties agreed, among other things, to the following: i. Triad Hunter agreed to, and the Company agreed to cause Triad Hunter to, pay Eureka Midstream an aggregate amount of $5,000,000 in immediately available funds, on the following schedule: (i) $3,000,000 (the “First Payment”) promptly upon execution of the November 2015 Letter Agreement by NHIP II (which payment was made on November 19, 2015), and (ii) $2,000,000 on or before December 4, 2015 (the “Second Payment” and, collectively with the First Payment, the “Payments”); ii. Triad Hunter agreed to pay all amounts then currently owed by Triad Hunter to or billed to Triad Hunter by Eureka Midstream (after giving effect to the application of the Payments) under and in accordance with the Gathering Agreement upon the occurrence of (a) any comprehensive recapitalization or restructuring of the Company’s secured and unsecured indebtedness and/or any transaction or series of related transactions involving any business combination pursuant to which a majority of the Company’s equity or core assets are sold, other than under the circumstances described in clause (b) below; or (b) in the event of the commencement of a case under Chapter 11 of the Bankruptcy Code, the date that is no later than 30 days after the Petition Date, to the extent approved by the bankruptcy court (each, a “Liquidity Event”); iii. The Company and Triad Hunter agreed that in the event either entity commences a voluntary case under Chapter 11 of the Bankruptcy Code, the Company and Triad Hunter would file a motion seeking, and use commercially reasonable efforts to obtain, on an interim basis as part of the “first day orders” and on a final basis to be entered no later than 30 days following the Petition Date, entry of an order(s) in form and substance reasonably acceptable to NHIP II authorizing the Company and Triad Hunter to timely honor as allowed administrative expenses and otherwise perform all their respective obligations arising under the Gathering Agreement in accordance with the Gathering Agreement during the period beginning on the Petition Date and ending on the earlier of (a) the end of the Chapter 11 case, (b) rejection of the Gathering Agreement, and (c) as otherwise agreed to in writing among the Company, Triad Hunter, and NHIP II; iv. Eureka Midstream agreed to, and NHIP II agreed to instruct the EHH Group to, prior to the Forbearance End Date (as defined below), (a) commencing upon the receipt of the First Payment, forbear (and as immediately as practicable restore service in connection with any prior exercise) from the exercise and/or enforcement of any rights and/or remedies with respect to Triad Hunter and the Company under the Gathering Agreement in relation to the payment of any arrearages under the Gathering Agreement including, without limitation, termination, suspense of service and demands for adequate assurance of future performance and pursuing any remedies related thereto under Section 8.4(d)(ii) of the New LLC Agreement; (b) not commence any action at law or in equity or otherwise against Triad Hunter or the Company in relation to the payment of any arrearages under the Gathering Agreement; and (c) not commence an involuntary bankruptcy proceeding against Triad Hunter or the Company. Section 8.4(d)(ii) of the New LLC Agreement permits NHIP II, on behalf of Eureka Midstream Holdings and the other members of the EHH Group, to take any and all actions relating to the exercise and/or enforcement of any rights and/or remedies under any agreement between any member of the EHH Group, on the one hand, and the Company or any of its subsidiaries, including Triad Hunter, on the other hand, including the Gathering Agreement; v. NHIP II agreed to, prior to the Forbearance End Date, (i) commencing upon the receipt of the First Payment, forbear from the exercise and/or enforcement of any rights and/or remedies with respect to the Company under the New LLC Agreement or otherwise, including, without limitation, under Section 8.4(d)(ii) of the New LLC Agreement, in respect of any arrearages under the Gathering Agreement, and (ii) not commence any action at law or in equity or otherwise against the Company or Triad Hunter in respect of such arrearages, including an involuntary bankruptcy proceeding; and vi. Eureka Midstream agreed to, and NHIP II agreed to instruct the EHH Group to, amend the Demand Notice to extend the Deadline until the earlier to occur of (a) December 31, 2015; (b) the date on which the Company and Triad Hunter breaches any of its obligations under the November 2015 Letter Agreement; (c) the taking of any action by the Company or Triad Hunter that is materially inconsistent with the November 2015 Letter Agreement; (d) upon the filing of a voluntary petition for relief under the Bankruptcy Code by the Company or Triad Hunter; (e) upon the latter of an entry of an order for relief entered or 45 days after the filing of an involuntary case under the Bankruptcy Code against the Company or Triad Hunter; (f) after the effective date of the November 2015 Letter Agreement, any Default or Event of Default (as defined in the Gathering Agreement) of the Gathering Agreement by the Company or Triad Hunter, other than a Default or Event of Default arising from the Company’s or Triad Hunter’s failure to pay amounts due under the Gathering Agreement or a Default or Event of Default arising from an involuntary or voluntary bankruptcy filing; and (g) the occurrence of a Liquidity Event (the “Forbearance End Date”). In connection with the Company’s bankruptcy proceeding, the Company agreed to assume the gathering agreement with Eureka Midstream subject to certain agreed upon amendments. These amendments will, among other things, modify certain of the reservation fees and commodity fees that Triad Hunter pays to Eureka Midstream and provide certain volume credits to Triad Hunter. TGT Transportation Agreement On August 18, 2014, Triad Hunter executed a Precedent Agreement for Texas Gas Transmission LLC’s (“TGT”) Northern Supply Access Line (“TGT Transportation Services Agreement”). Through executing the TGT Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation capacity on TGT’s Northern Supply Access Line. The term of the TGT Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to be in early 2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement is contingent upon TGT receiving appropriate approvals from the Federal Energy Regulatory Commission (“FERC”) for their pipeline project. Upon executing a Firm Transportation Agreement, the Company will have minimum annual contractual obligations for reservation charges of approximately $12.8 million over the 15 year term of the agreement. On October 21, 2014, Triad Hunter executed a Credit Support Agreement with TGT, related to the TGT Transportation Services Agreement executed on August 18, 2014, (“Precedent Agreement Date”). In accordance with the provisions of the Credit Support Agreement, Triad Hunter will provide TGT with letters of credit on the dates and in the amounts that follow (“Credit Support Amount”): i during the period beginning on the date that is fourteen months after the Precedent Agreement Date and ending on the day immediately prior to the date that is twenty-one months after the Precedent Agreement Date, an amount equal to

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	NOTE 19 - SUPPLEMENTAL CASH FLOW INFORMATION The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing transactions: Year Ended December 31, 2015 2014 2013 (in thousands) Cash paid for interest $ 55,531 $ 73,192 $ 67,736 Cash paid for taxes $ — $ — $ 1,200 Non-cash transactions Change in accrued capital expenditures - increase (decrease) $ (100,774 ) $ 127,068 $ (65,634 ) Reclassification of deposit from field equipment to other assets $ 2,125 $ — $ — Eureka Midstream Holdings, LLC Series A convertible preferred unit dividends paid in kind $ — $ 1,950 $ 8,243 Non-cash additions to asset retirement obligation $ 141 $ 3,426 $ 2,132 Common stock issued for 401k matching contributions $ 1,878 $ 1,593 $ 1,192 Non-cash consideration received from sale of assets $ — $ 9,447 $ 42,300 Loss on extinguishment of Eureka Midstream Holdings Series A Preferred Units $ — $ (51,692 ) $ — The Company issued dividends on common stock in the form of 17,030,622 warrants with fair value of $21.6 million during the year ended December 31, 2013.

SEGMENT REPORTING

SEGMENT REPORTING	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Reporting	NOTE 20 - SEGMENT REPORTING Upstream, Midstream and Oilfield Services represent the operating segments of the Company. The Upstream segment is organized and operated to explore for and produce crude oil and natural gas within the geographic boundaries of the U.S. and Canada. All Canadian operations were divested during the year ended December 31, 2014 as discussed in “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” , and are classified as discontinued operations. The Midstream segment consists primarily of Eureka Midstream Holdings, which markets natural gas and operates a network of pipelines and compression stations that gather natural gas and NGLs in the U.S. for transportation to market. During the year ended December 31, 2013 and through December 18, 2014, Eureka Midstream Holdings was a consolidated subsidiary of the Company. Subsequent to December 18, 2014, the Company accounts for its interest in Eureka Midstream Holdings using the equity method of accounting. See “Note 4 - Eureka Midstream Holdings”. The Oilfield Services segment provides drilling services to oil and natural gas exploration and production companies. The customers of the Company’s Midstream and Oilfield Services segments are the Company and its subsidiaries and also third-party oil and natural gas companies. The following tables set forth operating activities and capital expenditures by segment for the years ended, and segment assets as of December 31, 2015 , 2014 , and 2013 . For the Year Ended December 31, 2015 Upstream Midstream (1) Oilfield Services Corporate Unallocated Intersegment Eliminations Total (in thousands) Total revenue $ 134,812 $ 867 $ 18,973 $ — $ (528 ) $ 154,124 Depreciation, depletion, and amortization 128,973 — 3,926 — (95 ) 132,804 (Gain) loss on sale of assets (31,409 ) — 51 — — (31,358 ) Other operating expenses 454,984 736 19,637 38,794 (387 ) 513,764 Other income (expense) (10,091 ) (181,092 ) (577 ) (89,887 ) — (281,647 ) Reorganization items, net — — — (41,139 ) — (41,139 ) Net income (loss) $ (427,827 ) $ (180,961 ) $ (5,218 ) $ (169,820 ) $ (46 ) $ (783,872 ) Total assets $ 756,265 $ 166,107 $ 37,787 $ 100,040 $ (41 ) $ 1,060,158 Total capital expenditures $ 63,981 $ — $ 650 $ 2,247 $ — $ 66,878 For the Year Ended December 31, 2014 Upstream Midstream (1) Oilfield Services Corporate Unallocated (1) Intersegment Eliminations Total (in thousands) Total revenue $ 270,615 $ 109,658 $ 31,392 $ — $ (20,196 ) $ 391,469 Depreciation, depletion, and amortization 127,607 15,737 3,524 — — 146,868 Gain on sale of assets (2,075 ) (12 ) (369 ) — — (2,456 ) Other operating expenses 556,085 93,138 26,642 81,746 (20,196 ) 737,415 Other income (expense) 1,340 (99,221 ) (813 ) 454,921 (3,702 ) 352,525 Income (loss) from continuing operations before income tax (409,662 ) (98,426 ) 782 373,175 (3,702 ) (137,833 ) Income (loss) from discontinued operations, net of tax 3,481 — — (12,775 ) — (9,294 ) Net income (loss) $ (406,181 ) $ (98,426 ) $ 782 $ 360,400 $ (3,702 ) $ (147,127 ) Total assets $ 1,168,829 $ 347,645 $ 47,009 $ 116,849 $ (2,377 ) $ 1,677,955 Total capital expenditures $ 470,843 $ 221,455 $ 8,079 $ 231 $ — $ 700,608 For the Year Ended December 31, 2013 Upstream Midstream (1) Oilfield Services Corporate Unallocated Intersegment Eliminations Total (in thousands) Total revenue $ 225,498 $ 69,306 $ 21,527 $ — $ (11,793 ) $ 304,538 Depreciation, depletion, and amortization 92,713 12,318 2,354 — — 107,385 Loss on sale of assets 44,629 8 4 — — 44,641 Other operating expenses 267,935 60,497 19,252 49,241 (9,620 ) 387,305 Other income (expense) (656 ) (22,358 ) (507 ) (61,446 ) 2,240 (82,727 ) Income (loss) from continuing operations before income tax (180,435 ) (25,875 ) (590 ) (110,687 ) 67 (317,520 ) Income tax benefit 56,418 — — 28,989 — 85,407 Total income (loss) from discontinued operations, net of tax 9,018 — — — (69 ) 8,949 Net income (loss) $ (114,999 ) $ (25,875 ) $ (590 ) $ (81,698 ) $ (2 ) $ (223,164 ) Total assets $ 1,441,408 $ 296,739 $ 44,193 $ 77,684 $ (3,373 ) $ 1,856,651 Total capital expenditures $ 459,737 $ 87,498 $ 22,440 $ 1,037 $ — $ 570,712 ______________ (1) For the years ended December 31, 2014 and 2013, the Midstream segment includes operations of Eureka Midstream Holdings, which represents approximately 38.6% and 40.7% of Midstream revenues for the years ended December 31, 2014 and 2013, respectively, and which was deconsolidated as of December 18, 2014. See “Note 4 - Eureka Midstream Holdings”. For the year ended December 31, 2015, other expense of the Midstream segment represents loss from the Company’s equity method investment in Eureka Midstream Holdings.

CONDENSED CONSOLIDATED GUARANTO

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS	NOTE 21 - CONDENSED COMBINED GUARANTOR FINANCIAL STATEMENTS Guarantor Subsidiaries Certain of the Company’s wholly owned subsidiaries, including Alpha Hunter Drilling, Bakken Hunter, Shale Hunter, Magnum Hunter Marketing, MHP, NGAS Hunter, Triad Hunter, VIRCO, and Bakken Hunter Canada, (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. Condensed consolidating financial information for Magnum Hunter Resources Corporation, the Guarantor Subsidiaries and the other subsidiaries of the Company (“Non Guarantor Subsidiaries”) as of December 31, 2015 and 2014 and for the years ended December 31, 2015 , 2014 , and 2013 is as follows: Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Balance Sheets (in thousands) As of December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter ASSETS Current assets $ 52,010 $ 31,359 $ 177 $ 2 $ 83,548 Intercompany accounts receivable 1,159,346 — — (1,159,346 ) — Property and equipment (using successful efforts accounting) 6,221 762,361 — (44 ) 768,538 Investment in subsidiaries (516,241 ) 91,759 — 424,482 — Investment in affiliate, equity-method 166,099 — — — 166,099 Other assets 41,809 164 — — 41,973 Total Assets $ 909,244 $ 885,643 $ 177 $ (734,906 ) $ 1,060,158 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities $ 127,469 $ 18,390 $ 39 $ 2 $ 145,900 Intercompany accounts payable — 1,120,148 41,434 (1,161,582 ) — Liabilities subject to compromise 994,120 101,951 — — 1,096,071 Long-term liabilities 139 30,532 — — 30,671 Redeemable preferred stock 100,000 — — — 100,000 Shareholders' equity (deficit) (312,484 ) (385,378 ) (41,296 ) 426,674 (312,484 ) Total Liabilities and Shareholders' Equity $ 909,244 $ 885,643 $ 177 $ (734,906 ) $ 1,060,158 Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Balance Sheets (in thousands) As of December 31, 2014 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter ASSETS Current assets $ 88,542 $ 41,569 $ 589 $ (2,378 ) $ 128,322 Intercompany accounts receivable 1,113,417 — — (1,113,417 ) — Property and equipment (using successful efforts 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 $ 1,485,865 $ 1,309,805 $ 619 $ (1,118,334 ) $ 1,677,955 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities $ 28,242 $ 148,145 $ 2,567 $ (2,383 ) $ 176,571 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 $ 1,485,865 $ 1,309,805 $ 619 $ (1,118,334 ) $ 1,677,955 Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Operations (in thousands) For the Year Ended December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Revenues $ 16 $ 155,270 $ 1,036 $ (2,198 ) $ 154,124 Expenses 351,749 587,612 789 (2,154 ) 937,996 Income (loss) from continuing operations before equity in net income of subsidiaries (351,733 ) (432,342 ) 247 (44 ) (783,872 ) Equity in net income of subsidiaries (432,139 ) (2,374 ) — 434,513 — Income (loss) from continuing operations before income tax (783,872 ) (434,716 ) 247 434,469 (783,872 ) Income tax benefit — — — — — Net income (loss) (783,872 ) (434,716 ) 247 434,469 (783,872 ) Dividends on preferred stock (33,817 ) — — — (33,817 ) Net income (loss) attributable to common shareholders $ (817,689 ) $ (434,716 ) $ 247 $ 434,469 $ (817,689 ) For the Year Ended December 31, 2014 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Revenues $ 142 $ 368,537 $ 43,611 $ (20,821 ) $ 391,469 Expenses (370,646 ) 772,355 144,714 (17,121 ) 529,302 Income (loss) from continuing operations before equity in net income of subsidiaries 370,788 (403,818 ) (101,103 ) (3,700 ) (137,833 ) Equity in net income of subsidiaries (513,580 ) (8,181 ) — 521,761 — Income (loss) from continuing operations before income tax (142,792 ) (411,999 ) (101,103 ) 518,061 (137,833 ) Income tax benefit — — — — — Income (loss) from continuing operations (142,792 ) (411,999 ) (101,103 ) 518,061 (137,833 ) Income from discontinued operations, net of tax — — 4,561 — 4,561 Gain (loss) on disposal of discontinued operations, net of tax (20,027 ) 97 6,075 — (13,855 ) Net income (loss) (162,819 ) (411,902 ) (90,467 ) 518,061 (147,127 ) Net income attributable to non-controlling interest — — — 3,653 3,653 Net income (loss) attributable to Magnum Hunter Resources Corporation (162,819 ) (411,902 ) (90,467 ) 521,714 (143,474 ) Dividends on preferred stock (35,364 ) — (19,343 ) — (54,707 ) Loss on extinguishment of Eureka Midstream Holdings (51,692 ) — — — (51,692 ) Net income (loss) attributable to common shareholders $ (249,875 ) $ (411,902 ) $ (109,810 ) $ 521,714 $ (249,873 ) Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Operations (in thousands) For the Year Ended December 31, 2013 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Revenues $ 2,629 $ 277,854 $ 35,848 $ (11,793 ) $ 304,538 Expenses 112,754 461,173 59,991 (11,860 ) 622,058 Income (loss) from continuing operations before equity in net income of subsidiaries (110,125 ) (183,319 ) (24,143 ) 67 (317,520 ) Equity in net income of subsidiaries (298,775 ) (424 ) — 299,199 — Income (loss) from continuing operations before income tax (408,900 ) (183,743 ) (24,143 ) 299,266 (317,520 ) Income tax benefit (expense) 28,989 56,422 (4 ) — 85,407 Income (loss) from continuing operations (379,911 ) (127,321 ) (24,147 ) 299,266 (232,113 ) Income (loss) from discontinued operations, net of tax (7,813 ) 22,661 (77,340 ) (69 ) (62,561 ) Gain (loss) on disposal of discontinued operations, net of tax 144,378 — (72,868 ) — 71,510 Net income (loss) (243,346 ) (104,660 ) (174,355 ) 299,197 (223,164 ) Net income attributable to non-controlling interest — — — 988 988 Net income (loss) attributable to Magnum Hunter Resources Corporation (243,346 ) (104,660 ) (174,355 ) 300,185 (222,176 ) Dividends on preferred stock (35,464 ) — (21,241 ) — (56,705 ) Net income (loss) attributable to common shareholders $ (278,810 ) $ (104,660 ) $ (195,596 ) $ 300,185 $ (278,881 ) Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Comprehensive Income (Loss) (in thousands) For the Year Ended December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Net income (loss) $ (783,872 ) $ (434,716 ) $ 247 $ 434,469 $ (783,872 ) Foreign currency translation gain — 99 — — 99 Unrealized loss on available for sale securities — (2,771 ) — — (2,771 ) Amounts reclassified for other than temporary impairment of available for sale securities — 10,183 — — 10,183 Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities — (19 ) — — (19 ) Comprehensive income (loss) $ (783,872 ) $ (427,224 ) $ 247 $ 434,469 $ (776,380 ) For the Year Ended December 31, 2014 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Net income (loss) $ (162,819 ) $ (411,902 ) $ (90,467 ) $ 518,061 $ (147,127 ) Foreign currency translation loss — — (1,204 ) — (1,204 ) Unrealized loss on available for sale securities — (7,401 ) — — (7,401 ) Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc. 20,741 — — — 20,741 Comprehensive income (loss) (142,078 ) (419,303 ) (91,671 ) 518,061 (134,991 ) Comprehensive (income) loss attributable to non-controlling interest — — — 3,653 3,653 Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation $ (142,078 ) $ (419,303 ) $ (91,671 ) $ 521,714 $ (131,338 ) For the Year Ended December 31, 2013 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Net income (loss) $ (243,346 ) $ (104,660 ) $ (174,355 ) $ 299,197 $ (223,164 ) Foreign currency translation loss — — (10,928 ) — (10,928 ) Unrealized gain (loss) on available for sale securities 8,262 (84 ) — — 8,178 Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities (8,262 ) — — — (8,262 ) Comprehensive income (loss) (243,346 ) (104,744 ) (185,283 ) 299,197 (234,176 ) Comprehensive (income) loss attributable to non-controlling interest — — — 988 988 Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation $ (243,346 ) $ (104,744 ) $ (185,283 ) $ 300,185 $ (233,188 ) Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Cash Flows (in thousands) For the Year Ended December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Cash flow from operating activities $ (113,263 ) $ 138,429 $ — $ (140 ) $ 25,026 Cash flow from investing activities (43,305 ) (122,776 ) — 140 (165,941 ) Cash flow from financing activities 134,733 (6,099 ) — — 128,634 Effect of exchange rate changes on cash — (28 ) — — (28 ) Net increase (decrease) in cash (21,835 ) 9,526 — — (12,309 ) Cash at beginning of period 64,165 (10,985 ) — — 53,180 Cash at end of period $ 42,330 $ (1,459 ) $ — $ — $ 40,871 For the Year Ended December 31, 2014 Magnum Hunter Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Cash flow from operating activities $ (347,898 ) $ 255,088 $ 74,145 $ — $ (18,665 ) Cash flow from investing activities 107,595 (248,928 ) (176,786 ) — (318,119 ) Cash flow from financing activities 250,194 301 97,700 — 348,195 Effect of exchange rate changes on cash — — 56 — 56 Net increase (decrease) in cash 9,891 6,461 (4,885 ) — 11,467 Cash at beginning of period 47,895 (17,651 ) 11,469 — 41,713 Cash at end of period $ 57,786 $ (11,190 ) $ 6,584 $ — $ 53,180 For the Year Ended December 31, 2013 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Cash flow from operating activities $ (371,351 ) $ 397,213 $ 99,153 $ (13,304 ) $ 111,711 Cash flow from investing activities 422,303 (411,473 ) (138,690 ) — (127,860 ) Cash flow from financing activities (29,929 ) 796 16,485 13,304 656 Effect of exchange rate changes on cash — — (417 ) — (417 ) Net increase (decrease) in cash 21,023 (13,464 ) (23,469 ) — (15,910 ) Cash at beginning of period 26,872 (4,187 ) 34,938 — 57,623 Cash at end of period $ 47,895 $ (17,651 ) $ 11,469 $ — $ 41,713

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 22 - SUBSEQUENT EVENTS Consummation of Second and Third DIP Draws under the DIP Facility The Second DIP Draw was fully funded on January 14, 2016 following the Bankruptcy Court’s entry of the Final DIP Order on January 11, 2016 approving, on a final basis, the financing provided pursuant to the DIP Credit Agreement. Approximately $70.2 million of the net proceeds from the Second DIP Draw was used to repay in full all loans outstanding under the Company’s Senior Secured Bridge Financing Facility. The Third DIP Draw was fully funded on April 21, 2016, following the satisfaction of certain conditions pursuant to the DIP Credit Agreement. See “Note 3 - Voluntary Reorganization under Chapter 11” and “Note 11 - Long-Term Debt” . Rejection or Amendment of Certain Agreements through the Bankruptcy Proceedings TGT Transportation Agreement and Related Contracts On February 19, 2016, the Company and the other Debtors filed a motion with the Bankruptcy Court seeking to reject the TGT Transportation Services Agreement, the Credit Support Agreement, and certain ancillary contracts. On March 10, 2016, the Bankruptcy Court held a hearing on the motion. At the March 10, 2016 hearing, the Debtors and TGT announced a settlement agreement under which all executory contracts related to the TGT Transportation Services Agreement will be rejected and all other related contracts will be terminated, and TGT will be entitled to an Allowed General Unsecured Claim (as defined in the Plan) in an amount of $15 million . The Bankruptcy Court approved the related settlement motion on March 30, 2016. See “Note 18 - Commitments and Contingencies” . Eureka Midstream Amended and Restated Gas Gathering Services Agreement In connection with the bankruptcy proceedings, Triad Hunter agreed to assume the Amended and Restated Gas Gathering Services Agreement with Eureka Midstream, subject to certain agreed upon amendments. These amendments will, among other things, modify certain of the reservation fees and commodity fees that Triad Hunter pays to Eureka Midstream and provide certain volume credits to Triad Hunter. See “Note 18 - Commitments and Contingencies” . Continuum Energy Natural gas production from MHP’s southern Appalachian Basin properties is delivered and sold through gas gathering facilities owned by Continuum Energy Services, L.L.C. and certain of its affiliates (collectively, “Continuum Energy”). MHP operates these gathering facilities, which are located in southeastern Kentucky, northeastern Tennessee and western Virginia. MHP has gas gathering and gas gathering facilities operating agreements with Continuum Energy. In connection with the bankruptcy proceeding, MHP agreed to assume its agreements with Continuum Energy, subject to certain agreed upon amendments. These amendments will, among other things, provide MHP with lower gas gathering rates, gas processing rates and liquids processing rates. In addition, MHP will continue to operate these gathering facilities. Rockies Express Pipeline LLC (“REX”) Transportation Services Agreement In connection with the bankruptcy proceeding, Triad Hunter agreed to assume the REX Transportation Services Agreement, subject to certain agreed upon amendments. Among other things, these amendments reduced Triad Hunter’s firm transportation volume commitment from 100,000 MMBtu per day to 50,000 MMBtu per day. In addition, the amount of Triad Hunter’s posted letter of credit will be reduced by approximately $2.8 million every three months until the posted letter of credit amount is reduced to $20.0 million , subject to further reduction five years following the effective date of the FTA. “Note 18 - Commitments and Contingencies” . Amendments to Restructuring Support Agreement On February 25, 2016, April 1, 2016, April 13, 2016 and May 5, 2016, the Company and the other Debtors entered into the First Amendment to RSA, the Second Amendment to RSA, the Third Amendment to RSA, and the Fourth Amendment to RSA, respectively, with certain Second Lien Lenders and certain Noteholders as further described in “Note 3 - Voluntary Reorganization under Chapter 11” . Amendments to the Plan of Reorganization On January 7, 2016, the Company and the other Debtors filed the Original Plan with the Bankruptcy Court. On February 19, 2016, February 25, 2016, and April 14, 2016, the Company and the other Debtors filed the First Amended Plan, the Second Amended Plan, and the Third Amended Plan, respectively, with the Bankruptcy Court as further described in “Note 3 - Voluntary Reorganization under Chapter 11” . Settlement of SEC Wells Notice On March 10, 2016, the SEC Commissioners approved a settlement negotiated with the Company. Without admitting or denying the SEC’s findings, the Company agreed to pay a civil penalty of $250,000 to the SEC, subject to Bankruptcy Court approval. On March 11, 2016, the Company filed a motion with the Bankruptcy Court seeking approval of the Company’s settlement with the SEC and authority to pay the civil penalty. The Bankruptcy Court approved the motion on March 29, 2016. See additional discussion in “Note 18 - Commitments and Contingencies” . Confirmation Hearing On March 27, 2016, the Company and the other Debtors filed a motion with the Bankruptcy Court seeking to adjourn the confirmation hearing that was previously scheduled for March 31, 2016. On March 29, 2016, a Notice of Adjournment was filed with the Bankruptcy Court to adjourn the confirmation hearing until April 8, 2016. On April 4, 2016, a Second Notice of Adjournment was filed with the Bankruptcy Court in order to further adjourn the confirmation hearing until April 18, 2016. The confirmation hearing was held, and the Bankruptcy Court approved the Plan, on April 18, 2016. See “Note 3 - Voluntary Reorganization under Chapter 11” .

OTHER INFORMATION

OTHER INFORMATION	12 Months Ended
	Dec. 31, 2015
Other Information
OTHER INFORMATION	NOTE 23 - OTHER INFORMATION Quarterly Data (Unaudited) The following tables set forth unaudited summary financial results on a quarterly basis for the most recent two years. Quarter Ended March 31, June 30, September 30, December 31, Year Ended 2015 (in thousands) Total revenue (1) $ 55,396 $ 39,526 $ 33,664 $ 25,538 $ 154,124 Operating income (loss) (2) $ (77,488 ) $ 4,529 $ (84,652 ) $ (303,475 ) $ (461,086 ) Net loss attributable to Magnum Hunter Resources Corporation (3) $ (105,919 ) $ (21,676 ) $ (113,181 ) $ (543,096 ) $ (783,872 ) Net loss attributable to common shareholders $ (114,767 ) $ (30,523 ) $ (122,029 ) $ (550,370 ) $ (817,689 ) Basic and diluted loss per common share $ (0.57 ) $ (0.15 ) $ (0.53 ) $ (2.11 ) $ (3.63 ) 2014 Total revenue (4) $ 113,482 $ 138,463 $ 79,670 $ 59,854 $ 391,469 Operating income (loss) (5) $ (32,762 ) $ 1,555 $ (57,576 ) $ (401,575 ) $ (490,358 ) Income (loss) from continuing operations (6) $ (56,557 ) $ (61,407 ) $ (123,189 ) $ 103,320 $ (137,833 ) Income from discontinued operations, net of tax $ 3,369 $ 1,192 $ — $ — $ 4,561 Gain (loss) on disposal of discontinued operations, net of tax $ (8,513 ) $ (5,212 ) $ (258 ) $ 128 $ (13,855 ) Net income (loss) attributable to Magnum Hunter Resources Corporation $ (61,592 ) $ (64,647 ) $ (120,683 ) $ 103,448 $ (143,474 ) Net income (loss) attributable to common shareholders $ (76,468 ) $ (79,997 ) $ (136,175 ) $ 42,767 $ (249,873 ) Basic and diluted income (loss) from continuing operations per common share $ (0.41 ) $ (0.41 ) $ (0.68 ) $ 0.23 $ (1.27 ) Basic and diluted income (loss) per common share $ (0.44 ) $ (0.43 ) $ (0.68 ) $ 0.23 $ (1.32 ) ______________ (1) Total revenues decreased during each consecutive quarter throughout the year ended December 31, 2015 primarily due to decreases in realized prices for oil, gas and NGLs. (2) Fluctuations in operating income (loss) throughout the year ended December 31, 2015 were impacted by decreases in revenues as discussed above, as well as by changes in depreciation, depletion, amortization and accretion expense, impairment of proved oil and gas properties, and exploration expense. During the quarter ended March 31, 2015, depreciation, depletion, amortization and accretion expense was $57.8 million , impairment of proved oil and gas properties was $13.9 million , and exploration expense was $8.5 million . In contrast, depreciation, depletion, amortization and accretion expense was $22.3 million , impairment of proved oil and gas properties was $0.1 million , and exploration expense was $1.5 million during the quarter ended June 30, 2015. During the quarter ended September 30, 2015, the Company recorded exploration expense of $4.4 million and impairment of proved oil and natural gas properties of $49.8 million primarily related to the Williston Basin, and during the quarter ended December 31, 2015, the Company recorded exploration expense of $45.5 million and impairment of proved oil and natural gas properties of $211.6 million related to both the Appalachian and Williston Basins. (3) Net loss attributable to Magnum Hunter Resources Corporation during the quarter ended December 31, 2015 includes impairment of $180.3 million in order to write down the carrying value of its equity interest in Eureka Midstream Holdings to fair value as a result of the Company’s determination that the investment no longer met the criteria for classification as a discontinued operation as of that date. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” . (4) Total revenues increased during the quarter ended June 30, 2014 primarily due to increases in natural gas gathering, processing, and marketing revenues as a result of new customers, growth from existing customers, and increased gas and NGLs revenues from the Markwest processing plant. Revenues decreased during the quarter ended September 30, 2014 due to decreases in natural gas gathering, processing, and marketing revenues. This decrease was due to the decision made by a third party customer to begin marketing their own natural gas, which had previously been marketed by the Company. Revenues decreased during the quarter ended December 31, 2014 due to decreases in oil prices, as well as decreased volumes due to the sales of certain oil and natural gas properties located in Divide County, North Dakota during the fourth quarter. (5) Income from operations during the quarter-ended June 30, 2014 was primarily driven by the increase in total revenues during that quarter, as discussed above. The loss from operations during the following quarter was due mainly to the decrease in total revenues, as discussed above. Loss from operations during the quarter ended December 31, 2014 was partially due to the decrease in revenues as discussed above, but also due to exploration expense of $66.1 million related mainly to the Williston Basin, impairment of proved oil and gas properties of $261.5 million mainly in the Williston Basin, and increased general and administrative expenses. General and administrative expenses during the quarter ended December 31, 2014 included a one-time charge of $32.6 million related to the Letter Agreement with MSI, in which the Company’s capital account with Eureka Midstream Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Midstream in connection with certain of Eureka Midstream’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects. (6) Loss from continuing operations during the quarters ended June 30, 2014 and September 30, 2014 includes loss on derivative contracts of $42.8 million and $49.6 million , respectively, primarily as a result of the unrealized loss on the embedded derivative liability resulting from certain features of the Eureka Midstream Holdings Series A Preferred Units. The unrealized losses were driven by increases in total enterprise value and a reduction in the expected term of the conversion feature. Income from continuing operations for the quarter ended December 31, 2014 includes a gain of $509.6 million from the deconsolidation of Eureka Midstream Holdings. See “Note 4 - Eureka Midstream Holdings”. Supplemental Oil and Gas Disclosures (Unaudited) The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities (in thousands): For the Year Ended December 31, 2015 2014 2013 Purchase of non-producing leases $ 18,906 $ 124,411 $ 149,592 Purchase of producing properties — 12,246 1,358 Exploration costs — 9,907 11,531 Development costs 45,075 327,138 276,130 $ 63,981 $ 473,702 $ 438,611 Oil and Gas Reserve Information Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firm Cawley, Gillespie, & Associates, Inc. in 2015 , 2014 , and 2013 . There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact. Total Proved Reserves Crude Oil NGLs Natural Gas (MBbl) (MBbl) (MMcf) Balance December 31, 2012 36,827 9,125 162,620 Revisions of previous estimates (1) 3,766 2,382 100,456 Purchase of reserves in place — — 88 Extensions, discoveries, and other additions 577 71 1,285 Sale of reserves in place (14,506 ) (698 ) (4,185 ) Production (2,329 ) (458 ) (13,482 ) Balance December 31, 2013 24,335 10,422 246,782 Revisions of previous estimates (1) (6,540 ) 2,149 (511 ) Extensions, discoveries, and other additions 1,705 3,226 132,345 Sale of reserves in place (7,321 ) (434 ) (3,768 ) Production (1,658 ) (960 ) (21,847 ) Balance December 31, 2014 10,521 14,403 353,001 Revisions of previous estimates (1) (6,075 ) (6,959 ) (162,147 ) Extensions, discoveries and other additions — — 25,309 Production (1,016 ) (1,263 ) (34,778 ) Balance December 31, 2015 3,430 6,181 181,385 Developed reserves, included above December 31, 2013 12,085 6,990 176,585 December 31, 2014 6,938 10,587 251,628 December 31, 2015 3,430 6,181 156,076 Proved undeveloped reserves, included above: December 31, 2013 12,250 3,432 70,197 December 31, 2014 3,583 3,816 101,373 December 31, 2015 — — 25,309 ______________ (1) See discussion of revisions of previous estimates under “Changes in Standardized Measure of Discounted Future Net Cash Flows” below. The sale of reserves in place during the year ended December 31, 2013, includes approximately 11,459 MBoe of proved reserves included in the sale of Eagle Ford Hunter and approximately 4,308 MBoe of proved reserves in the sale of certain North Dakota Oil and Natural Gas Properties (see “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” ). Extensions, discoveries and other additions during the year ended December 31, 2014, related to (i) extension of the proved acreage of previously discovered reserves through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions and discoveries increased 26,126 MBoe in 2014 to 26,988 MBoe from a base of 862 MBoe in 2013. The largest extensions and discoveries were all related to activity in the Company’s Marcellus Shale and Utica Shale development program which included the wells completed on the Stewart Winland, Stalder, WVDNR and Ormet pads. Extensions and discoveries of 25,309 MMcf ( 4,218 MBoe) in 2015 were related to activity on the Company’s Stalder and Ormet pads. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with provisions of ASC 932 - Extractive Activities - Oil and Gas . Future cash inflows at December 31, 2015 , 2014 , and 2013 were computed by applying the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2015 , 2014 , and 2013 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carry forwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company’s oil and natural gas properties. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: Years Ended December 31, 2015 2014 2013 (in thousands) Future cash inflows $ 598,161 $ 3,282,768 $ 3,711,260 Future production costs (369,478 ) (1,443,121 ) (1,423,306 ) Future development costs (16,712 ) (219,509 ) (421,797 ) Future income tax expense — — (149,367 ) Future net cash flows 211,971 1,620,138 1,716,790 10% annual discount for estimated timing of cash flows (101,382 ) (710,875 ) (872,280 ) Standardized measure of discounted future net cash flows $ 110,589 $ 909,263 $ 844,510 Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end. No provision for income taxes has been provided in the above standardized measure of discounted future net cash flows as of December 31, 2015 and 2014, as a result of the Company’s net operating loss carryforwards of $1,031 million and $710 million , respectively, and other future expected tax deductions. See “Note 15 - Income Taxes” . Changes in Standardized Measure of Discounted Future Net Cash Flows The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: Years Ended December 31, 2015 2014 2013 (in thousands) Balance, beginning of period $ 909,263 $ 844,510 $ 847,653 Net changes in prices and production costs (640,645 ) (281,352 ) (7,355 ) Changes in estimated future development costs 137,578 (57,348 ) (261,591 ) Sales and transfers of oil and gas produced during the period (20,851 ) (166,611 ) (190,151 ) Net changes due to extensions, discoveries, and improved recovery 12,630 332,684 12,829 Net changes due to revisions of previous quantity estimates (1) (458,945 ) (55,176 ) 341,003 Previously estimated development costs incurred during the period 44,976 269,017 283,736 Accretion of discount 77,077 95,547 90,153 Purchase of minerals in place — — 218 Sale of minerals in place — (141,847 ) (236,885 ) Changes in timing and other 49,506 (7,720 ) (91,088 ) Net change in income taxes — 77,559 55,988 Standardized measure of discounted future net cash flows $ 110,589 $ 909,263 $ 844,510 ______________ (1) For the year ended December 31, 2015 , the Company made downward revisions of 6,075 MBbl of oil, 162,147 MMcf of natural gas, and 6,959 MBbl of natural gas liquids due to additional information gathered from continued production, lower pricing levels, and liquidity constraints. For the year ended December 31, 2014 , the Company made downward revisions of 6,540 MBbls of oil and 511 MMcf of natural gas, and upward revisions of 2,149 MBbl of natural gas liquids due to additional information gathered from continued production from the shale areas and increases in estimated ultimate recoveries (“EURs”). For the year ended December 31, 2013 , the Company made upward revisions of 3,766 MBbls of oil, 2,382 MBbl of natural gas liquids and 100,456 MMcf of natural gas due to continued production from the shale areas and increases in EURs. The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows: 2015 2014 2013 Oil (per Bbl) $ 41.83 $ 85.21 $ 93.13 Natural gas liquids (per Bbl) $ 16.90 $ 50.64 $ 43.79 Gas (per Mcf) $ 1.93 $ 4.69 $ 4.14 In accordance with SEC requirements, the pricing used in the Company’s standardized measure of future net revenues is based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period January through December for each period presented and adjusted by lease for transportation fees and regional price differentials. The use of SEC pricing rules may not be indicative of actual prices realized by the Company in the future.

SUMMARY OF SIGNIFICANT ACCOUN32

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Presentation of Consolidated Financial Statements	Presentation of Consolidated Financial Statements The consolidated financial statements include the accounts of the Company and entities in which it holds a controlling financial interest. The Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions have been eliminated. The consolidated financial statements have been prepared in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852, Reorganizations . This guidance requires that transactions and events directly associated with the Chapter 11 reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. See “Note 3 - Voluntary Reorganization under Chapter 11” . The Company deconsolidates entities in which it no longer holds a controlling financial interest as of the date control is lost. The results of operations and assets and liabilities of deconsolidated entities are included in the Company’s consolidated financial statements with all significant intercompany balances eliminated through the date of deconsolidation. Subsequently, retained interests in an entity, if any, are accounted for based on the nature of the retained interest in accordance with GAAP. The consolidated financial statements also reflect the interests of the Company’s wholly owned subsidiary, MHP, in various managed drilling partnerships. The Company accounts for the interests in these managed drilling partnerships using the proportionate consolidation method.
Use of Estimates in the Preparation of Financial Statements	Use of Estimates in the Preparation of Financial Statements Preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant recurring items subject to such estimates and assumptions include those related to stock based compensation, the valuation of commodity and financial derivative instruments, embedded derivative assets and liabilities, asset retirement obligations and other liabilities and whether declines in the value of investments are other than temporary. The estimates of proved, probable and possible oil and gas reserves are used as significant inputs in determining the depletion of oil and gas properties and the impairment of proved and unproved oil and gas properties. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. The determination of whether declines in the value of investments are other than temporary involves the consideration of many factors including, but not limited to, the length of time and the extent to which market value has been less than cost, the financial condition and near-term prospects of the investee, and the intent and ability of the Company to retain its investment for a period of time sufficient to allow for any anticipated recovery in market value. Evaluating these factors requires significant judgment. Non-recurring items subject to significant estimates include the fair value of the Company’s retained financial interest in equity method investees and liabilities subject to compromise. Actual results could differ from the estimates and assumptions utilized.
Non-Controlling Interest in Consolidated Subsidiaries	Non-Controlling Interest in Consolidated Subsidiaries 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 its previously consolidated affiliate, Eureka Midstream Holdings. Accordingly, the results of operations of Eureka Midstream Holdings were consolidated in the accompanying consolidated financial statements up to December 18, 2014. The Company held a 48.6% equity interest in Eureka Midstream Holdings at December 18, 2014 and December 31, 2014, and held a 44.5% equity interest at December 31, 2015. The Company accounts for this retained interest under the equity method of accounting with the Company’s share of Eureka Midstream Holdings’ earnings recorded in “Loss from equity method investment” in the accompanying consolidated statements of operations. See “Note 4 - Eureka Midstream Holdings” and “Note 10 - Investments and Derivatives” . Prior to July 24, 2014, the Company owned 87.5% of the equity interests in PRC Williston, which sold substantially all of its assets on December 30, 2013. On July 24, 2014, the Company executed a settlement and release agreement with Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a/ D.B. Zwirn Special Opportunities Fund, L.P. As a result of this settlement agreement, the Company owns 100% of the equity interests in PRC Williston and has all rights and claims to its remaining assets and liabilities, which are not significant. The net loss attributable to non-controlling interest for PRC Williston is recorded through July 24, 2014. Changes in the non-controlling interests attributable to entities in which the Company held a controlling financial interest were accounted for as equity transactions, as they were considered investments by owners and distributions to owners acting in their capacity as owners. No gains or losses were recognized as the carrying value of the non-controlling interest was adjusted to reflect the change in the Company’s ownership interest in the subsidiary.
Reclassification of Prior-Year Balances	Reclassification of Prior-Year Balances Certain prior period balances have been reclassified to correspond with current-period presentation. The Company has reclassified approximately $5.2 million of oil and gas transportation, processing and production tax payables from “Accounts receivable: oil and natural gas sales” to “Accounts payable” as of December 31, 2014 in the accompanying consolidated balance sheets.
Financial instruments	Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, notes receivable, payables and accrued liabilities, derivatives, and certain long-term debt instruments approximate fair value as of December 31, 2015 and 2014 .
Cash and cash equivalents	Cash and Cash Equivalents Cash and cash equivalents include cash in banks and highly liquid investment securities that have original maturities of three months or less.
Accounts Receivable	Accounts Receivable The Company’s share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. Accounts receivable (oil and natural gas sales) consist of accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. At December 31, 2015 and 2014 , the Company did not have any allowance for doubtful accounts with respect to its oil and natural gas sales accounts receivable. Accounts receivable from joint interest owners and other consists primarily of joint interest owner obligations due within 30 days of the invoice date. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible.
Commodity and Financial Derivative Instruments	Commodity and Financial Derivative Instruments At various times, the Company has used commodity and financial derivative instruments, typically options and swaps, to manage the risk associated with fluctuations in oil and gas prices. Freestanding derivative instruments are recorded at fair value in the consolidated balance sheets as either an asset or liability, with those contracts maturing in the next twelve months classified as current, and those maturing thereafter as long-term. The Company recognizes changes in the fair value of derivatives in earnings, as it has not designated its oil and gas price derivative contracts as cash flow hedges. The Company recognizes the gains and losses on settled and open transactions on a net basis within the “Gain (loss) on derivative contracts, net” line item within the “Other Income (Expense)” section of the consolidated statements of operations. The Company may be party to contracts or purchase certain investments that contain embedded derivatives. If an embedded derivative is not clearly and closely related to the host contract, and as a separate instrument would qualify as a derivative, the derivative is separated from the host contract, held at fair value and reported separately from the host instrument in the consolidated balance sheets. The Company recognizes changes in the fair value of bifurcated derivatives in “ Gain (loss) on derivative contracts, net ”.
Investments in Affiliates, Equity Method	Investments in Affiliates, Equity Method Investments in non-controlled affiliates over which the Company is able to exercise significant influence but not control are accounted for under the equity method of accounting. Under the equity method of accounting, the Company’s share of the investee’s underlying net income or loss is recorded as earnings (loss) from equity method investment. Distributions received from the investment reduce the Company’s investment balance. When an investee accounted for using the equity method issues its own equity or when the Company sells a portion of its interest in the investee that results in a reduction in the Company’s interest in the investee, a gain or loss is recognized equal to the proportionate change in the Company’s interest in the investee’s net assets. Investments in equity method investees are evaluated for impairment as events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If a decline in the value of an equity method investment is determined to be other-than-temporary, a loss is recorded. The Company evaluated its investment in Eureka Midstream Holdings and determined that while the investment had declined in value, the decline was not other-than-temporary; and no impairment was required as of December 31, 2015 . Upon the deconsolidation of Eureka Midstream Holdings on December 18, 2014, the Company remeasured its retained interest in Eureka Midstream Holdings at fair value in accordance with the derecognition provisions of ASC Topic 810, Consolidation . See “Note 4 - Eureka Midstream Holdings” and “Note 9 - Fair Value of Financial Instruments” . Effective June 2015, the Company reclassified its equity method investment in Eureka Midstream Holdings to assets of discontinued operations. As of November 3, 2015, the Company determined that the planned divestiture no longer met the criteria for classification as a discontinued operation, and remeasured the carrying value of its equity method investment in Eureka Midstream Holdings at fair value. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” and “Note 9 - Fair Value of Financial Instruments” .
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip new development wells and related asset retirement costs are capitalized. Costs to acquire mineral interests and drill exploratory wells are also capitalized pending determination of whether the wells have proved reserves or not. If the Company determines that the wells do not have proved reserves, the costs are charged to exploration expense. Geological and geophysical costs, including seismic studies and related costs of carrying and retaining unproved properties are charged to exploration expense as incurred. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization as a normal retirement with no resulting gain or loss recognized in income if the amortization rate is not significantly affected; otherwise it is accounted for as the sale of an asset and a gain or loss is recognized. Leasehold costs attributable to proved oil and gas properties are depleted by the unit-of-production method over total proved reserves. Capitalized development costs are depleted by the unit-of-production method over proved developed producing reserves. Unproved oil and gas leasehold costs that are individually significant are periodically assessed for impairment of value by comparing current quotes and recent acquisitions, future lease expirations, and taking into account management’s intent, and a loss is recognized at the time of impairment by providing an impairment allowance recognized in “Exploration” expense in the consolidated statements of operations. Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment quarterly based on an analysis of undiscounted future net cash flows of proved and risk-adjusted probable and possible reserves. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows and other relevant market value data. Impairment of proved oil and gas properties is calculated on a field by field basis. It is common for operators of oil and gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically a provision of the joint operating agreement that working interest owners in a property adopt. The Company records these advance payments in the property accounts. If a lease associated with an unproved property expires without identifying proved reserves, the cost of the property is charged to the impairment allowance. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. If the Company sells its entire interest in an unproved property, the cost of the property and any proceeds received from the sale are charged to “ (Gain) loss on sale of assets, net ” in the consolidated statements of operations. The estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower market commodity prices, which may make it uneconomic to drill for and produce due to higher-cost fields.
Gas Transportation, Gathering, Processing Equipment	Gas Transportation, Gathering and Processing Equipment and Other The Company’s gas gathering system assets and field servicing assets are carried at cost. 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. Depreciation of gas gathering system assets is provided using the straight line method over an estimated useful life of fifteen years. Depreciation of field servicing assets is provided using the straight line method over various useful lives ranging from three to ten years. Gain or loss on retirement or sale of assets is included in “ (Gain) loss on sale of assets, net ” in the period of disposition or retirement. Furniture, fixtures and other equipment are carried at cost. Depreciation of furniture, fixtures and other equipment is provided using the straight-line method over estimated useful lives ranging from five to fifteen years. Gain or loss on retirement or sale of assets is included in “ (Gain) loss on sale of assets, net ” in the period of disposition or retirement.
Deferred Financing Costs	Deferred Financing Costs The Company may, from time to time, enter into or modify certain debt arrangements such as senior debentures, term loans, and lines of credit to fund capital expenditure plans and to fund other corporate expenses. Financing costs incurred as a result of these instruments are generally recorded as an asset and deferred over the life of the debt instrument using the straight line method for lines of credit and the effective interest method for term loans.
Intangible Assets	Intangible Assets Intangible assets consisted primarily of acquired gas treating agreements and customer relationships of Eureka Midstream Holdings. Such assets were being amortized over the estimated useful lives, which ranged from 2 to 13 years, up to December 18, 2014, when Eureka Midstream Holdings was deconsolidated. The Company assesses the carrying amount of its other intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable.
Revenue Payable	Revenue Payable Revenue payable represents amounts collected from purchasers for oil and gas sales which are either revenues due to other working or royalty interest owners or severance taxes due to the respective state or local tax authorities. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received. Revenue payable of approximately $5.2 million is included in “Liabilities subject to compromise” on the consolidated balance sheet as of December 31, 2015. See “Note 3 - Voluntary Reorganization under Chapter 11” .
Asset Retirement Obligation	Asset Retirement Obligation Asset retirement obligations (“ARO”) primarily represent the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the projected end of their productive lives, in accordance with applicable federal, state and local laws. The Company determined its ARO by calculating the present value of estimated cash flows related to the obligation. The retirement obligation is recorded as a liability at its estimated present value as of the obligation’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as accretion expense in the accompanying consolidated statements of operations. ARO liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated ARO. The liability for current ARO is reported in other current liabilities.
Revenue Recognition	Revenue Recognition Revenues associated with sales of crude oil, natural gas, and natural gas liquids are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. Prices for production are defined in sales contracts and are readily determinable or estimable based on available data. Revenues from the production of natural gas and crude oil from properties in which the Company has an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on the Company’s net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant. Revenues from field servicing activities are recognized at the time the services are provided and earned as provided in the various contract agreements. Gas gathering revenues are recognized at the time the natural gas is delivered at the destination point.
Production Costs	Production Costs Lease operating expenses, including compressor rental and repair, pumpers’ salaries, saltwater disposal, ad valorem taxes, insurance, repairs and maintenance, workovers and other operating expenses are expensed as incurred.
Severance Taxes and Marketing Costs	Severance Taxes and Marketing Costs Severance taxes are comprised of production taxes charged by most states on oil, natural gas, and natural gas liquids produced. These taxes are computed on the basis of volumes and/or value of production or sales. These taxes are usually levied at the time and place the minerals are severed from the producing reservoir. Marketing costs are those directly associated with marketing the Company’s production and are based on volumes.
Transportation, Processing, and Other Related Costs	Transportation, Processing, and Other Related Costs Transportation, processing, and other related costs are comprised of transportation and gathering expenses incurred to deliver natural gas to the processing plant and/or selling point, and are expensed as incurred.
Exploration	Exploration Exploration expense consists primarily of impairment reserves for abandonment costs associated with unproved properties for which the Company has no further exploration or development plans, exploratory dry hole costs, and geological and geophysical costs.
Share-based Compensation	Share-Based Compensation The Company estimates the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and matching contributions of stock to employees under its employee stock ownership plan, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. Awards that vest only upon achievement of performance criteria are recorded only when achievement of the performance criteria is considered probable. The Company estimated the fair value of each share-based award using the Black-Scholes option pricing model or a lattice model. These models are highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards, the estimated volatility of the Company’s stock price, and the assessment of whether the achievement of performance criteria is probable.
Income Taxes and Uncertain Tax Positions	Income Taxes and Uncertain Tax Positions Income taxes are accounted for in accordance with ASC Topic 740, Income Taxes, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in earnings in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. Interest and penalties related to income taxes are recognized in “ Income tax benefit ” in the consolidated statement of operations. Under accounting standards for uncertainty in income taxes, a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” ( i.e. a likelihood greater than 50 percent ) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in the accounting standards for income taxes refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The Company had no uncertain tax positions at December 31, 2015 or 2014 . The Company applies the intra-period tax allocation rules, using the with and without approach, to allocate income taxes among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital when it meets the criteria as prescribed in the rules.
Loss per Common Share	Loss per Common Share Basic net income or loss per common share is computed by dividing the net income or loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. During the year ended December 31, 2015, net loss attributable to common shareholders does not include preferred stock dividends that accumulated subsequent to the Petition Date. See “Note 13 - Shareholders' Equity” and “Note 14 - Redeemable Preferred Stock” for additional discussion of preferred stock dividends. Diluted net income or loss per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from stock options, unvested restricted stock awards, stock warrants and any outstanding convertible securities. Potentially dilutive common share equivalents are not included in the computation of diluted earnings per share if they are anti-dilutive.
Other Comprehensive Income (Loss)	Other Comprehensive Income (Loss) The functional currency of the Company’s operations in Canada is the Canadian dollar. The Company closed its Calgary, Alberta office effective January 31, 2015 due to the sales of all of its Canadian assets during 2014 (see “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” ), but maintained certain Canadian bank accounts through December 31, 2015. For purposes of consolidation, the Company translated the assets and liabilities of its Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses were translated at the average rates in effect for the period. The related translation gains and losses are included in accumulated other comprehensive income. Unrealized gains and losses on changes in fair value of common and preferred stock of publicly traded companies designated as available for sale securities, except those losses that are other-than-temporary and charged to earnings, are included in accumulated other comprehensive income. Upon the sale of available for sale securities, the related gain or loss in accumulated other comprehensive income is reclassified to “ Other income (expense) ” in the consolidated statements of operations.
Regulated Activities	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 ASC 980-605, Regulated Operations–Revenue Recognition , which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators.
Recently Issued Accounting Standards	Recently Issued Accounting Standards Accounting standards-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews all new pronouncements to determine their impact, if any, on its financial statements. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition , and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date , which defers the effective date of ASU 2014-09 for all entities by one year. As such, this amendment is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, and earlier application is permitted as of annual reporting periods beginning after December 14, 2016, including interim reporting periods within that reporting period. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern . This update requires an entity’s management to evaluate for each annual and interim reporting period whether there are adverse conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued. Examples of adverse conditions and events that may raise substantial doubt about an entity’s ability to continue as a going concern include, but are not limited to, negative financial trends (such as recurring operating losses, working capital deficiencies, or insufficient liquidity), a need to restructure outstanding debt to avoid default, and industry developments (such as declining commodity prices and regulatory changes).The update further requires certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, and requires an express statement and other disclosures when substantial doubt is not alleviated. This amendment is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company adopted this ASU during the period ended March 31, 2016. In April 2015, the FASB issued ASU 2015-03, Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs . This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this update. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. As of December 31, 2015, the Company had no remaining debt issuance costs on its consolidated balance sheet. In April 2015, the FASB issued ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Agreement . This update provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. This update does not change GAAP for a customer’s accounting for service contracts. This amendment is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted for all entities, either prospectively to all arrangements entered into or materially modified after the effective date, or retrospectively. The Company has several cloud computing arrangements and is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes , which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet. This amendment is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. The Company does not expect this ASU to have a material impact on its consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The core principle of Topic 842 is that a lessee should recognize the assets and liabilities that arise from leases. The ASU will require lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Under the new guidance, lessor accounting is largely unchanged. Certain targeted improvements were made to align, where necessary, lessor accounting with the lessee accounting model and Topic 606, Revenue from Contracts with Customers. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. The ASU is effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
Fair Value Measurement Policy	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: i. Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets; ii. 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; iii. Level 3 — Significant inputs to the valuation model are unobservable.

VOLUNTARY REORGANIZATION UNDE33

VOLUNTARY REORGANIZATION UNDER CHAPTER 11 (Tables)	12 Months Ended
	Dec. 31, 2015
Reorganizations [Abstract]
Schedule Of Liabilities Subject To Compromise	Liabilities subject to compromise consist of the following: December 31, 2015 (in thousands) Debt Senior Notes $ 599,305 Second Lien Term Loan 335,853 Other notes payable 1,800 Total debt 936,958 Accounts payable 78,536 Accounts payable to related parties 16,513 Dividends payable 7,275 Accrued liabilities 48,364 Revenue payable 5,198 Other liabilities 3,227 Total liabilities subject to compromise $ 1,096,071
Schedule Of Reorganization Items	Reorganization items consist of the following for the year ended December 31, 2015: December 31, 2015 (in thousands) Professional fees $ 4,118 Debt issuance costs 9,036 Loss on adjustments to carrying value of Senior Notes 12,533 Loss on adjustments to carrying value of Second Lien Term Loan 15,452 Total reorganization items $ 41,139
Condensed Combined Financial Statements Of Debtors	Condensed combined financial statements of the Debtors are set forth below. These condensed combined financial statements exclude the financial statements of the Non-Debtors, but include the Company’s equity method investment in Eureka Midstream Holdings. Transactions and balances of receivables and payables between Debtors are eliminated in consolidation. However, the Debtors’ condensed combined balance sheet includes receivables from related Non-Debtors and payables to related Non-Debtors. Condensed Combined Balance Sheet For the Year Ended December 31, 2015 (in thousands) ASSETS Current assets $ 83,371 Intercompany accounts receivable 137 Property and equipment (using successful efforts accounting) 766,843 Investment in subsidiaries 1,214 Investment in affiliate, equity-method 166,099 Other assets 41,973 Total Assets $ 1,059,637 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities $ 145,860 Liabilities subject to compromise 1,096,071 Long-term liabilities 30,670 Redeemable preferred stock 100,000 Shareholders' equity (deficit) (312,964 ) Total Liabilities and Shareholders' Equity $ 1,059,637 Condensed Statement of Operations For the Year Ended December 31, 2015 (in thousands) Revenues $ 153,087 Operating expenses 614,383 Operating loss (461,296 ) Other Income (Expense) Interest income 157 Interest expense (99,559 ) Gain (loss) on derivative contracts, net 4,886 Loss from equity method investments (181,556 ) Reorganization items (41,139 ) Other income (expense) (5,568 ) Total other expense (322,779 ) Net loss (784,075 ) Dividends on preferred stock (33,817 ) Net loss attributable to common shareholders $ (817,892 ) Condensed Combined Statement of Comprehensive Income (Loss) For the Year Ended December 31, 2015 (in thousands) Net loss $ (784,075 ) Other comprehensive income (loss) Foreign currency translation loss 99 Unrealized gain (loss) on available for sale securities (2,771 ) Amounts reclassified for other than temporary impairment of available for sale securities 10,183 Amounts reclassified for available for sale securities (19 ) Total other comprehensive income (loss) 7,492 Comprehensive loss $ (776,583 ) Condensed Combined Statement of Cash Flows For the Year Ended December 31, 2015 (in thousands) Cash flow from operating activities $ 24,915 Cash flow from investing activities (165,941 ) Cash flow from financing activities 128,634 Effect of exchange rate changes on cash (28 ) Net increase (decrease) in cash (12,420 ) Cash at beginning of period 53,187 Cash at end of period $ 40,767

EUREKA HUNTER HOLDINGS (Tables)

EUREKA HUNTER HOLDINGS (Tables)	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interest [Abstract]
Deconsolidation of subsidiary, allocation of basis difference	The Company initially recognized a basis difference of $201.9 million upon deconsolidation related to its investment in Eureka Midstream Holdings which has been allocated to the following identifiable assets of Eureka Midstream Holdings: Identifiable Assets Ending Basis December 31, 2014 Basis Amortization Basis Reduction Ending Basis December 31, 2015 (in thousands) Fixed assets $ 5,088 $ (208 ) $ (4,785 ) $ 95 Intangible assets 155,189 (6,057 ) (146,252 ) 2,880 Goodwill 41,597 — (40,750 ) 847 Total basis difference $ 201,874 $ (6,265 ) $ (191,787 ) $ 3,822
Deconsolidation Of Subsidiary Assets And Liabilities	Summarized balance sheet information for Eureka Midstream Holdings as of December 31, 2015 and 2014 is as follows: December 31, 2015 December 31, 2014 (in thousands) Current assets $ 86,910 $ 17,113 Non-current assets $ 507,201 $ 445,450 Current liabilities $ 20,683 $ 63,313 Non-current liabilities $ 182,561 $ 100,037
Deconsolidation Of Subsidiary Results Of Operations And Stockholders Equity	Summarized income information for Eureka Midstream Holdings for the year ended December 31, 2015 and the period from December 18, 2014 through December 31, 2014 is as follows: Year Ended December 31, 2015 Fourteen Days Ended December 31, 2014 (in thousands) Operating revenues $ 77,022 $ 2,124 Operating income $ 23,250 $ 74 Net income (loss) $ 18,979 $ (207 ) Magnum Hunter’s interest in Eureka Midstream Holdings net income (loss) $ 8,490 $ (101 ) Basis difference amortization (6,265 ) — Loss on downward adjustment of units (7,664 ) — Impairment upon reclassification from discontinued operations to continuing operations (180,254 ) — Magnum Hunter’s equity in earnings (loss), net $ (185,693 ) $ (101 )

ACQUISITIONS, DIVESTITURES, A35

ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures	The Company included the results of operations of WHI Canada, which has historically been the only member of the Company’s Canadian Upstream segment, through May 12, 2014, and Eagle Ford Hunter, which has historically been included as part of the U.S. Upstream segment, through April 24, 2013 in discontinued operations as follows: Year Ended December 31, 2014 2013 (in thousands) Revenues $ 8,533 $ 67,490 Expenses (1) (3,975 ) (130,331 ) Other income (expense) 3 186 Income (loss) from discontinued operations before tax 4,561 (62,655 ) Income tax benefit (expense) (2) — 94 Income (loss) from discontinued operations, net of tax 4,561 (62,561 ) Gain (loss) on disposal of discontinued operations, net of taxes (3)(4) (13,855 ) 71,510 Income (loss) from discontinued operations, net of tax $ (9,294 ) $ 8,949 _____________________ (1) Includes impairment expense of $65.4 million for the year ended December 31, 2013 and exploration expense of $0.1 million and $19.9 million for the years ended December 31, 2014 and 2013, respectively, relating to the discontinued operations of WHI Canada, which is recorded in income (loss) from discontinued operations. (2) The Company’s 2013 effective tax rate on the loss from discontinued operations is 0.2% primarily due to the significant losses generated in WHI Canada, which has an overall lower statutory tax rate further lowered by the utilization of certain net operating losses. (3) Income tax expense associated with gain/(loss) on sale of discontinued operations was none and $11.9 million for the years ended December 31, 2014 and 2013, respectively. (4) The Company’s 2013 effective tax rate on the gain on disposal of discontinued operations is 14.23% primarily due to the anticipated utilization of a capital loss on the sale of WHI Canada against the capital gains included in discontinued operations.

OIL & NATURAL GAS SALES (Tables

OIL & NATURAL GAS SALES (Tables)	12 Months Ended
	Dec. 31, 2015
Oil and Natural Gas Sales [Abstract]
Schedule of Oil Natural Gas and NGL Revenue	During the years ended December 31, 2015 , 2014 , and 2013 , the Company recognized sales from oil, natural gas, and natural gas liquids (“NGLs”) as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Oil $ 42,805 $ 131,109 $ 147,798 Natural gas 69,533 91,277 53,821 NGLs 21,110 46,115 19,080 Total oil and natural gas sales $ 133,448 $ 268,501 $ 220,699

PROPERTY, PLANT, & EQUIPMENT (T

PROPERTY, PLANT, & EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Schedule of Proved Property Impairments	During the years ended December 31, 2015 , 2014 and 2013 , the Company recorded proved property impairments as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Williston Basin $ 64,165 $ 261,270 $ 8,498 Appalachian Basin $ 207,340 6,001 1,151 Western Kentucky $ 3,783 33,811 40,043 South Texas $ 87 194 319 $ 275,375 $ 301,276 $ 50,011
Geological Geophysical Costs and Leasehold Abandonments Expense	The following table provides the Company’s exploration expense for 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in thousands) Geological and geophysical $ 2,317 $ 1,564 $ 1,402 Leasehold impairments: Williston Basin 45,811 103,147 89,167 Appalachian Basin 11,501 9,978 6,773 Western Kentucky 75 3,820 3,047 South Texas 127 — — $ 59,831 $ 118,509 $ 100,389
Oil and natural gas properties
Property, Plant and Equipment [Line Items]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	The following sets forth the net capitalized costs under the successful efforts method for oil and natural gas properties as of: December 31, 2015 2014 (in thousands) Mineral interests in properties: Unproved leasehold costs $ 398,302 $ 481,643 Proved leasehold costs 198,458 257,185 Wells and related equipment and facilities 469,578 560,060 Uncompleted wells, equipment and facilities — 46,346 Advances to operators for wells in progress 1,279 1,411 Total costs 1,067,617 1,346,645 Less accumulated depreciation, depletion, and amortization (369,347 ) (248,410 ) Net capitalized costs $ 698,270 $ 1,098,235
Gas Transportation Gathering Processing and Other Equipment
Property, Plant and Equipment [Line Items]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	The historical cost of gas transportation, gathering, and processing equipment and other property, presented on a gross basis with accumulated depreciation, as of December 31, 2015 and 2014 , is summarized as follows: December 31, 2015 2014 (in thousands) Gas transportation, gathering and processing equipment and other $ 100,916 $ 100,436 Less accumulated depreciation (30,648 ) (23,013 ) Net capitalized costs $ 70,268 $ 77,423

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of asset retirement obligation	The following table summarizes the changes in the Company’s ARO balances during the years ended December 31, 2015 and 2014 : December 31, 2015 2014 (in thousands) Asset retirement obligation at beginning of period $ 26,524 $ 16,216 Liabilities incurred 40 218 Liabilities settled (346 ) (107 ) Liabilities sold (254 ) (2,598 ) Accretion expense 2,597 1,478 Revisions in estimated liabilities 101 3,208 Reclassified from liabilities associated with assets held for sale — 8,109 Asset retirement obligation at end of period 28,662 26,524 Less: current portion (1,464 ) (295 ) Asset retirement obligation at end of period $ 27,198 $ 26,229

FAIR VALUE OF FINANCIAL INSTR39

FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value measurements on a recurring basis	The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2015 and 2014 : Fair Value Measurements on a Recurring Basis December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Available for sale securities $ 157 $ — $ — Total assets at fair value $ 157 $ — $ — Fair Value Measurements on a Recurring Basis December 31, 2014 (in thousands) 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
Schedule of reconciliation of derivative assets and liabilities measured at fair value using significant unobservable inputs	The following table presents the changes in the fair value of the derivative assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31, 2015 , 2014 and 2013 : Embedded Derivatives Series A Preferred Units Convertible Security (in thousands) Fair value at December 31, 2012 $ (43,548 ) $ 264 Issuance of embedded liability (14,645 ) — Change in fair value recognized in loss on derivative contracts, net (17,741 ) (185 ) Fair value at December 31, 2013 $ (75,934 ) $ 79 Issuance of redeemable preferred stock (5,479 ) — Change in fair value recognized in loss on derivative contracts, net (91,792 ) (4 ) Conversion of Eureka Midstream Holdings Series A Preferred Units to Series A-2 Units 173,205 — Fair value at December 31, 2014 $ — $ 75 Change in fair value recognized in loss on derivative contracts, net — (75 ) Fair value at December 31, 2015 $ — $ —
Carrying amounts and fair values of long-term debt	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: Fair Value December 31, 2015 December 31, 2014 Hierarchy Level Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value (in thousands) Senior Notes Level 2 $ 599,305 $ 161,520 $ 597,355 $ 498,000 Second Lien Term Loan Level 3 355,853 211,588 329,140 329,140 Equipment notes payable Level 3 15,482 15,482 22,238 22,150 Senior Secured Bridge Financing Facility Level 3 70,000 70,000 — — Debtor-in-Possession Credit Facility Level 3 40,000 40,000 — —
Fair value measurements on a non-recurring basis	Other fair value measurements made on a non-recurring basis during the years ended December 31, 2015 , 2014 , and 2013 consist of the following: Fair Value Measurements on a Non-recurring Basis (Level 1) (Level 2) (Level 3) (in thousands) Year ended December 31, 2015 Fair value of proved properties impaired $ — $ — $ 298,689 Fair value of interest in Eureka Midstream Holdings — — 163,362 Year ended December 31, 2014 Fair value of proved properties impaired $ — $ — $ 584,895 Fair value of long-lived assets of MHP — — 28,443 Fair value of retained interest in Eureka Midstream Holdings — — 347,291 Year ended December 31, 2013 Fair value of proved properties impaired $ — $ — $ 329,409 Fair value of acquisitions — — 87,149

INVESTMENTS AND DERIVATIVES (Ta

INVESTMENTS AND DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Investment	elow is a summary of changes in investments for the years ended December 31, 2015 , 2014 , and 2013 : Available for Sale Securities Equity Method Investments (in thousands) Carrying value at December 31, 2012 $ 1,958 $ 2,072 Securities received as consideration 42,300 — Sales of securities (50,562 ) — Realized gain recognized in net income 8,262 — Decrease in carrying amount return of capital — (138 ) Loss from equity method investment — (994 ) Other adjustments (55 ) — Change in fair value recognized in other comprehensive loss (84 ) — Carrying value at December 31, 2013 $ 1,819 $ 940 Securities received as consideration 9,446 — Fair value of retained interest in Eureka Midstream Holdings — 347,292 Loss from equity method investment — (1,038 ) Other adjustments — (3 ) Change in fair value recognized in other comprehensive loss (7,401 ) — Carrying value at December 31, 2014 $ 3,864 $ 347,191 Sales of securities (472 ) — Gain on dilution of interest in Eureka Midstream Holdings — 4,601 Loss from equity method investment (1) (464 ) (185,693 ) Other adjustments — — Change in fair value recognized in other comprehensive loss (2,771 ) — Carrying value at December 31, 2015 $ 157 $ 166,099 _________________ (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.
Schedule of investments by balance sheet grouping	The Company’s investments have been presented in the consolidated balance sheet as of December 31, 2015 and December 31, 2014 as follows: December 31, 2015 (in thousands) Available for Sale Securities Equity Method Investments Total Investments - Current $ 157 $ — $ 157 Investments - Non-current — 166,099 166,099 Carrying value as of December 31, 2015 $ 157 $ 166,099 $ 166,256 December 31, 2014 (in thousands) Available for Sale Securities Equity Method Investments Total Investments - Current $ 3,864 $ — $ 3,864 Investments - Non-current — 347,191 347,191 Carrying value as of December 31, 2014 $ 3,864 $ 347,191 $ 351,055
Schedule of carrying value and estimated fair value of equity securities	The cost for equity securities and their respective fair values as of December 31, 2015 and 2014 are as follows: December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (in thousands) Securities available for sale, carried at fair value: Equity securities $ 78 $ — $ (2 ) $ 76 Equity securities - related party (see “Note 17 - Related Party Transactions”) 465 — (384 ) 81 Total Securities available for sale $ 543 $ — $ (386 ) $ 157 December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value (in thousands) Securities available for sale, carried at fair value: Equity securities $ 9,876 $ — $ (7,323 ) $ 2,553 Equity securities - related party (see “Note 17 - Related Party Transactions”) 2,200 — (889 ) 1,311 Total Securities available for sale $ 12,076 $ — $ (8,212 ) $ 3,864
Schedule of fair value of derivative contracts	The following table summarizes the fair value of the Company’s derivative contracts as of December 31, 2014: Derivatives not designated as hedging instruments December 31, 2014 Commodity (in thousands) Derivative assets $ 16,511 Total commodity $ 16,511 Financial Derivative assets $ 75 Total financial $ 75 Total derivatives $ 16,586
Schedule of net gain (loss) on derivative contracts	The following table summarizes the net gain (loss) on all derivative contracts included in other income (expense) on the consolidated statements of operations for the years ended December 31, 2015 , 2014 and 2013 : For the Year Ended December 31, 2015 2014 2013 (in thousands) Gain (loss) on settled transactions $ 2,449 $ 1,306 $ (8,216 ) Gain (loss) on open contracts 2,437 18,232 (17,058 ) Loss on extinguished embedded derivative — (91,792 ) — Total gain (loss), net $ 4,886 $ (72,254 ) $ (25,274 )

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Details of notes payable	Notes payable at December 31, 2015 and 2014 consisted of the following: As of December 31, 2015 2014 (in thousands) MHR Senior Revolving Credit Facility $ — $ — Senior Secured Bridge Financing Facility, interest rate of 4.2% at December 31, 2015 70,000 — Debtor-in-Possession Credit Facility, interest rate of 9.00% at December 31, 2015 40,000 — Second Lien Term Loan due October 22, 2019, interest rate of 8.5%, net of unamortized discount of $10.0 million at December 31, 2014 335,853 329,140 Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.6 million at December 31, 2014 599,305 597,355 Various equipment and real estate notes payable with maturity dates April 2016 - November 2017, interest rates of 4.25% - 8.70% 15,482 22,238 $ 1,060,640 $ 948,733 Less: current portion (83,682 ) (10,770 ) Less: debtor-in-possession financing (40,000 ) — Less: liabilities subject to compromise (see “Note 3 - Voluntary Reorganization under Chapter 11”) (936,958 ) — Total long-term debt obligations not subject to compromise, net of current portion $ — $ 937,963
Summary of approximate annual maturities of debt	The following table presents the approximate annual maturities of debt: (in thousands) 2016 $ 1,060,640 2017 — 2018 — 2019 — 2020 — Thereafter — $ 1,060,640
Schedule of Interest Expense Incurred on Debt [Table Text Block]	The following table sets forth interest expense for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in thousands) Interest expense incurred on debt, net of amounts capitalized $ 91,032 $ 76,784 $ 67,803 Amortization and write-off of deferred financing costs 8,527 9,679 4,818 Total interest expense $ 99,559 $ 86,463 $ 72,621

SHARE-BASED COMPENSATION (Table

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of stock option and stock appreciation rights	A summary of stock option and stock appreciation rights activity for the years ended December 31, 2015 , 2014 , and 2013 is presented below: 2015 2014 2013 Weighted-Average Exercise Price Weighted-Average Exercise Price Weighted-Average Exercise Price Shares Shares Shares Outstanding at beginning of the year 13,194,956 $ 5.91 16,891,419 $ 5.69 14,846,994 $ 6.01 Granted — $ — — $ — 4,937,575 $ 4.11 Exercised (100,000 ) $ 0.51 (2,375,273 ) $ 4.09 (1,466,025 ) $ 3.66 Forfeited or expired (5,780,205 ) $ 6.24 (1,321,190 ) $ 6.27 (1,427,125 ) $ 5.51 Outstanding at end of the year 7,314,751 $ 5.75 13,194,956 $ 5.91 16,891,419 $ 5.69 Exercisable at end of the year 6,721,950 $ 5.89 9,140,323 $ 6.22 9,983,743 $ 5.96
Summary of non-vested options and stock appreciation rights	A summary of the Company’s non-vested common stock options and stock appreciation rights for the years ended December 31, 2015 , 2014 , and 2013 is presented below: Non-vested Options 2015 2014 2013 Non-vested at beginning of the year 4,054,633 6,907,476 6,163,372 Granted — — 4,937,575 Vested (1,635,365 ) (1,915,526 ) (3,133,700 ) Forfeited (1,826,467 ) (937,317 ) (1,059,771 ) Non-vested at end of the year 592,801 4,054,633 6,907,476
Assumptions used in fair value method calculation	The assumptions used in the fair value method calculations for the year ended December 31, 2013 are disclosed in the following table: Year Ended December 31, 2013 Weighted average fair value per option granted during the period (1) $2.52 Assumptions (2) : Weighted average stock price volatility (3) 80.61% Weighted average risk free rate of return 0.78% Weighted average estimated forfeiture rate 2.45% Weighted average expected term 4.65 years ________________________________ (1) Calculated using the Black-Scholes fair value based method for service and performance based grants and the Lattice Model for market based grants. (2) The Company has not paid cash dividends on its common stock. (3) The volatility assumption was estimated based upon a blended calculation of historical volatility and implied volatility over the life of the awards.
Summary of non-vested shares	A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2015 , 2014 , and 2013 is presented below: 2015 2014 2013 Weighted-Average Share Price Weighted-Average Share Price Weighted-Average Share Price Non-vested Shares Shares Shares Shares Non-vested at beginning of the year 2,352,013 $ 5.99 27,500 $ 7.24 65,025 $ 6.09 Granted 3,468,833 $ 1.24 3,239,796 $ 5.66 210,494 $ 4.66 Forfeited (847,514 ) $ 5.92 (135,000 ) $ 7.26 — $ — Vested (1,583,436 ) $ 4.51 (780,283 ) $ 4.48 (248,019 ) $ 4.75 Non-vested at end of the year 3,389,896 $ 2.92 2,352,013 $ 5.99 27,500 $ 7.24

SHAREHOLDERS' EQUITY (Tables)

SHAREHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Summary of warrant activity	A summary of warrant activity for the years ended December 31, 2015 , 2014 , and 2013 is presented below: 2015 2014 2013 Weighted - Weighted - Weighted - Average Average Average Shares Exercise Price Shares Exercise Price Shares Exercise Price Outstanding at beginning of year 19,173,480 $ 8.50 17,169,010 $ 8.56 13,376,277 $ 10.56 Granted — $ — 2,142,858 $ 8.50 17,030,622 $ 8.50 Exercised, forfeited, or expired — $ — (138,388 ) $ 16.28 (13,237,889 ) $ 10.50 Outstanding at end of year 19,173,480 $ 8.50 19,173,480 $ 8.50 17,169,010 $ 8.56 Exercisable at end of year 2,142,858 $ 8.50 2,142,858 $ 8.50 138,388 $ 16.28
Summary of dividends paid	A summary of dividends incurred by the Company for the years ended December 31, 2015 , 2014 , and 2013 is presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Dividend on Eureka Midstream Holdings Series A Preferred Units $ — $ 12,760 $ 14,323 Eureka MidstreamAccretion of the carrying value of the Eureka Midstream Holdings Series A Preferred Units — 6,583 6,918 Dividend on Series C Preferred Stock 9,792 10,248 10,248 Dividend on Series D Preferred Stock 16,911 17,698 17,655 Dividend on Series E Preferred Stock 7,114 7,418 7,561 Total dividends on Preferred Stock $ 33,817 $ 54,707 $ 56,705
Schedule of antidilutive securities excluded from computation of earnings per share	The following table summarizes the types of potentially dilutive securities outstanding as of December 31, 2015 , 2014 and 2013 : December 31, 2015 2014 2013 (in thousands of shares) Series E Preferred Stock 11,126 10,946 10,946 Warrants 19,173 19,173 17,169 Restricted shares granted, not yet issued 3,643 2,369 28 Common stock options 7,315 13,195 16,891 Total 41,257 45,683 45,034

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Provision for income taxes	The total provision for income taxes applicable to continuing operations consists of the following: Year Ended December 31, 2015 2014 2013 (in thousands) Deferred income tax benefit Federal $ — $ — $ (78,743 ) State — — (6,664 ) Total deferred tax benefit $ — $ — $ (85,407 ) Total income tax benefit $ — $ — $ (85,407 )
Reconciliation of the reported amount of income tax expense (benefit) to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income	The following is a reconciliation of the reported amount of income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2015 , 2014 , and 2013 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income: Year Ended December 31, 2015 2014 2013 (in thousands) Income tax benefit at statutory U.S. rate $ (274,355 ) $ (48,242 ) $ (111,132 ) State income taxes (net of federal benefit) (28,930 ) (3,616 ) (4,331 ) Tax effect of permanent differences 224 (498 ) 750 Provision to return adjustment — (11,736 ) — Foreign statutory tax rate differences (9 ) 297 — Tax effect of loss attributable to non-controlled interest — 1,279 346 Tax benefit recognized as tax expense in discontinued operations — — (28,989 ) Change in valuation allowance 302,373 63,341 58,341 Other 697 (825 ) (392 ) Total continuing operations — — (85,407 ) Discontinued operations — — 11,773 Total tax benefit $ — $ — $ (73,634 )
Schedule of income before income tax, domestic and foreign	Income (loss) before income taxes was as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Domestic $ (783,963 ) $ (134,853 ) $ (317,520 ) Foreign 91 (2,980 ) — Loss from continuing operations (783,872 ) (137,833 ) (317,520 ) Gain (loss) from discontinued operations — 4,561 (62,655 ) Gain (loss) on disposal of discontinued operations — (13,855 ) 83,378 Loss before income tax $ (783,872 ) $ (147,127 ) $ (296,797 )
Components of deferred income taxes	The tax effects of temporary differences that gave rise to the Company’s deferred tax assets and liabilities are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Deferred tax assets: Net operating loss carry forwards $ 371,531 $ 263,452 $ 155,507 Property and equipment 162,236 63,823 — Capital loss carry forward 76,955 38,401 — Share-based compensation 17,293 15,035 10,156 Depletion carry forwards 1,047 1,047 1,047 Tax credits 53 53 53 US investment in Canada — — 74,148 Other 15,354 1,562 561 Deferred tax liabilities: Property and equipment — — (90,950 ) Investment in Eureka Midstream Holdings (135,331 ) (176,606 ) — Valuation allowance Tax credits (53 ) (53 ) (53 ) Depletion carry forwards (1,047 ) (1,047 ) (1,047 ) Capital loss carry forward (76,955 ) (38,401 ) — Net operating losses (371,531 ) (263,452 ) (155,507 ) Other (59,552 ) 96,186 80,233 US investment in Canada — — (74,148 ) Net deferred tax asset (liability) $ — $ — $ —
Reconciliation of unrecognized tax benefits	Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in thousands) Unrecognized tax benefits at January 1 $ 3,879 $ 3,879 $ 3,879 Change in unrecognized tax benefits taken during a prior period — — — Change in unrecognized tax benefits taken during the current period (netted against the US net operating loss) — — — Decreases in unrecognized tax benefits from settlements with taxing authorities — — — Reductions to unrecognized tax benefits from lapse of statutes of limitations — — — Unrecognized tax benefits at December 31 $ 3,879 $ 3,879 $ 3,879

MAJOR CUSTOMERS (Tables)

MAJOR CUSTOMERS (Tables)	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Schedule of percentages of the consolidated oil, NGL and gas revenues represented by major purchasers	The table below provides the percentages of the Company’s consolidated oil, NGLs and gas revenues from continuing operations represented by its major purchasers during the periods presented: Year Ended December 31, 2015 2014 2013 Samson Resources Company (1) 22 % 24 % 31 % Markwest Liberty Midstream 14 % 15 % 6 % Tenaska Marketing Ventures 11 % 17 % 10 % Baytex Energy USA LTD — % 7 % 11 % _________________ (1) See “ Note 18 - Commitments and Contingencies - Samson Matter”

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Balances	The following table sets forth the related party balances as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in thousands) GreenHunter (1) Accounts receivable, net of reserve $ — $ 21 Accounts payable $ (24 ) $ (249 ) Liabilities subject to compromise $ (635 ) $ — Derivative assets (2) $ — $ 75 Investments (2) $ 81 $ 1,311 Notes receivable, net of reserve (2) $ — $ 1,224 Prepaid expenses $ 5 $ 1,000 Eureka Midstream Holdings (3) Accounts receivable $ 5,467 $ 2,898 Accounts payable $ (1,480 ) $ (2,776 ) Liabilities subject to compromise $ (15,827 ) $ — Equity method investment $ 166,099 $ 347,191 Pilatus Hunter (4) Accounts receivable $ 12 $ 12 Classic Petroleum, Inc. (5) Liabilities subject to compromise $ (51 ) $ —
Schedule of Related Party Transactions	The following table sets forth the related party balances as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in thousands) GreenHunter (1) Accounts receivable, net of reserve $ — $ 21 Accounts payable $ (24 ) $ (249 ) Liabilities subject to compromise $ (635 ) $ — Derivative assets (2) $ — $ 75 Investments (2) $ 81 $ 1,311 Notes receivable, net of reserve (2) $ — $ 1,224 Prepaid expenses $ 5 $ 1,000 Eureka Midstream Holdings (3) Accounts receivable $ 5,467 $ 2,898 Accounts payable $ (1,480 ) $ (2,776 ) Liabilities subject to compromise $ (15,827 ) $ — Equity method investment $ 166,099 $ 347,191 Pilatus Hunter (4) Accounts receivable $ 12 $ 12 Classic Petroleum, Inc. (5) Liabilities subject to compromise $ (51 ) $ — The following table sets forth the related party transaction activities for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in thousands) GreenHunter Production costs (1) $ 3,675 $ 4,973 $ 3,315 Midstream natural gas gathering, processing, and marketing (1) $ — $ 652 $ — Oilfield services (1) $ 298 $ — $ — General and administrative (1) $ 23 $ 44 $ 13 Interest income (2) $ 113 $ 154 $ 205 Miscellaneous income (expense) (2) $ (620 ) $ 220 $ 220 Loss from equity method investment (2) $ 464 $ 590 $ 730 Capitalized costs incurred (1) $ 508 $ 3,149 $ — Pilatus Hunter, LLC (4) General and administrative $ 143 $ 281 $ 166 Eureka Midstream Holdings (3) Oil and natural gas sales $ 347 $ — $ — Production costs $ 1,181 $ — $ — Transportation, processing, and other related costs $ 24,865 $ 353 $ — Oilfield services $ 34 $ — $ — General and administrative $ 8 $ 32,569 $ — Gain on deconsolidation of Eureka Midstream Holdings, LLC $ — $ 509,563 $ — Gain on dilution of interest in Eureka Midstream Holdings, LLC $ 4,601 $ — $ — Loss from equity method investment $ 185,693 $ 448 $ — Loss on extinguishment of Eureka Midstream Holdings Series A Preferred Units $ — $ 51,692 $ — Capitalized costs incurred $ 121 $ — $ — Classic Petroleum (5) Capitalized costs incurred $ 206 $ 1,495 $ — Kirk Trosclair Enterprises, LLC (6) General and administrative $ 169 $ — $ — _________________________________ (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 VIRCO, wholly owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and certain affiliated companies. The Company had approximately $66,000 of accounts receivable from GreenHunter which was fully reserved as of December 31, 2015. (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 9 - Fair Value of Financial Instruments”. 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. Miscellaneous income (expense) includes other than temporary impairment loss on the GreenHunter available for sale security of $0.8 million for the year ended December 31, 2015. See “Note 10 - Investments and Derivatives” for additional information. (3) Following a sequence of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Midstream Holdings. The Company deconsolidated Eureka Midstream Holdings and accounts for its retained interest as of December 31, 2015 and 2014 under the equity method of accounting. See “Note 4 - Eureka Midstream Holdings” and “Note 10 - 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 former Executive Vice President and President of the Company’s Appalachian Division. Triad Hunter received land brokerage services from Classic Petroleum, Inc., including courthouse abstracting, contract negotiations, GIS mapping and leasing services. (6) On July 18, 2014, the Company entered into a consulting agreement with Kirk J. Trosclair, a former executive of Alpha Hunter Drilling, 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 year ended December 31, 2015, the Company paid Mr. Trosclair $169,000 , which includes reimbursement of expenses incurred on behalf of the Company, and recognized $163,423 in stock compensation expense.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of future minimum lease commitments under noncancellable operating leases	Future minimum lease commitments under non-cancelable operating leases at December 31, 2015 , are as follows (in thousands): 2016 $ 605 2017 $ 488 2018 $ 154 2019 $ 53 2020 $ — Thereafter $ —
Schedule of future minimum gathering, processing, and transportation commitments	Future minimum gathering, processing, and transportation commitments at December 31, 2015 , are as follows (in thousands): 2016 $ 22,562 2017 $ 22,517 2018 $ 22,517 2019 $ 22,517 2020 $ 22,517 Thereafter $ 123,943

SUPPLEMENTAL CASH FLOW INFORM48

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing transactions: Year Ended December 31, 2015 2014 2013 (in thousands) Cash paid for interest $ 55,531 $ 73,192 $ 67,736 Cash paid for taxes $ — $ — $ 1,200 Non-cash transactions Change in accrued capital expenditures - increase (decrease) $ (100,774 ) $ 127,068 $ (65,634 ) Reclassification of deposit from field equipment to other assets $ 2,125 $ — $ — Eureka Midstream Holdings, LLC Series A convertible preferred unit dividends paid in kind $ — $ 1,950 $ 8,243 Non-cash additions to asset retirement obligation $ 141 $ 3,426 $ 2,132 Common stock issued for 401k matching contributions $ 1,878 $ 1,593 $ 1,192 Non-cash consideration received from sale of assets $ — $ 9,447 $ 42,300 Loss on extinguishment of Eureka Midstream Holdings Series A Preferred Units $ — $ (51,692 ) $ —

SEGMENT REPORTING (Tables)

SEGMENT REPORTING (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Details of operating activities by segment	The following tables set forth operating activities and capital expenditures by segment for the years ended, and segment assets as of December 31, 2015 , 2014 , and 2013 . For the Year Ended December 31, 2015 Upstream Midstream (1) Oilfield Services Corporate Unallocated Intersegment Eliminations Total (in thousands) Total revenue $ 134,812 $ 867 $ 18,973 $ — $ (528 ) $ 154,124 Depreciation, depletion, and amortization 128,973 — 3,926 — (95 ) 132,804 (Gain) loss on sale of assets (31,409 ) — 51 — — (31,358 ) Other operating expenses 454,984 736 19,637 38,794 (387 ) 513,764 Other income (expense) (10,091 ) (181,092 ) (577 ) (89,887 ) — (281,647 ) Reorganization items, net — — — (41,139 ) — (41,139 ) Net income (loss) $ (427,827 ) $ (180,961 ) $ (5,218 ) $ (169,820 ) $ (46 ) $ (783,872 ) Total assets $ 756,265 $ 166,107 $ 37,787 $ 100,040 $ (41 ) $ 1,060,158 Total capital expenditures $ 63,981 $ — $ 650 $ 2,247 $ — $ 66,878 For the Year Ended December 31, 2014 Upstream Midstream (1) Oilfield Services Corporate Unallocated (1) Intersegment Eliminations Total (in thousands) Total revenue $ 270,615 $ 109,658 $ 31,392 $ — $ (20,196 ) $ 391,469 Depreciation, depletion, and amortization 127,607 15,737 3,524 — — 146,868 Gain on sale of assets (2,075 ) (12 ) (369 ) — — (2,456 ) Other operating expenses 556,085 93,138 26,642 81,746 (20,196 ) 737,415 Other income (expense) 1,340 (99,221 ) (813 ) 454,921 (3,702 ) 352,525 Income (loss) from continuing operations before income tax (409,662 ) (98,426 ) 782 373,175 (3,702 ) (137,833 ) Income (loss) from discontinued operations, net of tax 3,481 — — (12,775 ) — (9,294 ) Net income (loss) $ (406,181 ) $ (98,426 ) $ 782 $ 360,400 $ (3,702 ) $ (147,127 ) Total assets $ 1,168,829 $ 347,645 $ 47,009 $ 116,849 $ (2,377 ) $ 1,677,955 Total capital expenditures $ 470,843 $ 221,455 $ 8,079 $ 231 $ — $ 700,608 For the Year Ended December 31, 2013 Upstream Midstream (1) Oilfield Services Corporate Unallocated Intersegment Eliminations Total (in thousands) Total revenue $ 225,498 $ 69,306 $ 21,527 $ — $ (11,793 ) $ 304,538 Depreciation, depletion, and amortization 92,713 12,318 2,354 — — 107,385 Loss on sale of assets 44,629 8 4 — — 44,641 Other operating expenses 267,935 60,497 19,252 49,241 (9,620 ) 387,305 Other income (expense) (656 ) (22,358 ) (507 ) (61,446 ) 2,240 (82,727 ) Income (loss) from continuing operations before income tax (180,435 ) (25,875 ) (590 ) (110,687 ) 67 (317,520 ) Income tax benefit 56,418 — — 28,989 — 85,407 Total income (loss) from discontinued operations, net of tax 9,018 — — — (69 ) 8,949 Net income (loss) $ (114,999 ) $ (25,875 ) $ (590 ) $ (81,698 ) $ (2 ) $ (223,164 ) Total assets $ 1,441,408 $ 296,739 $ 44,193 $ 77,684 $ (3,373 ) $ 1,856,651 Total capital expenditures $ 459,737 $ 87,498 $ 22,440 $ 1,037 $ — $ 570,712 ______________ (1) For the years ended December 31, 2014 and 2013, the Midstream segment includes operations of Eureka Midstream Holdings, which represents approximately 38.6% and 40.7% of Midstream revenues for the years ended December 31, 2014 and 2013, respectively, and which was deconsolidated as of December 18, 2014. See “Note 4 - Eureka Midstream Holdings”. For the year ended December 31, 2015, other expense of the Midstream segment represents loss from the Company’s equity method investment in Eureka Midstream Holdings.

CONDENSED CONSOLIDATED GUARAN50

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Schedule of condensed consolidating balance sheets	Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Balance Sheets (in thousands) As of December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter ASSETS Current assets $ 52,010 $ 31,359 $ 177 $ 2 $ 83,548 Intercompany accounts receivable 1,159,346 — — (1,159,346 ) — Property and equipment (using successful efforts accounting) 6,221 762,361 — (44 ) 768,538 Investment in subsidiaries (516,241 ) 91,759 — 424,482 — Investment in affiliate, equity-method 166,099 — — — 166,099 Other assets 41,809 164 — — 41,973 Total Assets $ 909,244 $ 885,643 $ 177 $ (734,906 ) $ 1,060,158 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities $ 127,469 $ 18,390 $ 39 $ 2 $ 145,900 Intercompany accounts payable — 1,120,148 41,434 (1,161,582 ) — Liabilities subject to compromise 994,120 101,951 — — 1,096,071 Long-term liabilities 139 30,532 — — 30,671 Redeemable preferred stock 100,000 — — — 100,000 Shareholders' equity (deficit) (312,484 ) (385,378 ) (41,296 ) 426,674 (312,484 ) Total Liabilities and Shareholders' Equity $ 909,244 $ 885,643 $ 177 $ (734,906 ) $ 1,060,158 Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Balance Sheets (in thousands) As of December 31, 2014 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter ASSETS Current assets $ 88,542 $ 41,569 $ 589 $ (2,378 ) $ 128,322 Intercompany accounts receivable 1,113,417 — — (1,113,417 ) — Property and equipment (using successful efforts 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 $ 1,485,865 $ 1,309,805 $ 619 $ (1,118,334 ) $ 1,677,955 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities $ 28,242 $ 148,145 $ 2,567 $ (2,383 ) $ 176,571 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 $ 1,485,865 $ 1,309,805 $ 619 $ (1,118,334 ) $ 1,677,955
Schedule of condensed consolidating statements of operations	Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Operations (in thousands) For the Year Ended December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Revenues $ 16 $ 155,270 $ 1,036 $ (2,198 ) $ 154,124 Expenses 351,749 587,612 789 (2,154 ) 937,996 Income (loss) from continuing operations before equity in net income of subsidiaries (351,733 ) (432,342 ) 247 (44 ) (783,872 ) Equity in net income of subsidiaries (432,139 ) (2,374 ) — 434,513 — Income (loss) from continuing operations before income tax (783,872 ) (434,716 ) 247 434,469 (783,872 ) Income tax benefit — — — — — Net income (loss) (783,872 ) (434,716 ) 247 434,469 (783,872 ) Dividends on preferred stock (33,817 ) — — — (33,817 ) Net income (loss) attributable to common shareholders $ (817,689 ) $ (434,716 ) $ 247 $ 434,469 $ (817,689 ) For the Year Ended December 31, 2014 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Revenues $ 142 $ 368,537 $ 43,611 $ (20,821 ) $ 391,469 Expenses (370,646 ) 772,355 144,714 (17,121 ) 529,302 Income (loss) from continuing operations before equity in net income of subsidiaries 370,788 (403,818 ) (101,103 ) (3,700 ) (137,833 ) Equity in net income of subsidiaries (513,580 ) (8,181 ) — 521,761 — Income (loss) from continuing operations before income tax (142,792 ) (411,999 ) (101,103 ) 518,061 (137,833 ) Income tax benefit — — — — — Income (loss) from continuing operations (142,792 ) (411,999 ) (101,103 ) 518,061 (137,833 ) Income from discontinued operations, net of tax — — 4,561 — 4,561 Gain (loss) on disposal of discontinued operations, net of tax (20,027 ) 97 6,075 — (13,855 ) Net income (loss) (162,819 ) (411,902 ) (90,467 ) 518,061 (147,127 ) Net income attributable to non-controlling interest — — — 3,653 3,653 Net income (loss) attributable to Magnum Hunter Resources Corporation (162,819 ) (411,902 ) (90,467 ) 521,714 (143,474 ) Dividends on preferred stock (35,364 ) — (19,343 ) — (54,707 ) Loss on extinguishment of Eureka Midstream Holdings (51,692 ) — — — (51,692 ) Net income (loss) attributable to common shareholders $ (249,875 ) $ (411,902 ) $ (109,810 ) $ 521,714 $ (249,873 ) Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Operations (in thousands) For the Year Ended December 31, 2013 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Revenues $ 2,629 $ 277,854 $ 35,848 $ (11,793 ) $ 304,538 Expenses 112,754 461,173 59,991 (11,860 ) 622,058 Income (loss) from continuing operations before equity in net income of subsidiaries (110,125 ) (183,319 ) (24,143 ) 67 (317,520 ) Equity in net income of subsidiaries (298,775 ) (424 ) — 299,199 — Income (loss) from continuing operations before income tax (408,900 ) (183,743 ) (24,143 ) 299,266 (317,520 ) Income tax benefit (expense) 28,989 56,422 (4 ) — 85,407 Income (loss) from continuing operations (379,911 ) (127,321 ) (24,147 ) 299,266 (232,113 ) Income (loss) from discontinued operations, net of tax (7,813 ) 22,661 (77,340 ) (69 ) (62,561 ) Gain (loss) on disposal of discontinued operations, net of tax 144,378 — (72,868 ) — 71,510 Net income (loss) (243,346 ) (104,660 ) (174,355 ) 299,197 (223,164 ) Net income attributable to non-controlling interest — — — 988 988 Net income (loss) attributable to Magnum Hunter Resources Corporation (243,346 ) (104,660 ) (174,355 ) 300,185 (222,176 ) Dividends on preferred stock (35,464 ) — (21,241 ) — (56,705 ) Net income (loss) attributable to common shareholders $ (278,810 ) $ (104,660 ) $ (195,596 ) $ 300,185 $ (278,881 )
Schedule of condensed consolidating statements of comprehensive income (loss)	Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Comprehensive Income (Loss) (in thousands) For the Year Ended December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Net income (loss) $ (783,872 ) $ (434,716 ) $ 247 $ 434,469 $ (783,872 ) Foreign currency translation gain — 99 — — 99 Unrealized loss on available for sale securities — (2,771 ) — — (2,771 ) Amounts reclassified for other than temporary impairment of available for sale securities — 10,183 — — 10,183 Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities — (19 ) — — (19 ) Comprehensive income (loss) $ (783,872 ) $ (427,224 ) $ 247 $ 434,469 $ (776,380 ) For the Year Ended December 31, 2014 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Net income (loss) $ (162,819 ) $ (411,902 ) $ (90,467 ) $ 518,061 $ (147,127 ) Foreign currency translation loss — — (1,204 ) — (1,204 ) Unrealized loss on available for sale securities — (7,401 ) — — (7,401 ) Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc. 20,741 — — — 20,741 Comprehensive income (loss) (142,078 ) (419,303 ) (91,671 ) 518,061 (134,991 ) Comprehensive (income) loss attributable to non-controlling interest — — — 3,653 3,653 Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation $ (142,078 ) $ (419,303 ) $ (91,671 ) $ 521,714 $ (131,338 ) For the Year Ended December 31, 2013 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Net income (loss) $ (243,346 ) $ (104,660 ) $ (174,355 ) $ 299,197 $ (223,164 ) Foreign currency translation loss — — (10,928 ) — (10,928 ) Unrealized gain (loss) on available for sale securities 8,262 (84 ) — — 8,178 Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities (8,262 ) — — — (8,262 ) Comprehensive income (loss) (243,346 ) (104,744 ) (185,283 ) 299,197 (234,176 ) Comprehensive (income) loss attributable to non-controlling interest — — — 988 988 Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation $ (243,346 ) $ (104,744 ) $ (185,283 ) $ 300,185 $ (233,188 )
Schedule of condensed consolidating statements of cash flows	Magnum Hunter Resources Corporation and Subsidiaries (Debtor-in-Possession) Condensed Consolidating Statements of Cash Flows (in thousands) For the Year Ended December 31, 2015 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Cash flow from operating activities $ (113,263 ) $ 138,429 $ — $ (140 ) $ 25,026 Cash flow from investing activities (43,305 ) (122,776 ) — 140 (165,941 ) Cash flow from financing activities 134,733 (6,099 ) — — 128,634 Effect of exchange rate changes on cash — (28 ) — — (28 ) Net increase (decrease) in cash (21,835 ) 9,526 — — (12,309 ) Cash at beginning of period 64,165 (10,985 ) — — 53,180 Cash at end of period $ 42,330 $ (1,459 ) $ — $ — $ 40,871 For the Year Ended December 31, 2014 Magnum Hunter Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Cash flow from operating activities $ (347,898 ) $ 255,088 $ 74,145 $ — $ (18,665 ) Cash flow from investing activities 107,595 (248,928 ) (176,786 ) — (318,119 ) Cash flow from financing activities 250,194 301 97,700 — 348,195 Effect of exchange rate changes on cash — — 56 — 56 Net increase (decrease) in cash 9,891 6,461 (4,885 ) — 11,467 Cash at beginning of period 47,895 (17,651 ) 11,469 — 41,713 Cash at end of period $ 57,786 $ (11,190 ) $ 6,584 $ — $ 53,180 For the Year Ended December 31, 2013 Magnum Hunter 100% Owned Guarantor Non-Guarantor Consolidating / Eliminating Adjustments Magnum Hunter Cash flow from operating activities $ (371,351 ) $ 397,213 $ 99,153 $ (13,304 ) $ 111,711 Cash flow from investing activities 422,303 (411,473 ) (138,690 ) — (127,860 ) Cash flow from financing activities (29,929 ) 796 16,485 13,304 656 Effect of exchange rate changes on cash — — (417 ) — (417 ) Net increase (decrease) in cash 21,023 (13,464 ) (23,469 ) — (15,910 ) Cash at beginning of period 26,872 (4,187 ) 34,938 — 57,623 Cash at end of period $ 47,895 $ (17,651 ) $ 11,469 $ — $ 41,713

OTHER INFORMATION (Tables)

OTHER INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
Other Information
Details of unaudited summary financial results	The following tables set forth unaudited summary financial results on a quarterly basis for the most recent two years. Quarter Ended March 31, June 30, September 30, December 31, Year Ended 2015 (in thousands) Total revenue (1) $ 55,396 $ 39,526 $ 33,664 $ 25,538 $ 154,124 Operating income (loss) (2) $ (77,488 ) $ 4,529 $ (84,652 ) $ (303,475 ) $ (461,086 ) Net loss attributable to Magnum Hunter Resources Corporation (3) $ (105,919 ) $ (21,676 ) $ (113,181 ) $ (543,096 ) $ (783,872 ) Net loss attributable to common shareholders $ (114,767 ) $ (30,523 ) $ (122,029 ) $ (550,370 ) $ (817,689 ) Basic and diluted loss per common share $ (0.57 ) $ (0.15 ) $ (0.53 ) $ (2.11 ) $ (3.63 ) 2014 Total revenue (4) $ 113,482 $ 138,463 $ 79,670 $ 59,854 $ 391,469 Operating income (loss) (5) $ (32,762 ) $ 1,555 $ (57,576 ) $ (401,575 ) $ (490,358 ) Income (loss) from continuing operations (6) $ (56,557 ) $ (61,407 ) $ (123,189 ) $ 103,320 $ (137,833 ) Income from discontinued operations, net of tax $ 3,369 $ 1,192 $ — $ — $ 4,561 Gain (loss) on disposal of discontinued operations, net of tax $ (8,513 ) $ (5,212 ) $ (258 ) $ 128 $ (13,855 ) Net income (loss) attributable to Magnum Hunter Resources Corporation $ (61,592 ) $ (64,647 ) $ (120,683 ) $ 103,448 $ (143,474 ) Net income (loss) attributable to common shareholders $ (76,468 ) $ (79,997 ) $ (136,175 ) $ 42,767 $ (249,873 ) Basic and diluted income (loss) from continuing operations per common share $ (0.41 ) $ (0.41 ) $ (0.68 ) $ 0.23 $ (1.27 ) Basic and diluted income (loss) per common share $ (0.44 ) $ (0.43 ) $ (0.68 ) $ 0.23 $ (1.32 ) ______________ (1) Total revenues decreased during each consecutive quarter throughout the year ended December 31, 2015 primarily due to decreases in realized prices for oil, gas and NGLs. (2) Fluctuations in operating income (loss) throughout the year ended December 31, 2015 were impacted by decreases in revenues as discussed above, as well as by changes in depreciation, depletion, amortization and accretion expense, impairment of proved oil and gas properties, and exploration expense. During the quarter ended March 31, 2015, depreciation, depletion, amortization and accretion expense was $57.8 million , impairment of proved oil and gas properties was $13.9 million , and exploration expense was $8.5 million . In contrast, depreciation, depletion, amortization and accretion expense was $22.3 million , impairment of proved oil and gas properties was $0.1 million , and exploration expense was $1.5 million during the quarter ended June 30, 2015. During the quarter ended September 30, 2015, the Company recorded exploration expense of $4.4 million and impairment of proved oil and natural gas properties of $49.8 million primarily related to the Williston Basin, and during the quarter ended December 31, 2015, the Company recorded exploration expense of $45.5 million and impairment of proved oil and natural gas properties of $211.6 million related to both the Appalachian and Williston Basins. (3) Net loss attributable to Magnum Hunter Resources Corporation during the quarter ended December 31, 2015 includes impairment of $180.3 million in order to write down the carrying value of its equity interest in Eureka Midstream Holdings to fair value as a result of the Company’s determination that the investment no longer met the criteria for classification as a discontinued operation as of that date. See “Note 5 - Acquisitions, Divestitures, and Discontinued Operations” . (4) Total revenues increased during the quarter ended June 30, 2014 primarily due to increases in natural gas gathering, processing, and marketing revenues as a result of new customers, growth from existing customers, and increased gas and NGLs revenues from the Markwest processing plant. Revenues decreased during the quarter ended September 30, 2014 due to decreases in natural gas gathering, processing, and marketing revenues. This decrease was due to the decision made by a third party customer to begin marketing their own natural gas, which had previously been marketed by the Company. Revenues decreased during the quarter ended December 31, 2014 due to decreases in oil prices, as well as decreased volumes due to the sales of certain oil and natural gas properties located in Divide County, North Dakota during the fourth quarter. (5) Income from operations during the quarter-ended June 30, 2014 was primarily driven by the increase in total revenues during that quarter, as discussed above. The loss from operations during the following quarter was due mainly to the decrease in total revenues, as discussed above. Loss from operations during the quarter ended December 31, 2014 was partially due to the decrease in revenues as discussed above, but also due to exploration expense of $66.1 million related mainly to the Williston Basin, impairment of proved oil and gas properties of $261.5 million mainly in the Williston Basin, and increased general and administrative expenses. General and administrative expenses during the quarter ended December 31, 2014 included a one-time charge of $32.6 million related to the Letter Agreement with MSI, in which the Company’s capital account with Eureka Midstream Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Midstream in connection with certain of Eureka Midstream’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects. (6) Loss from continuing operations during the quarters ended June 30, 2014 and September 30, 2014 includes loss on derivative contracts of $42.8 million and $49.6 million , respectively, primarily as a result of the unrealized loss on the embedded derivative liability resulting from certain features of the Eureka Midstream Holdings Series A Preferred Units. The unrealized losses were driven by increases in total enterprise value and a reduction in the expected term of the conversion feature. Income from continuing operations for the quarter ended December 31, 2014 includes a gain of $509.6 million from the deconsolidation of Eureka Midstream Holdings. See “Note 4 - Eureka Midstream Holdings”.
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities	The following table sets forth the costs incurred in oil and gas property acquisition, exploration, and development activities (in thousands): For the Year Ended December 31, 2015 2014 2013 Purchase of non-producing leases $ 18,906 $ 124,411 $ 149,592 Purchase of producing properties — 12,246 1,358 Exploration costs — 9,907 11,531 Development costs 45,075 327,138 276,130 $ 63,981 $ 473,702 $ 438,611
Summary of estimating quantities of proved reserves data	The following reserve data only represent estimates and should not be construed as being exact. Total Proved Reserves Crude Oil NGLs Natural Gas (MBbl) (MBbl) (MMcf) Balance December 31, 2012 36,827 9,125 162,620 Revisions of previous estimates (1) 3,766 2,382 100,456 Purchase of reserves in place — — 88 Extensions, discoveries, and other additions 577 71 1,285 Sale of reserves in place (14,506 ) (698 ) (4,185 ) Production (2,329 ) (458 ) (13,482 ) Balance December 31, 2013 24,335 10,422 246,782 Revisions of previous estimates (1) (6,540 ) 2,149 (511 ) Extensions, discoveries, and other additions 1,705 3,226 132,345 Sale of reserves in place (7,321 ) (434 ) (3,768 ) Production (1,658 ) (960 ) (21,847 ) Balance December 31, 2014 10,521 14,403 353,001 Revisions of previous estimates (1) (6,075 ) (6,959 ) (162,147 ) Extensions, discoveries and other additions — — 25,309 Production (1,016 ) (1,263 ) (34,778 ) Balance December 31, 2015 3,430 6,181 181,385 Developed reserves, included above December 31, 2013 12,085 6,990 176,585 December 31, 2014 6,938 10,587 251,628 December 31, 2015 3,430 6,181 156,076 Proved undeveloped reserves, included above: December 31, 2013 12,250 3,432 70,197 December 31, 2014 3,583 3,816 101,373 December 31, 2015 — — 25,309 ______________ (1) See discussion of revisions of previous estimates under “Changes in Standardized Measure of Discounted Future Net Cash Flows” below.
Details of standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: Years Ended December 31, 2015 2014 2013 (in thousands) Future cash inflows $ 598,161 $ 3,282,768 $ 3,711,260 Future production costs (369,478 ) (1,443,121 ) (1,423,306 ) Future development costs (16,712 ) (219,509 ) (421,797 ) Future income tax expense — — (149,367 ) Future net cash flows 211,971 1,620,138 1,716,790 10% annual discount for estimated timing of cash flows (101,382 ) (710,875 ) (872,280 ) Standardized measure of discounted future net cash flows $ 110,589 $ 909,263 $ 844,510
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: Years Ended December 31, 2015 2014 2013 (in thousands) Balance, beginning of period $ 909,263 $ 844,510 $ 847,653 Net changes in prices and production costs (640,645 ) (281,352 ) (7,355 ) Changes in estimated future development costs 137,578 (57,348 ) (261,591 ) Sales and transfers of oil and gas produced during the period (20,851 ) (166,611 ) (190,151 ) Net changes due to extensions, discoveries, and improved recovery 12,630 332,684 12,829 Net changes due to revisions of previous quantity estimates (1) (458,945 ) (55,176 ) 341,003 Previously estimated development costs incurred during the period 44,976 269,017 283,736 Accretion of discount 77,077 95,547 90,153 Purchase of minerals in place — — 218 Sale of minerals in place — (141,847 ) (236,885 ) Changes in timing and other 49,506 (7,720 ) (91,088 ) Net change in income taxes — 77,559 55,988 Standardized measure of discounted future net cash flows $ 110,589 $ 909,263 $ 844,510 ______________ (1) For the year ended December 31, 2015 , the Company made downward revisions of 6,075 MBbl of oil, 162,147 MMcf of natural gas, and 6,959 MBbl of natural gas liquids due to additional information gathered from continued production, lower pricing levels, and liquidity constraints. For the year ended December 31, 2014 , the Company made downward revisions of 6,540 MBbls of oil and 511 MMcf of natural gas, and upward revisions of 2,149 MBbl of natural gas liquids due to additional information gathered from continued production from the shale areas and increases in estimated ultimate recoveries (“EURs”). For the year ended December 31, 2013 , the Company made upward revisions of 3,766 MBbls of oil, 2,382 MBbl of natural gas liquids and 100,456 MMcf of natural gas due to continued production from the shale areas and increases in EURs.
Standardized measure to calculate future net revenues	The commodity prices inclusive of adjustments for quality and location used in determining future net revenues related to the standardized measure calculation are as follows: 2015 2014 2013 Oil (per Bbl) $ 41.83 $ 85.21 $ 93.13 Natural gas liquids (per Bbl) $ 16.90 $ 50.64 $ 43.79 Gas (per Mcf) $ 1.93 $ 4.69 $ 4.14

ORGANIZATION AND NATURE OF OP52

ORGANIZATION AND NATURE OF OPERATIONS (Details)	Dec. 31, 2015	Dec. 31, 2014	Dec. 18, 2014
Eureka Midstream Holdings
Business Acquisition [Line Items]
Ownership percentage by parent	44.53%	48.60%	48.60%

SUMMARY OF SIGNIFICANT ACCOUN53

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 18, 2014	Dec. 31, 2013	Dec. 15, 2015	Jul. 23, 2014
Summary of Significant Accounting Policies [Line Items]
Due period of joint interest owner obligations	30 days
Allowance for doubtful accounts receivable	$ 1,000,000	$ 308,000
Reclassification of deferred financing costs as debt reduction					$ 18,200,000
Deferred finance costs	0	22,856,000
Amortization and write-off of deferred financing costs	8,527,000	9,679,000		$ 4,818,000
Amortization of intangible assets	$ 0	2,000,000		2,500,000
Required period to remit liabilities under revenue payable	30 days
Revenue payable	$ 5,198,000
Liability for uncertain tax positions, current	0	0
Amounts reclassified from accumulated other comprehensive income for other than temporary impairment of available for sale securities	$ 19,000	$ (20,741,000)
Eureka Midstream Holdings
Summary of Significant Accounting Policies [Line Items]
Ownership percentage by parent	44.53%	48.60%	48.60%
PRC Williston, Inc.
Summary of Significant Accounting Policies [Line Items]
Ownership percentage by parent	100.00%					87.50%
Sentra Corporation
Summary of Significant Accounting Policies [Line Items]
Regulated operating revenue, gas	$ 637,000	$ 718,000		$ 216,000
Minimum
Summary of Significant Accounting Policies [Line Items]
Accounts receivable oil and gas period after production outstanding balance due	30 days
Useful lives of intangible assets			2 years
Maximum
Summary of Significant Accounting Policies [Line Items]
Accounts receivable oil and gas period after production outstanding balance due	60
Maximum | Eureka Midstream Holdings
Summary of Significant Accounting Policies [Line Items]
Useful lives of intangible assets			13 years
Oil and natural gas properties
Summary of Significant Accounting Policies [Line Items]
Interest costs capitalized, minimum time period for capitalization	6 months
Gas Transportation Gathering Processing and Other Equipment
Summary of Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	15 years
Field Servicing Assets | Minimum
Summary of Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	3 years
Field Servicing Assets | Maximum
Summary of Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	10 years
Furniture and Fixtures Equipment | Minimum
Summary of Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	5 years
Furniture and Fixtures Equipment | Maximum
Summary of Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	15 years
Accumulated Other Comprehensive Income (Loss)
Summary of Significant Accounting Policies [Line Items]
Amounts reclassified from accumulated other comprehensive income for other than temporary impairment of available for sale securities	$ 19,000	(20,741,000)
Accounts Payable
Summary of Significant Accounting Policies [Line Items]
Prior period reclassification adjustment		$ 5,200,000

VOLUNTARY REORGANIZATION UNDE54

VOLUNTARY REORGANIZATION UNDER CHAPTER 11 - Narrative (Details) $ in Millions	Feb. 25, 2016USD ($)directorcandidate	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Interest expense on liabilities subject to compromise | $		$ 2.8
First Amendment To Restructuring Support Agreement | Subsequent Event | Debtor
Debt Instrument [Line Items]
Cash pool for general unsecured claims | $	$ 23
Total enterprise value (agreed upon by parties to the RSA) | $	$ 900
Number of directors on new board	7
Number of directors selected by Noteholder Backstoppers	2
Number of directors selected by Second Lien Backstoppers	2
Number of directors selected by Noteholder Backstoppers based upon jointly determined three candidates	1
Number of candidates selected for one director position, jointly determined | candidate	3
First Amendment To Restructuring Support Agreement | Second Lien Term Loan Agreement | Subsequent Event | Debtor
Debt Instrument [Line Items]
Common equity received (result of reorganization of debt), percent	36.87%
First Amendment To Restructuring Support Agreement | 9.75% Senior Notes Due May 15, 2020 | Debtor
Debt Instrument [Line Items]
Interest rate (as a percent)		9.75%
First Amendment To Restructuring Support Agreement | 9.75% Senior Notes Due May 15, 2020 | Subsequent Event | Debtor
Debt Instrument [Line Items]
Common equity received (result of reorganization of debt), percent	31.33%
First Amendment To Restructuring Support Agreement | Debtor-in-possession Financial Facility | Subsequent Event | Debtor
Debt Instrument [Line Items]
Common equity received (result of reorganization of debt), percent	28.80%
First Amendment To Restructuring Support Agreement | Lenders Of Principal Amount, Second Lien Term Loan Agreement | Second Lien Term Loan Agreement | Subsequent Event | Debtor
Debt Instrument [Line Items]
Percent ownership of principal amount outstanding	67.00%
First Amendment To Restructuring Support Agreement | Holders Of Principal Amount Of 9.75% Senior Notes | 9.75% Senior Notes Due May 15, 2020 | Subsequent Event | Debtor
Debt Instrument [Line Items]
Percent ownership of principal amount outstanding	79.00%
Line of Credit | First Amendment To Restructuring Support Agreement | Debtor-in-possession Financial Facility | Subsequent Event | Debtor
Debt Instrument [Line Items]
Maximum borrowing capacity | $	$ 200
Non-Executive Chairman | First Amendment To Restructuring Support Agreement | Subsequent Event | Debtor
Debt Instrument [Line Items]
Number of directors selected by Noteholder and Second Lien Backstoppers	1

VOLUNTARY REORGANIZATION UNDE55

VOLUNTARY REORGANIZATION UNDER CHAPTER 11 - Liabilities Subject to Compromise (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Reorganizations [Abstract]
Senior Notes	$ 599,305
Second Lien Term Loan	335,853
Other notes payable	1,800
Total debt	936,958	$ 0
Accounts payable	78,536
Accounts payable to related parties	16,513	0
Dividends payable	7,275
Accrued liabilities	48,364
Revenue payable	5,198
Other liabilities	3,227
Total liabilities subject to compromise	$ 1,096,071	$ 0

VOLUNTARY REORGANIZATION UNDE56

VOLUNTARY REORGANIZATION UNDER CHAPTER 11 - Reorganization Items (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reorganizations [Abstract]
Professional fees	$ 4,118
Debt issuance costs	9,036
Loss on adjustments to carrying value of Senior Notes	12,533
Loss on adjustments to carrying value of Second Lien Term Loan	15,452
Total reorganization items	$ 41,139	$ 0	$ 0

VOLUNTARY REORGANIZATION UNDE57

VOLUNTARY REORGANIZATION UNDER CHAPTER 11 - Debtor Condensed Financial Statements (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets	$ 83,548				$ 128,322				$ 83,548	$ 128,322
Property and equipment (using successful efforts accounting)	768,538				1,175,658				768,538	1,175,658
Investment in affiliates, equity method	166,099				347,191				166,099	347,191
Other assets	41,973				3,928				41,973	3,928
Total assets	1,060,158				1,677,955				1,060,158	1,677,955	$ 1,856,651
Current liabilities	145,900				176,571				145,900	176,571
Liabilities subject to compromise	1,096,071				0				1,096,071	0
Long-term liabilities	176,571				1,146,100				176,571	1,146,100
Shareholders' equity (deficit)	(312,484)				431,855				(312,484)	431,855	450,730	$ 711,652
Total liabilities and shareholders’ equity	1,060,158				1,677,955				1,060,158	1,677,955
Revenues	25,538	$ 33,664	$ 39,526	$ 55,396	59,854	$ 79,670	$ 138,463	$ 113,482	154,124	391,469	304,538
Operating expenses									615,210	881,827	539,331
OPERATING LOSS	(303,475)	(84,652)	4,529	(77,488)	(401,575)	(57,576)	1,555	(32,762)	(461,086)	(490,358)	(234,793)
Interest income									157	156	265
Interest expense									(99,559)	(86,463)	(72,621)
Gain (loss) on derivative contracts, net									4,886	(72,254)	(25,274)
Loss from equity method investments									(186,157)	(1,038)	(994)
Reorganization items									(41,139)	0	0
Other income (expense)									(5,575)	2,561	15,897
Total other income (expense), net									(281,647)	352,525	(82,727)
Dividends on preferred stock									(33,817)	(54,707)	(56,705)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(550,370)	$ (122,029)	$ (30,523)	(114,767)	42,767	$ (136,175)	$ (79,997)	(76,468)	(817,689)	(249,873)	(278,881)
NET LOSS									(783,872)	(147,127)	(223,164)
Foreign currency translation gain (loss)									99	(1,204)	(10,928)
Unrealized gain (loss) on available for sale securities									(2,771)	(7,401)	8,178
Amounts reclassified for other than temporary impairment of available for sale securities									10,183	0	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities									(19)	0	(8,262)
Total other comprehensive income (loss)									7,492	12,136	(11,012)
COMPREHENSIVE LOSS									(776,380)	(134,991)	(234,176)
Cash flow from operating activities									25,026	(18,665)	111,711
Cash flow from investing activities									(165,941)	(318,119)	(127,860)
Cash flow from financing activities									128,634	348,195	656
Effect of foreign exchange rate changes on cash									(28)	56	(417)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS									(12,309)	11,467	(15,910)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR				53,180				$ 41,713	53,180	41,713	57,623
CASH AND CASH EQUIVALENTS, END OF YEAR	40,871				53,180				40,871	53,180	$ 41,713
Debtor
Current assets	83,371								83,371
Intercompany accounts receivable	137								137
Property and equipment (using successful efforts accounting)	766,843								766,843
Investment in Subsidiaries	1,214								1,214
Investment in affiliates, equity method	166,099								166,099
Other assets	41,973								41,973
Total assets	1,059,637								1,059,637
Current liabilities	145,860								145,860
Liabilities subject to compromise	1,096,071								1,096,071
Long-term liabilities	30,670								30,670
Redeemable preferred stock	100,000								100,000
Shareholders' equity (deficit)	(312,964)								(312,964)
Total liabilities and shareholders’ equity	1,059,637								1,059,637
Revenues									153,087
Operating expenses									614,383
OPERATING LOSS									(461,296)
Interest income									157
Interest expense									(99,559)
Gain (loss) on derivative contracts, net									4,886
Loss from equity method investments									(181,556)
Reorganization items									(41,139)
Other income (expense)									(5,568)
Total other income (expense), net									(322,779)
Dividends on preferred stock									(33,817)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(817,892)
NET LOSS									(784,075)
Foreign currency translation gain (loss)									99
Unrealized gain (loss) on available for sale securities									(2,771)
Amounts reclassified for other than temporary impairment of available for sale securities									10,183
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities									(19)
Total other comprehensive income (loss)									7,492
COMPREHENSIVE LOSS									(776,583)
Cash flow from operating activities									24,915
Cash flow from investing activities									(165,941)
Cash flow from financing activities									128,634
Effect of foreign exchange rate changes on cash									(28)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS									(12,420)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR				$ 53,187					53,187
CASH AND CASH EQUIVALENTS, END OF YEAR	$ 40,767				$ 53,187				$ 40,767	$ 53,187

EUREKA HUNTER HOLDINGS - Decons

EUREKA HUNTER HOLDINGS - Deconsolidation Narrative (Details)	Nov. 03, 2015USD ($)	Jul. 27, 2015shares	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 18, 2014USD ($)member	Nov. 20, 2014USD ($)	Nov. 18, 2014USD ($)shares	Jan. 31, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)representative	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 30, 2015USD ($)	Dec. 17, 2014member
Noncontrolling Interest [Line Items]
Non-cash loss, downward adjustment of equity interests										$ 32,600,000
Gain on deconsolidation										0	$ 509,563,000	$ 0
Loss from equity method investments										186,157,000	1,038,000	$ 994,000
Investment in affiliates, equity method				$ 347,191,000						166,099,000	347,191,000
Identifiable assets, basis difference				$ 201,874,000						$ 3,822,000	$ 201,874,000
Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Ownership percentage by parent				48.60%	48.60%					44.53%	48.60%
Consolidated entities ownership percentage in entity										100.00%
Percent ownership of subsidiaries										48.60%
Number of representatives on the board of managers of LLC | representative										3
Gain on deconsolidation					$ 509,600,000
Revaluation of retained investment, gain					$ 187,200,000
Series A-1 Units | Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Payments for limited liability company units						$ 20,000,000
Morgan Stanley Infrastructure (MSI) | Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Investment holding of total dhares outstanding, percent								6.50%
Payments to acquire equity method investments								$ 65,000,000
Percent ownership of subsidiaries								98.00%		49.84%
Carried interest limit if capital contributions are made										$ 60,000,000
Number of managers on the board of limited liability company | member					6									5
Number of representatives on the board of managers of LLC | representative										3
Retained interest upon deconsolidation				$ 347,292,000	$ 347,300,000						$ 347,292,000
Deferred capital contributions										$ 27,200,000
Morgan Stanley Infrastructure (MSI) | Series A-1 Units | Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Reduction in capital account, shares | shares							1,227,182
Reduction in capital account							$ 32,600,000
Payments for limited liability company units					$ 55,000,000				$ 13,300,000
Limited liability company units sold, as a percent					5.50%
Morgan Stanley Infrastructure (MSI) | Series A-2 Units | Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Payments for limited liability company units					$ 10,000,000	$ 30,000,000
Eureka Midstream Holdings | Series A-1 Units
Noncontrolling Interest [Line Items]
Percent ownership of subsidiaries													45.53%
Eureka Midstream Holdings | Morgan Stanley Infrastructure (MSI) | Series A-2 Units
Noncontrolling Interest [Line Items]
Percent ownership of subsidiaries													53.00%
Eureka Midstream Holdings | 2015 Growth CapEx Projects Contribution | Morgan Stanley Infrastructure (MSI) | Series A-2 Units
Noncontrolling Interest [Line Items]
Payments for limited liability company units			$ 27,200,000
Eureka Midstream Holdings | Additional Contribution | Morgan Stanley Infrastructure (MSI) | Series A-2 Units
Noncontrolling Interest [Line Items]
Payments for limited liability company units			37,800,000
Eureka Midstream Holdings | MHR 2015 Make-Up Contribution | Morgan Stanley Infrastructure (MSI) | Series A-2 Units
Noncontrolling Interest [Line Items]
Payments for limited liability company units			$ 18,700,000
Reduction in limited liability company (LLC) units, adjustment | shares		529,190
Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Percent ownership of subsidiaries				48.60%							48.60%
Gain on deconsolidation										4,600,000
Revaluation of retained investment, gain										(7,500,000)
Loss from equity method investments				$ 101,000						(8,490,000)
Impairment of equity method investments	$ 180,300,000			0						180,254,000
Investment in affiliates, equity method				347,200,000						166,100,000	$ 347,200,000
Eureka Midstream Holdings | Series A-1 Units
Noncontrolling Interest [Line Items]
Loss from equity method investments				$ 0						$ 7,664,000
Reduction in basis difference													$ 4,000,000
Eureka Midstream Holdings | Morgan Stanley Infrastructure (MSI)
Noncontrolling Interest [Line Items]
Percent ownership of subsidiaries				49.84%						53.98%	49.84%

EUREKA HUNTER HOLDINGS - Net As

EUREKA HUNTER HOLDINGS - Net Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Identifiable Assets Basis Amortization And Reduction [Roll Forward]
Identifiable assets, beginning balance	$ 201,874
Basis Amortization	(6,265)
Basis Reduction	(191,787)
Identifiable assets, ending balance	3,822
Fixed assets
Identifiable Assets Basis Amortization And Reduction [Roll Forward]
Identifiable assets, beginning balance	5,088
Basis Amortization	(208)
Basis Reduction	(4,785)
Identifiable assets, ending balance	95
Intangible assets
Identifiable Assets Basis Amortization And Reduction [Roll Forward]
Identifiable assets, beginning balance	155,189
Basis Amortization	(6,057)
Basis Reduction	(146,252)
Identifiable assets, ending balance	2,880
Goodwill
Identifiable Assets Basis Amortization And Reduction [Roll Forward]
Identifiable assets, beginning balance	41,597
Basis Amortization	0
Basis Reduction	(40,750)
Identifiable assets, ending balance	$ 847
Minimum
Noncontrolling Interest [Line Items]
Basis difference, estimated useful lives	3 years
Maximum
Noncontrolling Interest [Line Items]
Basis difference, estimated useful lives	39 years

EUREKA HUNTER HOLDINGS - Balanc

EUREKA HUNTER HOLDINGS - Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Current assets	$ 83,548	$ 128,322
Current liabilities	145,900	176,571
Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Current assets	86,910	17,113
Non-current assets	507,201	445,450
Current liabilities	20,683	63,313
Non-current liabilities	$ 182,561	$ 100,037

EUREKA HUNTER HOLDINGS - Income

EUREKA HUNTER HOLDINGS - Income Information (Details) - USD ($) $ in Thousands	Nov. 03, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Noncontrolling Interest [Line Items]
Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014			$ (186,157)	$ (1,038)	$ (994)
Basis difference amortization			0	$ (2,000)	$ (2,500)
Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Operating revenues		$ 2,124	77,022
Operating income		74	23,250
Net income (loss)		(207)	18,979
Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014		(101)	8,490
Impairment upon reclassification from discontinued operations to continuing operations	$ (180,300)	0	(180,254)
Magnum Hunter’s equity in earnings (loss), net		(101)	(185,693)
Basis Difference Resulting from Deconsolidation | Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Basis difference amortization		0	(6,265)
Series A-1 Units | Eureka Midstream Holdings
Noncontrolling Interest [Line Items]
Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014		$ 0	$ (7,664)

ACQUISITIONS, DIVESTITURES, A62

ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS (Acqusition Narratives) (Details) $ in Millions	Jul. 24, 2014USD ($)	Jun. 17, 2014	Dec. 31, 2015USD ($)a	Dec. 31, 2014USD ($)a	Dec. 31, 2013USD ($)a	Jun. 18, 2014a	Aug. 12, 2013USD ($)a
Business Acquisition [Line Items]
Acquisition related costs | $					$ 2.8
Utica Shale
Business Acquisition [Line Items]
Net mineral acres acquired | a							32,000
Maximum purchase price | $							$ 142.1
Payments to acquire land | $					$ 24.6
Ormet Asset Purchase Agreement
Business Acquisition [Line Items]
Acreage In which mineral interests acquired (in acres) | a						1,700
Utica Shale, Ohio | Triad Hunter | Asset Purchase Agreement With MNW
Business Acquisition [Line Items]
Acreage of undeveloped leasehold acquired (in acres) | a			2,665	16,456	5,922
Payments to acquire land | $			$ 12	$ 67.3
Monroe County, Ohio | Ormet Asset Purchase Agreement
Business Acquisition [Line Items]
Acreage In which mineral interests acquired (in acres) | a						1,375
Wetzerl County, West Virginia | Ormet Asset Purchase Agreement
Business Acquisition [Line Items]
Acreage In which mineral interests acquired (in acres) | a						325
Marcellus Zone | Ormet Asset Purchase Agreement
Business Acquisition [Line Items]
Leasehold rights, royalty carried on production, percentage		12.50%
Leasehold rights, interest in and rights to oil, natural gas, and other minerals, percentage	100.00%
Cash payment for acquisition | $	$ 22.7

ACQUISITIONS, DIVESTITURES, A63

ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS (Results of Operations of WHI Canada) (Details) - USD ($)	3 Months Ended				12 Months Ended			15 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014
Discontinued operations
Revenues						$ 8,533,000	$ 67,490,000
Expenses						(3,975,000)	(130,331,000)
Other income (expense)						3,000	186,000
Income (loss) from discontinued operations before tax					$ 0	4,561,000	(62,655,000)
Income tax benefit (expense)						0	94,000
Income (loss) from discontinued operations, net of tax						4,561,000	(62,561,000)
Gain (loss) on disposal of discontinued operations, net of taxes	$ 128,000	$ (258,000)	$ (5,212,000)	$ (8,513,000)	0	(13,855,000)	71,510,000
Income (loss) from discontinued operations, net of tax					$ 0	(9,294,000)	8,949,000
Magnum Hunter Production and Williston Hunter Canada
Discontinued operations
Gain (loss) on disposal of discontinued operations, net of taxes						(12,900,000)
Impairment expense related to discontinued operations				$ 18,600,000			65,400,000	$ 67,600,000
Exploration expense						100,000	$ 19,900,000
Wilson Hunter Canada, Inc.
Discontinued operations
Effective tax rate, loss from discontinued operations, as a percent							0.20%
Tax effect of income (loss) from disposal of discontinued operation						$ 0	$ 11,900,000
WHI Canada Capital Loss Utilization Against Capital Gains
Discontinued operations
Effective tax rate, loss from discontinued operations, as a percent							14.23%

ACQUISITIONS, DIVESTITURES, A64

ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS (Discontinued Operations Narratives) (Details) $ / shares in Units, $ in Thousands, CAD in Millions

Nov. 03, 2015USD ($)

Dec. 31, 2014USD ($)

May. 12, 2014USD ($)

May. 12, 2014CAD

Apr. 10, 2014USD ($)

Apr. 10, 2014CAD

Apr. 24, 2013USD ($)$ / sharesshares

Dec. 31, 2014USD ($)

Sep. 30, 2014USD ($)

Jun. 30, 2014USD ($)

Mar. 31, 2014USD ($)

Sep. 30, 2013USD ($)

Sep. 30, 2014USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Dec. 31, 2014USD ($)

Jul. 25, 2014USD ($)

Mar. 01, 2014CAD

Feb. 17, 2012shares

Discontinued operations

Depreciation

$ 8,000

$ 22,100

$ 15,600

Gain (loss) on disposal of discontinued operations, net of tax

$ 128

$ (258)

$ (5,212)

$ (8,513)

0

(13,855)

71,510

Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities

0

20,741

0

Eureka Midstream Holdings

Discontinued operations

Impairment of equity method investments

$ 180,300

$ 0

$ 180,254

Magnum Hunter Production, Inc.

Discontinued operations

Impairment expense related to discontinued operations

18,500

Magnum Hunter Production and Williston Hunter Canada

Discontinued operations

Impairment expense related to discontinued operations

$ 18,600

65,400

$ 67,600

Depreciation

$ 1,700

Gain (loss) on disposal of discontinued operations, net of tax

(12,900)

Ownership percentage sold

100.00%

100.00%

Proceeds from divestiture of businesses

$ 68,800

CAD 75

Cash in escrow | CAD

CAD 18.4

Williston Hunter Canada Assets

Discontinued operations

Proceeds from sale of property, plant, and equipment

$ 8,700

CAD 9.5

Gain (loss) on disposal of discontinued operations, net of tax

$ 6,100

Hunter Disposal LLC

Discontinued operations

Consideration received, number of shares of common stock received | shares

1,846,722

Eagle Ford Hunter

Discontinued operations

Consideration received, number of shares of common stock received | shares

10,000,000

Consideration received, common stock value

$ 42,300

Liabilities associated with assets held for sale

$ 33,700

Discontinued operations accrued liabilities

$ 1,300

Downward adjustment to prior period gain on sale, net of tax

$ 7,100

$ 28,100

Unproved Oil And Natural Gas Properties | Magnum Hunter Production and Williston Hunter Canada

Discontinued operations

Impairment expense related to discontinued operations

$ 1,900

Proved Oil and Natural Gas Properties | Magnum Hunter Production and Williston Hunter Canada

Discontinued operations

Impairment expense related to discontinued operations

$ 17,000

Penn Virginia | Hunter Disposal LLC

Discontinued operations

Gain (loss) on disposal of discontinued operations, net of tax

$ 172,500

Proceeds from divestiture of businesses

379,800

50,600

Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities

$ 8,300

Total consideration received

$ 422,100

Consideration received, number of shares of common stock received | shares

10,000,000

Consideration received, common stock value

$ 42,300

Common stock issued (in dollars per share) | $ / shares

$ 4.23

Sales proceeds used to pay down outstanding borrowings

$ 325,000

ACQUISITIONS, DIVESTITURES, A65

ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS (Other Divestitures Narratives) (Details) $ / shares in Units, $ in Thousands

Nov. 03, 2014USD ($)

Oct. 15, 2014USD ($)

Sep. 30, 2014USD ($)

Jan. 28, 2014USD ($)Well$ / sharesshares

Dec. 30, 2013USD ($)Well

Sep. 26, 2013USD ($)

Dec. 31, 2014USD ($)

Sep. 30, 2014USD ($)

Jun. 30, 2014USD ($)

Mar. 31, 2014USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Sep. 30, 2015USD ($)

Jun. 18, 2015USD ($)a

Discontinued operations

Gain (loss) on disposal of discontinued operations, net of tax

$ 128

$ (258)

$ (5,212)

$ (8,513)

$ 0

$ (13,855)

$ 71,510

Williston Hunter Inc

Discontinued operations

Proceeds from divestiture of businesses

$ 32,500

Gain (loss) on disposal of discontinued operations, net of tax

$ (38,100)

Enduro Operating LLC

Discontinued operations

Operated working interests, in wells | Well

180

Proceeds from divestiture of interest in consolidated subsidiaries

$ 44,100

Preliminary gain (loss) on disposal of discontinued operation

$ (7,100)

Eagle Ford Shale Assets

Discontinued operations

Proceeds from divestiture of businesses

$ 15,500

Gain (loss) on disposal group, not discontinued operation

$ (4,500)

Divide County, North Dakota | Non-Operated Working Interests In Oil And Gas Properties

Discontinued operations

Proceeds from divestiture of businesses

$ 84,800

$ 23,500

Gain (loss) on disposal of discontinued operations, net of tax

(3,100)

$ 7,200

Impairment expense related to discontinued operations

$ 15,200

Leasehold Acreage, Atascosa County, Texas | Eagle Ford Shale Assets

Discontinued operations

Number of horizontal oil and gas wells | Well

5

Number of horizontal oil and gas wells operated by Magnum Hunter Resources | Well

4

Roane Counties, West Virginia | Non-Core Working Interests In Oil And Gas Properties

Discontinued operations

Proceeds from divestiture of businesses

$ 1,200

Impairment expense related to discontinued operations

5,700

Gain (loss) on disposal group, not discontinued operation

$ (800)

New Standard Energy Texas LLC | Eagle Ford Shale Assets

Discontinued operations

Consideration received, number of shares of common stock received | shares

65,650,000

Consideration received, common stock value

$ 9,400

Disposal group including discontinued operation price of stock on sale date (in dollars per share) | $ / shares

$ 0.14

Investment holding of total dhares outstanding, percent

17.00%

Triad Hunter | Antero Resources Corporation | Right, Title And Interest In Undeveloped And Unproven Leasehold Acreage in Tyler County, West Virginia

Discontinued operations

Cash consideration received

$ 4,200

$ 33,600

Gas and oil area, undeveloped (in acres) | a

5,210

Gain (loss) on disposition of assets

$ 31,700

OIL & NATURAL GAS SALES (Detail

OIL & NATURAL GAS SALES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	$ 133,448	$ 268,501	$ 220,699
Oil
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	42,805	131,109	147,798
Natural Gas
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	69,533	91,277	53,821
NGL
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	$ 21,110	$ 46,115	$ 19,080

PROPERTY, PLANT, & EQUIPMENT (D

PROPERTY, PLANT, & EQUIPMENT (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Unproved leasehold costs			$ 398,302	$ 481,643
Proved leasehold costs			198,458	257,185
Wells and related equipment and facilities			469,578	560,060
Uncompleted wells, equipment and facilities			0	46,346
Advances to operators for wells in progress			1,279	1,411
Total costs			1,067,617	1,346,645
Less accumulated depreciation, depletion, and amortization			(369,347)	(248,410)
Net capitalized costs			698,270	1,098,235
Depreciation, depletion, amortization and accretion	$ 22,300	$ 57,800	132,804	146,868	$ 107,385
Depreciation			8,000	22,100	15,600
Magnum Hunter Production, Inc.
Property, Plant and Equipment [Line Items]
Impairment of leasehold				33,800	26,900
Oil and natural gas properties
Property, Plant and Equipment [Line Items]
Depreciation, depletion, amortization and accretion			$ 122,200	121,900	69,000
Eureka Midstream Holdings
Property, Plant and Equipment [Line Items]
Depreciation				$ 14,400	$ 9,900

PROPERTY, PLANT, & EQUIPMENT (P

PROPERTY, PLANT, & EQUIPMENT (Property Impairments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Proved property impairments	$ 275,375	$ 301,276	$ 50,011
Williston Basin
Property, Plant and Equipment [Line Items]
Proved property impairments	64,165	261,270	8,498
Appalachian Basin
Property, Plant and Equipment [Line Items]
Proved property impairments	207,340	6,001	1,151
Western Kentucky
Property, Plant and Equipment [Line Items]
Proved property impairments	3,783	33,811	40,043
South Texas
Property, Plant and Equipment [Line Items]
Proved property impairments	$ 87	$ 194	$ 319

PROPERTY, PLANT, & EQUIPMENT (E

PROPERTY, PLANT, & EQUIPMENT (Exploration) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Geological and geophysical	$ 2,317	$ 1,564	$ 1,402
Exploration abandonment and impairment expense	59,831	118,509	100,389
Williston Basin
Property, Plant and Equipment [Line Items]
Leasehold impairments	45,811	103,147	89,167
Appalachian Basin
Property, Plant and Equipment [Line Items]
Leasehold impairments	11,501	9,978	6,773
Western Kentucky
Property, Plant and Equipment [Line Items]
Leasehold impairments	75	3,820	3,047
South Texas
Property, Plant and Equipment [Line Items]
Leasehold impairments	$ 127	$ 0	$ 0

PROPERTY, PLANT, & EQUIPMENT (C

PROPERTY, PLANT, & EQUIPMENT (Capitalized Costs of Oil and Gas Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Gas transportation, gathering and processing equipment and other	$ 1,067,617	$ 1,346,645
Less accumulated depreciation	(369,347)	(248,410)
Net capitalized costs	698,270	1,098,235
Gas Transportation Gathering Processing and Other Equipment
Property, Plant and Equipment [Line Items]
Gas transportation, gathering and processing equipment and other	100,916	100,436
Less accumulated depreciation	(30,648)	(23,013)
Net capitalized costs	$ 70,268	$ 77,423

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of Asset Retirement Obligation
Asset retirement obligation at beginning of period	$ 26,524	$ 16,216
Liabilities incurred	40	218
Liabilities settled	(346)	(107)
Liabilities sold	(254)	(2,598)
Accretion expense	2,597	1,478
Revisions in estimated liabilities	101	3,208
Reclassified from liabilities associated with assets held for sale	0	8,109
Asset retirement obligation at end of period	28,662	26,524
Less: current portion	(1,464)	(295)
Asset retirement obligation at end of period	$ 27,198	$ 26,229

FAIR VALUE OF FINANCIAL INSTR72

FAIR VALUE OF FINANCIAL INSTRUMENTS (Financial Assets and Liabilities Adjusted to FV on a Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities	$ 157	$ 3,864	$ 1,819	$ 1,958
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities	157	3,864
Total assets at fair value	157	3,864
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities	0	0
Total assets at fair value	0	16,511
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities	0	0
Total assets at fair value	$ 0	75
Commodity derivative | Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Commodity derivative | Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		16,511
Commodity derivative | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Convertible security derivative assets | Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Convertible security derivative assets | Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Convertible security derivative assets | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		$ 75

FAIR VALUE OF FINANCIAL INSTR73

FAIR VALUE OF FINANCIAL INSTRUMENTS (Changes in FV of Derivative Assets and Liabilities) (Details) - USD ($) $ in Thousands	Oct. 03, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Series A Preferred Stock
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value, end of period		$ 0
Convertible security derivative assets | Level 3 | Embedded Derivatives, Assets
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value, beginning of period		75	$ 79	$ 264
Issuance of embedded liability			0	0
Change in fair value recognized in loss on derivative contracts, net		(75)	(4)	(185)
Fair value, end of period		0	75	79
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Conversion of Eureka Midstream Holdings Series A Preferred Units to Series A-2 Units			0
Convertible preferred stock derivative liabilities | Level 3 | Series A Preferred Stock
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value, beginning of period				(43,548)
Embedded Derivatives, Liabilities | Convertible preferred stock derivative liabilities | Level 3
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value, beginning of period		0
Issuance of embedded liability			(5,479)	(14,645)
Change in fair value recognized in loss on derivative contracts, net		$ 0	(91,792)	(17,741)
Conversion of Eureka Midstream Holdings Series A Preferred Units to Series A-2 Units	$ 173,205		173,205
Fair value, end of period			0
Embedded Derivatives, Liabilities | Convertible preferred stock derivative liabilities | Level 3 | Series A Preferred Stock
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair value, beginning of period			$ (75,934)
Fair value, end of period				$ (75,934)

FAIR VALUE OF FINANCIAL INSTR74

FAIR VALUE OF FINANCIAL INSTRUMENTS (Carrying Amounts and Fair Values Categorized by FV Hierarchy) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Oct. 22, 2014
Level 3 | Second Lien Term Loan
Carrying amounts and fair values of long-term debt
Discount on issuance of long-term debt, as a percent			3.00%
Carrying Amount | Level 2 | Senior Notes
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	$ 599,305	$ 597,355
Carrying Amount | Level 3 | Second Lien Term Loan
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	355,853	329,140
Carrying Amount | Level 3 | Equipment notes payable
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	15,482	22,238
Carrying Amount | Level 3 | Senior Secured Bridge Financing Facility
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	70,000	0
Carrying Amount | Level 3 | Debtor-in-Possession Credit Facility
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	40,000	0
Estimated Fair Value | Level 2 | Senior Notes
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	161,520	498,000
Estimated Fair Value | Level 3 | Second Lien Term Loan
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	211,588	329,140
Estimated Fair Value | Level 3 | Equipment notes payable
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	15,482	22,150
Estimated Fair Value | Level 3 | Senior Secured Bridge Financing Facility
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	70,000	0
Estimated Fair Value | Level 3 | Debtor-in-Possession Credit Facility
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	$ 40,000	$ 0

FAIR VALUE OF FINANCIAL INSTR75

FAIR VALUE OF FINANCIAL INSTRUMENTS (Fair Value Measurements on a Non-Recurring Basis) (Details) - Nonrecurring - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of proved properties impaired	$ 0	$ 0	$ 0
Fair value of long-lived assets of MHP		0
Fair value of retained interest in Eureka Midstream Holdings	0	0
Fair value of acquisitions			0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of proved properties impaired	0	0	0
Fair value of long-lived assets of MHP		0
Fair value of retained interest in Eureka Midstream Holdings	0	0
Fair value of acquisitions			0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of proved properties impaired	298,689	584,895	329,409
Fair value of long-lived assets of MHP		28,443
Fair value of retained interest in Eureka Midstream Holdings	$ 163,362	$ 347,291
Fair value of acquisitions			$ 87,149

FAIR VALUE OF FINANCIAL INSTR76

FAIR VALUE OF FINANCIAL INSTRUMENTS (Narratives) (Details) - USD ($) $ in Thousands	Dec. 18, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Impairment of proved oil and gas properties		$ 275,375	$ 301,276	$ 50,011
Morgan Stanley Infrastructure (MSI) | Series A-1 Units | Eureka Midstream Holdings
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Limited liability company units sold, as a percent	5.50%

INVESTMENTS AND DERIVATIVES Cha

INVESTMENTS AND DERIVATIVES Changes in Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 18, 2014	Dec. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Available for sale securities	$ 3,864	$ 3,864					$ 157	$ 3,864	$ 1,819		$ 1,958
Equity method investments, fair value disclosure	347,191	347,191					166,099	347,191	940		$ 2,072
Equity Method Investments, Return of Capital									(138)
Available for Sale Securities, Acquired During Period								9,446	42,300
Equity Method Investments, Acquired During Period									0
Loss from equity method investments							(186,157)	(1,038)	(994)
Equity Method Investments, Other Adjustments							0	(3)
Change in fair value recognized in other comprehensive loss							(2,771)	(7,401)	(84)
Gain on dilution of interest in Eureka Midstream Holdings, LLC							4,601	0	0
Available-for-sale equity securities, loss							(464)
Gain (loss) on disposal of discontinued operations, net of tax		128	$ (258)	$ (5,212)	$ (8,513)		0	(13,855)	71,510
Available-for-sale Securities, Other Adjustments								0	$ (55)
Penn Virginia
Schedule of Available-for-sale Securities [Line Items]
Proceeds from sale of available-for-sale securities						$ (50,562)	(472)
Gain (loss) on disposal of discontinued operations, net of tax						$ 8,262		0
Eureka Midstream Holdings
Schedule of Available-for-sale Securities [Line Items]
Loss from equity method investments	(101)						8,490
Loss from equity method investment	(101)						$ (185,693)
Morgan Stanley Infrastructure (MSI) | Eureka Midstream Holdings
Schedule of Available-for-sale Securities [Line Items]
Retained interest upon deconsolidation	$ 347,292	$ 347,292						$ 347,292		$ 347,300

INVESTMENTS AND DERIVATIVES Der

INVESTMENTS AND DERIVATIVES Derivative Assets and Liabilities (Details) $ in Thousands	Dec. 31, 2014USD ($)
Derivatives, Fair Value
Gross Derivative Assets	$ 16,586
Commodity
Derivatives, Fair Value
Gross Derivative Assets	16,511
Financial
Derivatives, Fair Value
Gross Derivative Assets	75
Derivative assets - current | Commodity
Derivatives, Fair Value
Gross Derivative Assets	16,511
Derivative assets - current | Financial
Derivatives, Fair Value
Gross Derivative Assets	$ 75

INVESTMENTS AND DERIVATIVES Net

INVESTMENTS AND DERIVATIVES Net Gain (Loss) on Derivative Contracts (Details) - Commodity - Other Income (Expense) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative contracts	$ 4,886	$ (72,254)	$ (25,274)
Loss on extinguished embedded derivative	0	(91,792)	0
Open Transaction
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative contracts	2,437	18,232	(17,058)
Settled Transaction
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative contracts	$ 2,449	$ 1,306	$ (8,216)

INVESTMENTS AND DERIVATIVES Inv

INVESTMENTS AND DERIVATIVES Investments by Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Available-for-sale Securities, Current	$ 157	$ 3,864
Equity Method Investments, Current	0	0
Investments, Available-for-sale and Equity Method, Current	157	3,864
Available-for-sale Securities, Noncurrent	0	0
Investment in affiliates, equity method	166,099	347,191
Investments, Available-for-sale and Equity Method, Noncurrent	166,099	347,191
Available for sale securities	157	3,864	$ 1,819	$ 1,958
Investment in affiliates, equity method	166,099	347,191
Investments, Available-for-sale and Equity Method, Current and Noncurrent	$ 166,256	$ 351,055

INVESTMENTS AND DERIVATIVES I81

INVESTMENTS AND DERIVATIVES Investments, Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
AFS, Cost	$ 78	$ 9,876
AFS, Gross Unrealized Gains	0	0
AFS, Gross Unrealized Losses	(2)	(7,323)
AFS, Fair Value	76	2,553
AFS, Related Party, Cost	465	2,200
AFS, Related Party, Gross Unrealized Gains	0	0
AFS, Related Party, Gross Unrealized Losses	(384)	(889)
AFS, Related Party, Fair Value	81	1,311
Cost	543	12,076
Gross Unrealized Gains	0	0
Gross Unrealized Losses	386	8,212
Fair Value	$ 157	$ 3,864

INVESTMENTS AND DERIVATIVES Eff

INVESTMENTS AND DERIVATIVES Effect of Master Netting (Details) $ in Thousands	Dec. 31, 2014USD ($)
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ 16,511
Derivative, Fair Value, Amount Offset Against Collateral, Net	0
Derivative, Fair Value, Net	16,511
Current assets: Fair value of derivative contracts
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement	18,146
Derivative Asset, Fair Value, Gross Liability	(1,635)
Derivative assets	16,511
Current liabilities: Fair value of derivative contracts
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement	(1,635)
Derivative Liability, Fair Value, Gross Asset	1,635
Derivative liability	$ 0

INVESTMENTS AND DERIVATIVES Nar

INVESTMENTS AND DERIVATIVES Narrative (Details) $ / shares in Units, AUD in Millions	Nov. 02, 2015USD ($)	Oct. 20, 2015USD ($)	Oct. 20, 2015AUD	Feb. 17, 2012shares	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2013USD ($)	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	May. 07, 2015USD ($)	Dec. 18, 2014USD ($)	Jan. 28, 2014USD ($)$ / sharesshares	Apr. 24, 2013USD ($)shares	Dec. 31, 2012USD ($)
Derivative [Line Items]
Other-than-temporary impairment reclassified from AOCI												$ 10,183,000	$ 0	$ 0
Investment in affiliates, equity method						$ 347,191,000						166,099,000	347,191,000
Gain (loss) on disposal of discontinued operations, net of tax						128,000	$ (258,000)	$ (5,212,000)	$ (8,513,000)			0	(13,855,000)	71,510,000
Available for sale securities						3,864,000						157,000	3,864,000	1,819,000					$ 1,958,000
Loss from equity method investments												186,157,000	1,038,000	994,000
Equity method investments, fair value disclosure						347,191,000						166,099,000	347,191,000	940,000					$ 2,072,000
GreenHunter Resources, Inc.
Derivative [Line Items]
Other-than-temporary impairment reclassified from AOCI												800,000
Loss from equity method investments												464,000	590,000	$ 730,000
Hunter Disposal LLC
Derivative [Line Items]
Consideration received, number of shares of common stock received | shares				1,846,722
Hunter Disposal LLC | Green Hunter Energy
Derivative [Line Items]
Consideration received, number of shares of preferred stock received | shares				88,000
Consideration received, common stock value						0						0	0
Eagle Ford Hunter
Derivative [Line Items]
Consideration received, number of shares of common stock received | shares																		10,000,000
Consideration received, common stock value																		$ 42,300,000
Penn Virginia
Derivative [Line Items]
Proceeds from sale of available-for-sales securities											$ 50,562,000	472,000
Gain (loss) on disposal of discontinued operations, net of tax											$ 8,262,000		0
New Standard Energy Limited
Derivative [Line Items]
Proceeds from sale of available-for-sales securities		$ 500,000	AUD 0.7
Available-for-sale securities, gross realized gains		$ 100,000
Series C Preferred Stock | Green Hunter Energy
Derivative [Line Items]
Consideration received, value of preferred stock received						1,300,000						80,961	1,300,000
Series C Preferred Stock | Hunter Disposal LLC | Green Hunter Energy
Derivative [Line Items]
Consideration received, cumulative preferred dividend rate on preferred stock received (as a percent)				10.00%
Common Stock | Hunter Disposal LLC | Green Hunter Energy
Derivative [Line Items]
Consideration received, value of preferred stock received						$ 1,300,000						$ 200,000	$ 1,300,000
New Standard Energy Texas LLC | Eagle Ford Shale Assets
Derivative [Line Items]
Consideration received, number of shares of common stock received | shares																	65,650,000
Consideration received, common stock value																	$ 9,400,000
Disposal group including discontinued operation price of stock on sale date (in dollars per share) | $ / shares																	$ 0.14
Eureka Midstream Holdings
Derivative [Line Items]
Ownership percentage by parent						48.60%						44.53%	48.60%			48.60%
Eureka Midstream Holdings | Morgan Stanley Infrastructure (MSI)
Derivative [Line Items]
Retained interest upon deconsolidation						$ 347,292,000							$ 347,292,000			$ 347,300,000
New Standard Energy Limited
Derivative [Line Items]
Other-than-temporary impairment reclassified from AOCI					$ 9,000,000
Redstar Gold Corp
Derivative [Line Items]
Other-than-temporary impairment reclassified from AOCI										$ 400,000
Redstar Gold Corp | Common Stock
Derivative [Line Items]
Investment owned, balance (in shares) | shares												2,619,981
Investment in affiliates, equity method						$ 90,120						$ 75,581	$ 90,120
Senior Revolving Credit Facility | Line of Credit | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Derivative [Line Items]
Proceeds from termination of commodity derivative positions expected															$ 11,800,000
Commodity derivative | Bank Of Montreal
Derivative [Line Items]
Proceeds from hedge, investing activities	$ 900,000

LONG-TERM DEBT - Summary Of Lon

LONG-TERM DEBT - Summary Of Long-term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total long-term debt, outstanding	$ 1,060,640	$ 948,733
Less: current portion	(83,682)	(10,770)
Less: debtor-in-possession financing	(40,000)	0
Liabilities Subject to Compromise	(936,958)	0
Total long-term debt obligations not subject to compromise, net of current portion	0	937,963
Line of Credit | Senior Revolving Credit Facility | MHR Senior Revolving Credit Facility
Debt Instrument [Line Items]
Total long-term debt, outstanding	0	0
Line of Credit | Senior Revolving Credit Facility | Senior Secured Bridge Financing Facility
Debt Instrument [Line Items]
Total long-term debt, outstanding	$ 70,000	0
Interest rate (as a percent)	4.20%
Line of Credit | Senior Revolving Credit Facility | Debtor-in-Possession Credit Facility
Debt Instrument [Line Items]
Total long-term debt, outstanding	$ 40,000	0
Interest rate (as a percent)	9.00%
Term Loan | Second Lien Term Loan due October 22, 2019, interest rate of 8.5%, net of unamortized discount of $10.0 million at December 31, 2014
Debt Instrument [Line Items]
Total long-term debt, outstanding	$ 335,853	$ 329,140
Interest rate (as a percent)		8.50%
Senior notes payable, unamortized discount (in dollars)		$ 10,000
Senior Notes | Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.6 million at December 31, 2014
Debt Instrument [Line Items]
Total long-term debt, outstanding	599,305	$ 597,355
Interest rate (as a percent)		9.75%
Senior notes payable, unamortized discount (in dollars)		$ 2,600
Note Payable | Various equipment and real estate notes payable with maturity dates April 2016 - November 2017, interest rates of 4.25% - 8.70%
Debt Instrument [Line Items]
Total long-term debt, outstanding	$ 15,482	$ 22,238
Interest rate, low end of the range (as a percent)	4.25%	4.25%
Interest rate, high end of the range (as a percent)	8.70%	8.70%

LONG-TERM DEBT - Expected Annua

LONG-TERM DEBT - Expected Annual Maturities of Debt (Details) $ in Thousands	Dec. 31, 2015USD ($)
Debt Disclosure [Abstract]
2,016	$ 1,060,640
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	0
Total	$ 1,060,640

LONG-TERM DEBT - MHR Senior Rev

LONG-TERM DEBT - MHR Senior Revolving Credit Facility (Details) - USD ($)	Nov. 02, 2015	Oct. 22, 2014	Dec. 31, 2015	Sep. 30, 2015	Sep. 08, 2015	Aug. 07, 2015
Debt Instrument [Line Items]
Accounts payable, net (in excess of 180 days outstanding)						$ 1,400,000
Line of Credit | Term Loan | Second Lien Term Loan Agreement
Debt Instrument [Line Items]
Borrowing base		$ 340,000,000
Accounts payable, net (in excess of 180 days outstanding)					$ 1,400,000
Line of Credit | Revolving Credit Facility | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Borrowing base		50,000,000
Borrowing capacity increase limit		$ 250,000,000
Present value of proved oil and gas reserves lien, percent		90.00%
Present value of proved oil and gas reserves lien, discount rate, percent		10.00%
Line of Credit | Revolving Credit Facility | Fifth Amendment
Debt Instrument [Line Items]
Number of days accounts payable outstanding				90 days
Line of Credit | Letter of Credit | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Borrowing base		$ 50,000,000
Commitment fee percentage		0.50%
Credit Agreement Amendment Period July 10, 2015 Through December 31, 2015 | Line of Credit | Revolving Credit Facility | Fifth Amendment
Debt Instrument [Line Items]
Number of days accounts payable outstanding			180 days
Number of days to cure technical default			30 days
Federal Funds Rate | Line of Credit | Revolving Credit Facility | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Basis spread on variable rate		0.50%
London Interbank Offered Rate (LIBOR) | Line of Credit | Revolving Credit Facility | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Basis spread on variable rate		1.00%
Bank Of Montreal | Commodity
Debt Instrument [Line Items]
Proceeds from termination of open commodity derivative positions	$ 900,000
Minimum | London Interbank Offered Rate (LIBOR) | Line of Credit | Revolving Credit Facility | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Basis spread on variable rate		2.00%
Minimum | Alternate Base Rate | Line of Credit | Revolving Credit Facility | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Basis spread on variable rate		1.00%
Maximum | London Interbank Offered Rate (LIBOR) | Line of Credit | Revolving Credit Facility | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Basis spread on variable rate		3.00%
Maximum | Alternate Base Rate | Line of Credit | Revolving Credit Facility | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Basis spread on variable rate		2.00%

LONG-TERM DEBT - Senior Secured

LONG-TERM DEBT - Senior Secured Bridge Financing Facility (Details) - USD ($)	Nov. 03, 2015	Dec. 31, 2015	Nov. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Outstanding borrowings		$ 1,060,640,000		$ 948,733,000
Line of Credit | MHR Senior Revolving Credit Facility
Debt Instrument [Line Items]
Repayments of debt	$ 5,000,000
Line of Credit | Senior Secured Bridge Financing Facility
Debt Instrument [Line Items]
Proceeds from other debt	16,000,000
Principal amount	$ 60,000,000
Number of days accounts payable outstanding	180 days
Line of Credit | Senior Secured Bridge Financing Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate		4.00%
Line of Credit | Senior Secured Bridge Financing Facility | Prime Rate
Debt Instrument [Line Items]
Basis spread on variable rate		3.00%
Term Loan | Senior Secured Bridge Financing Facility
Debt Instrument [Line Items]
Principal amount			$ 10,000,000
Borrowing base	$ 10,000,000
Other Assets | Letter of Credit | Senior Secured Bridge Financing Facility
Debt Instrument [Line Items]
Cash collateral	$ 39,000,000

LONG-TERM DEBT - Debtor-in-Poss

LONG-TERM DEBT - Debtor-in-Possession Credit Facility (Details) - Line of Credit - Term Loan	Jan. 14, 2016USD ($)$ / MillionsofBTU	Dec. 16, 2015USD ($)
DIP Facility
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 200,000,000
First DIP Draw
Debt Instrument [Line Items]
Maximum borrowing capacity		40,000,000
Second DIP Draw
Debt Instrument [Line Items]
Maximum borrowing capacity		100,000,000
Third DIP Draw
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 60,000,000
Subsequent Event | Second DIP Draw
Debt Instrument [Line Items]
Repayments of debt	$ 70,200,000
Subsequent Event | Debtor-in-Possession Credit Facility
Debt Instrument [Line Items]
Amount available for general corporate purposes	$ 25,500,000
Commitment fee percentage	2.00%
Backstop fee, percent of common equity	3.00%
Obligations secured by perfected first priority (Priming Liens)	$ 70,000,000
Consecutive trading period (in days) natural gas prices are below $1.65 per MMBtu	15 days
Natural gas prices threshold ($1.65 per MMBtu) | $ / MillionsofBTU	1.65
Budget variance covenant, percentage threshold on receipts, disbursements and capital expenditures	20.00%
Conversion into common equity of reorganized Company at discount to Plan value (percent)	25.00%
Subsequent Event | Debtor-in-Possession Credit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	8.00%
Interest rate floor	1.00%
Subsequent Event | Debtor-in-Possession Credit Facility | Current Interest Rate
Debt Instrument [Line Items]
Basis spread on variable rate, upon event of default	2.00%
Specified Tranche A Lenders | Subsequent Event | Debtor-in-Possession Credit Facility
Debt Instrument [Line Items]
Right to purchase as percent of funded and unfunded facility	15.00%
Period irrevocable notice of intent to purchase	10 days
Period purchase is complete	5 days

LONG-TERM DEBT - Second Lien Te

LONG-TERM DEBT - Second Lien Term Loan (Details)	Oct. 22, 2014USD ($)	Dec. 31, 2015USD ($)	Sep. 08, 2015USD ($)	Aug. 07, 2015USD ($)	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Accounts payable, net (in excess of 180 days outstanding)				$ 1,400,000
Long-term debt		$ 1,060,640,000			$ 948,733,000
Term Loan | Second Lien Term Loan due October 22, 2019, interest rate of 8.5%, net of unamortized discount of $10.0 million at December 31, 2014
Debt Instrument [Line Items]
Long-term debt, unamortized discount					10,000,000
Long-term debt		$ 335,853,000			$ 329,140,000
Term Loan | Line of Credit | Second Lien Term Loan Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 340,000,000
Long-term debt, unamortized discount	$ 10,200,000
Periodic amortization, principal, percent	1.00%
Amount outstanding in addition to loans repaid or prepaid, threshold	$ 50,000,000
Indebtedness threshold, percent of adjusted consolidated net tangible assets	25.00%
Accounts payable, net (in excess of 180 days outstanding)			$ 1,400,000
Fiscal Quarter Ending December 31, 2014 | Term Loan | Line of Credit | Second Lien Term Loan Agreement
Debt Instrument [Line Items]
Proved Reserves to secured debt ratio (not less than 1.5 to 1.0)	1.5
Proved developed and producing reserves to secured debt ratio (not less than 1.0 to 1.0)	1
Fiscal Quarter Ending March 31, 2016 And Any Fiscal Quarter Trailing Four-Quarter Period Then Ended | Term Loan | Line of Credit | Second Lien Term Loan Agreement
Debt Instrument [Line Items]
Leverage ratio limitation on netting of unencumbered cash	$ 100,000,000
Required maximum secured Net Debt to EBITDAX ratio	2.5
Option One | Term Loan | Line of Credit | Second Lien Term Loan Agreement | Federal Funds Rate
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
Option One | Term Loan | Line of Credit | Second Lien Term Loan Agreement | Adjusted One Month London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Option One | Term Loan | Line of Credit | Second Lien Term Loan Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate	6.50%
Option Two | Term Loan | Line of Credit | Second Lien Term Loan Agreement
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%
Option Two | Term Loan | Line of Credit | Second Lien Term Loan Agreement | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	7.50%

LONG-TERM DEBT - Senior Notes (

LONG-TERM DEBT - Senior Notes (Details) - USD ($) $ in Thousands	Nov. 15, 2015	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt		$ 1,060,640	$ 948,733
Senior Notes | 9.75% Senior Notes Due May 15, 2020
Debt Instrument [Line Items]
Interest payment	$ 29,300
Long-term debt		$ 599,305	$ 597,355

LONG-TERM DEBT - Equipment and

LONG-TERM DEBT - Equipment and Building Notes Payable (Details) - USD ($)	Jan. 23, 2014	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2014
Debt Instrument [Line Items]
Long-term debt		$ 1,060,640,000	$ 948,733,000
Note Payable | 7.94% Equipment Note Payable
Debt Instrument [Line Items]
Principal amount	$ 5,600,000
Interest rate (as a percent)	7.94%
Term of debt instrument	48 months
Claim threshold in the event of default to accelerate financial obligation	$ 1,000,000
Note Payable | 4.875% Building Note Payable
Debt Instrument [Line Items]
Principal amount				$ 3,800,000
Interest rate (as a percent)				4.875%
Current Portion Of Long-term Debt | Note Payable | 7.94% Equipment Note Payable
Debt Instrument [Line Items]
Long-term debt		2,800,000
Current Portion Of Long-term Debt | Note Payable | 4.875% Building Note Payable
Debt Instrument [Line Items]
Long-term debt		$ 3,600,000

LONG-TERM DEBT - Interest Expen

LONG-TERM DEBT - Interest Expense (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Interest expense incurred on debt, net of amounts capitalized		$ 91,032,000	$ 76,784,000	$ 67,803,000
Amortization and write-off of deferred financing costs		8,527,000	9,679,000	4,818,000
Interest Expense, Debt		99,559,000	86,463,000	72,621,000
Write off of deferred debt issuance cost	$ 2,700,000
MHR Senior Revolving Credit Facility Amendment, July 10, 2015
Debt Instrument [Line Items]
Write off of deferred debt issuance cost		1,100,000
MHR Senior Revolving Credit Facility Amendment, November 3, 2015
Debt Instrument [Line Items]
Write off of deferred debt issuance cost		$ 900,000
Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Write off of deferred debt issuance cost	1,700,000
Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Write off of deferred debt issuance cost	$ 1,400,000
Term Loan | 12.5% Term Loan due August 16, 2018
Debt Instrument [Line Items]
Prepayment penalty			2,200,000
Oil and natural gas properties
Debt Instrument [Line Items]
Interest costs capitalized, minimum time period for capitalization		6 months
Eureka Hunter Holdings Gas Gathering System
Debt Instrument [Line Items]
Interest costs capitalized		$ 0	$ 2,000,000	$ 2,600,000

SHARE-BASED COMPENSATION Stock

SHARE-BASED COMPENSATION Stock Option and Stock Appreciation Rights Activity (Details) - Stock Options and Stock Appreciation Rights - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement by Share Based Payment Award [Roll Forward]
Outstanding at beginning of the year	13,194,956	16,891,419	14,846,994
Weighted Average Exercise Price, beginning of the year	$ 5.91	$ 5.69	$ 6.01
Granted	0	0	4,937,575
Weighted Average Exercise Price, Granted	$ 0	$ 0	$ 4.11
Exercised	(100,000)	(2,375,273)	(1,466,025)
Weighted Average Exercise Price, Exercised	$ 0.51	$ 4.09	$ 3.66
Forfeited or expired	(5,780,205)	(1,321,190)	(1,427,125)
Weighted Average Exercise Price, Forfeited or Expired	$ 6.24	$ 6.27	$ 5.51
Outstanding at end of the year	7,314,751	13,194,956	16,891,419
Weighted Average Exercise Price, end of the year	$ 5.75	$ 5.91	$ 5.69
Exercisable at end of the year	6,721,950	9,140,323	9,983,743
Weighted Average Exercise Price, Exercisable at end of year	$ 5.89	$ 6.22	$ 5.96

SHARE-BASED COMPENSATION Non-Ve

SHARE-BASED COMPENSATION Non-Vested Common Stock (Details) - Stock Options and Stock Appreciation Rights - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at beginning of the year	4,054,633	6,907,476	6,163,372
Granted	0	0	4,937,575
Vested	(1,635,365)	(1,915,526)	(3,133,700)
Forfeited	(1,826,467)	(937,317)	(1,059,771)
Non-vested at end of the year	592,801	4,054,633	6,907,476

SHARE-BASED COMPENSATION Fair V

SHARE-BASED COMPENSATION Fair Value Assumptions (Details) - Common stock options	12 Months Ended
	Dec. 31, 2013$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value per option granted during the period	$ 2.52
Weighted average stock price volatility	80.61%
Weighted average risk free rate of return	0.78%
Weighted average estimated forfeiture rate	2.45%
Weighted average expected term	4 years 7 months 24 days

SHARE-BASED COMPENSATION Non-96

SHARE-BASED COMPENSATION Non-Vested Common Shares Granted Under the Stock Incentive Plan (Details) - Common Stock - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at beginning of the year	2,352,013	27,500	65,025
Weighted Average Share Price, beginning of the year	$ 5.99	$ 7.24	$ 6.09
Granted (in shares)	3,468,833	3,239,796	210,494
Weighted Average Share Price, Granted	$ 1.24	$ 5.66	$ 4.66
Forfeited	(847,514)	(135,000)	0
Weighted Average Share Price, Forfeited	$ 5.92	$ 7.26	$ 0
Vested	(1,583,436)	(780,283)	(248,019)
Weighted Average Share Price, Vested	$ 4.51	$ 4.48	$ 4.75
Non-vested at end of the year	3,389,896	2,352,013	27,500
Weighted Average Share Price, end of the year	$ 2.92	$ 5.99	$ 7.24
Compensation cost not yet recognized	$ 5.2	$ 9.7	$ 0.2
Unrecognized compensation cost, period for recognition	2 years 11 days

SHARE-BASED COMPENSATION Narrat

SHARE-BASED COMPENSATION Narratives (Details) - USD ($)	Sep. 01, 2015	Jun. 18, 2015	Mar. 30, 2015	Nov. 06, 2014	May. 12, 2014	Jan. 08, 2014	Dec. 31, 2014	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation									$ 6,000,000	$ 11,400,000	$ 13,600,000
Fair value of shares granted									$ 5,700,000	$ 11,363,000	$ 13,624,000
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period				1 year		1 year
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)								205,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period								3 years
Aggregate grant date fair value								$ 300,000
Weighted average estimated forfeiture rate								5.60%
Stock Options and Stock Appreciation Rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number outstanding (shares)							13,194,956		7,314,751	13,194,956	16,891,419	14,846,994
Non-vested number outstanding (shares)							4,054,633		592,801	4,054,633	6,907,476	6,163,372
Compensation cost not yet recognized							$ 3,200,000		$ 200,000	$ 3,200,000	$ 14,100,000
Unrecognized compensation cost, period for recognition									1 month 17 days
Non-vested intrinsic value									$ 0
Outstanding weighted average remaining contractual term									5 years 3 months 29 days
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested number							2,352,013		3,389,896	2,352,013	27,500	65,025
Granted (in shares)									3,468,833	3,239,796	210,494
Compensation cost not yet recognized							$ 9,700,000		$ 5,200,000	$ 9,700,000	$ 200,000
Unrecognized compensation cost, period for recognition									2 years 11 days
Amended And Restated Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized									27,500,000
Amended And Restated Stock Incentive Plan | Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued									11,539,043
Eureka Hunter Holdings, LLC Management Incentive Compensation Plan | Common Class B
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized					2,336,905
Granted (in shares)					894,102		413,110
Eureka Hunter Holdings, LLC Management Incentive Compensation Plan | Incentive Plan Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized					2,336,905
Granted (in shares)					894,102		413,110
Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares granted			$ 1,400,000
Board of Directors | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options, grants in period				216,348		123,798
Vesting Rights Percentage						100.00%
Restricted stock award, net of forfeitures									$ 18,500,000
Weighted average estimated forfeiture rate									3.40%
Board of Directors | Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)									128,559	105,812	182,994
Officers Executives and Employees | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options, grants in period				1,451,500		1,312,575	65,000		3,275,033
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period				3 years		3 years
Vesting Rights Percentage				33.00%		33.00%
Vesting period for one third of shares				1 year		1 year
Incremental compensation cost							$ 2,600,000
Officers Executives and Employees | Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			535,274
Board Of Directors, Non Employee Members | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		600,000
Fair value of shares granted		$ 700,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		2 years
Award vesting period upon change in control of company		6 months
Weighted average estimated forfeiture rate		5.60%
Newly Hired Officer | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	2,000,000
Fair value of shares granted	$ 1,500,000
Weighted average estimated forfeiture rate	5.60%

SHAREHOLDERS' EQUITY - Warrant

SHAREHOLDERS' EQUITY - Warrant Activity (Details)	12 Months Ended
	Dec. 31, 2015shares$ / warrant	Dec. 31, 2014shares$ / warrant	Dec. 31, 2013shares$ / warrant
Changes in warrant activity
Shares, Outstanding at beginning of year | shares	19,173,480	17,169,010	13,376,277
Shares, Granted | shares	0	2,142,858	17,030,622
Shares, Exercised, forfeited, or expired | shares	0	(138,388)	(13,237,889)
Shares, Outstanding at end of year | shares	19,173,480	19,173,480	17,169,010
Shares, Exercisable at end of year | shares	2,142,858	2,142,858	138,388
Changes in weighted-average exercise price
Weighted-Average Exercise Price, Outstanding at beginning of period (in dollars per share) | $ / warrant	8.50	8.56	10.56
Weighted-Average Exercise Price, Granted | $ / warrant	0	8.50	8.50
Weighted-Average Exercise Price, Exercised, forfeited, or expired (in dollars per share) | $ / warrant	0	16.28	10.50
Weighted-Average Exercise Price, Outstanding at end of period (in dollars per share) | $ / warrant	8.50	8.50	8.56
Weighted-Average Exercise Price, Exercisable at end of year (in dollars per share) | $ / warrant	8.50	8.50	16.28

SHAREHOLDERS' EQUITY - Preferre

SHAREHOLDERS' EQUITY - Preferred Dividends Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Dividends on preferred stock	$ 33,817	$ 54,707	$ 56,705
Series C Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	9,792	10,248	10,248
Series D Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	16,911	17,698	17,655
Series E Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	7,114	7,418	7,561
Eureka Midstream Holdings | Series A Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	0	12,760	14,323
Accretion of the difference between the carrying value and the redemption value of preferred stock included in dividends	$ 0	$ 6,583	$ 6,918

SHAREHOLDERS' EQUITY - Schedule

SHAREHOLDERS' EQUITY - Schedule of Potentially Dilutive Securities (Details) - Dilutive [Member] - shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	41,257	45,683	45,034
Series E Preferred Stock
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	11,126	10,946	10,946
Warrant
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	19,173	19,173	17,169
Restricted Stock
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	3,643	2,369	28
Common stock options
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	7,315	13,195	16,891

SHAREHOLDERS' EQUITY - Narrativ

SHAREHOLDERS' EQUITY - Narratives (Details)	May. 09, 2014USD ($)shares$ / shares$ / warrant	Mar. 31, 2014USD ($)$ / sharesshares	Aug. 26, 2013USD ($)$ / sharesshares	May. 03, 2011USD ($)shares	Dec. 14, 2015USD ($)	Dec. 31, 2014shares$ / shares	Dec. 31, 2015USD ($)shares$ / shares$ / warrant	Dec. 31, 2014USD ($)shareswarrant$ / shares	Dec. 31, 2013USD ($)shareswarrant$ / shares	Dec. 31, 2008USD ($)	Mar. 13, 2015USD ($)	Jul. 24, 2014	Apr. 02, 2012USD ($)shares
Common Stock [Abstract]
Common stock issued in connection with share-based compensation (in shares) | shares							1,383,449	657,317	182,994
Common stock issued upon warrant exercise (in shares) | shares							100,000	2,375,273	1,466,025
Proceeds from exercise of common stock options							$ 100,000	$ 9,700,000	$ 5,400,000
Proceeds from stock issuance							0	0	10,072,000
Gross proceeds from stock issuance							$ 58,229,000	$ 178,410,000
Common stock, shares issued | shares						201,420,701	261,397,232	201,420,701
Net proceeds from sale of common stock							$ 58,229,000	$ 178,410,000	0
ESOP compensation expense							$ 1,900,000	$ 1,600,000	$ 1,200,000
Common Stock Warrants [Abstract]
Number of days notice required for redemption by company							30 days
Common stock warrants shares exercisable | shares						2,142,858	2,142,858	2,142,858	138,388
Warrants outstanding							$ 0
Weighted average remaining contract life							3 months
Common Stock Warrant
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share) | $ / shares	$ 8.5
Redemption price of warrants (in dollars per share) | $ / warrant	0.001
Number of warrants exercised | shares	2,142,858
Class of warrant or right, redemption period notice	30 days
$10.50 Common stock warrants
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share) | $ / shares									$ 10.50
Number of warrants exercised | warrant									13,237,889
$15.13 Common stock warrants
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share) | $ / shares						$ 15.13		$ 15.13
Number of warrants exercised | warrant								97,780
$19.04 Common stock warrants
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share) | $ / shares						$ 19.04		$ 19.04
Number of warrants exercised | warrant								40,608
Eureka Midstream Holdings
Non-controlling Interests [Abstract]
Percent ownership of subsidiaries							48.60%
PRC Williston, Inc.
Non-controlling Interests [Abstract]
Equity participation agreement, percentage of distributions paid to PRC Williston payable to lenders										12.50%
Value of equity participation agreements										$ 3,400,000
Percent ownership of subsidiaries												100.00%
Common Stock
Common Stock [Abstract]
Common stock issued (in dollars per share) | $ / shares	$ 7
Stock issued (in shares) | shares	21,428,580
Gross proceeds from stock issuance	$ 149,700,000
Common Stock Warrants [Abstract]
Warrants issued | shares			17,030,622
Exercise price of warrants (in dollars per share) | $ / shares			$ 8.50
Warrants fair value			$ 21,600,000
Redemption price of warrants (in dollars per share) | $ / warrant							0.001
Common Stock | Magnum Hunter Resources Corporation
Common Stock [Abstract]
Common stock issued as a matching contribution to the Employee Stock Ownership Plan (in shares) | shares							2,290,565	249,531	221,170
Obligation to make future contributions to the plan							$ 0
Shares in ESOP | shares							2,797,554
Exchangeable common stock | NuLoch Resources
Exchangeable Common Stock [Abstract]
Exchangeable shares issued for acquisition of NuLoch Resources (in shares) | shares				4,275,998
Number of shares of common stock exchaged by each exchangeable share | shares				1
Exchangeable shares issued for acquisition of NuLoch Resources				$ 31,600,000
Exchangeable stock, time period from issuance the shares are redeemable							1 year
Common stock issued upon exchange of MHR Exchangeco Corporation's exchangeable shares (in shares) | shares								505,835
Series C Preferred Stock
Cumulative Perpetual Preferred Stock [Abstract]
Preferred stock par value (in dollars per share) | $ / shares							$ 0.01
Cumulative dividend rate for cumulative preferred stock (as a percent)							10.25%
Accrued preferred dividends					$ 2,100,000
Non-controlling Interests [Abstract]
Common units issued | shares						4,000,000	4,000,000	4,000,000
Series D Preferred Stock
Common Stock [Abstract]
Proceeds from stock issuance								$ 9,600,000
Stock issued (in shares) | shares								216,068
Offering expenses								$ 1,200,000
Cumulative Perpetual Preferred Stock [Abstract]
Preferred stock par value (in dollars per share) | $ / shares							$ 0.01
Preferred Stock, liquidation preference (in dollars per share) | $ / shares						$ 50	$ 50	$ 50
Cumulative dividend rate for cumulative preferred stock (as a percent)						8.00%	8.00%	8.00%
Accrued preferred dividends					3,600,000
Depositary shares
Class of Stock [Line Items]
Interest in series E Preferred Stock per share							0.001
Common Stock [Abstract]
Common stock issued in connection with acquisition (in shares) | shares		4,300,000						27,906
Common stock issued (in dollars per share) | $ / shares		$ 7				$ 24.24		$ 24.24
Proceeds from stock issuance		$ 28,900,000						$ 590,000
Cumulative Perpetual Preferred Stock [Abstract]
Preferred Stock, liquidation preference (in dollars per share) | $ / shares							$ 25
Cumulative dividend rate for cumulative preferred stock (as a percent)							8.00%
Conversion price (in dollars per share) | $ / shares							$ 8.50
Series A Preferred Stock | Eureka Midstream Holdings
Non-controlling Interests [Abstract]
Common units issued | shares													622,641
Value of common units issued related to acquisitions													$ 12,500,000
Series E Preferred Stock
Cumulative Perpetual Preferred Stock [Abstract]
Preferred stock par value (in dollars per share) | $ / shares							0.01
Preferred Stock, liquidation preference (in dollars per share) | $ / shares						$ 25,000	$ 25,000	$ 25,000
Cumulative dividend rate for cumulative preferred stock (as a percent)							8.00%	8.00%
Conversion price (in dollars per share) | $ / shares							$ 8.50
Accrued preferred dividends					$ 1,500,000
Universal Shelf Registration Statement Form S3
Common Stock [Abstract]
Shelf registration maximum offering											$ 500,000,000
Common stock, shares issued | shares							56,202,517
Net proceeds from sale of common stock							$ 58,200,000
Offering expenses							$ 1,300,000

REEDEMABLE PREFERRED STOCK (Det

REEDEMABLE PREFERRED STOCK (Details) $ / shares in Units, $ in Thousands	Oct. 03, 2014USD ($)	Dec. 14, 2015USD ($)	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)shares	Apr. 02, 2012shares	Mar. 21, 2012USD ($)	Dec. 14, 2011$ / shares
Class of Stock [Line Items]
Proceeds from sale of Series A preferred units in Eureka Midstream Holdings			$ 0	$ 11,956	$ 35,280
Proceeds from stock issuance			0	0	10,072
Preferred stock, cash dividends paid			33,817	54,707	56,705
Preferred stock, dividends paid-in-kind				1,950	8,243
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units			$ 0	$ (51,692)	0
Series C Preferred Stock
Class of Stock [Line Items]
Preferred stock par value per share | $ / shares			$ 0.01
Preferred Stock, liquidation preference (in dollars per share) | $ / shares			$ 25	$ 25
Temporary equity dividend rate percentage			10.25%	10.25%
Preferred stock, redemption price per share at the Company's option | $ / shares								$ 25
Preferred stock, redemption price per share in the event of a change of control | $ / shares			$ 25
Accrued preferred dividends		$ 2,100
Preferred stock, shares issued | shares			4,000,000	4,000,000
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock, cash dividends paid				$ 10,200	5,200
Preferred stock, dividends accrued					3,900
Preferred stock, dividends paid-in-kind				$ 1,900	$ 8,200
Preferred stock issued as in-kind payment (in shares) | shares				97,492	412,157
Series A Preferred Stock | Maximum | March 31, 2012 through March 31, 2013
Class of Stock [Line Items]
Percentage of dividend owed paid in kind			75.00%
Series A Preferred Stock | Maximum | June 30, 2013 through March 31, 2014
Class of Stock [Line Items]
Percentage of dividend owed paid in kind			50.00%
Series A Preferred Stock | Eureka Midstream Holdings
Class of Stock [Line Items]
Temporary equity dividend rate percentage			8.00%
Preferred stock, shares issued | shares						622,641
Cumulative dividend rate for cumulative preferred stock increased (as a percent)			10.00%
Conversion ratio (as a percent)			1
Series A-2 Units
Class of Stock [Line Items]
Preferred units outstanding	$ 389,000
Level 3 | Embedded Derivatives, Liabilities | Convertible preferred stock derivative liabilities
Class of Stock [Line Items]
Conversion of Eureka Midstream Holdings Series A Preferred Units to Series A-2 Units	$ 173,205			$ 173,205
Ridgeline | Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock, maximum purchase commitment pursuant to Unit Purchase Agreement							$ 200,000
Ridgeline | Series A Preferred Stock | Eureka Midstream Holdings
Class of Stock [Line Items]
Proceeds from sale of Series A preferred units in Eureka Midstream Holdings			$ 200,000
Preferred stock, shares issued | shares				610,000	1,800,000
Proceeds from stock issuance				$ 12,000	$ 35,300

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred income tax expense (benefit)
Federal	$ 0	$ 0	$ (78,743)
State	0	0	(6,664)
Total deferred tax benefit	0	0	(85,407)
Total continuing operations	0	0	(85,407)
Valuation allowance	509,100
Reconciliation of income tax expense (benefit)
Income tax benefit at statutory U.S. rate	(274,355)	(48,242)	(111,132)
State income taxes (net of federal benefit)	(28,930)	(3,616)	(4,331)
Tax effect of permanent differences	224	(498)	750
Provision to return adjustment	0	(11,736)	0
Foreign statutory tax rate differences	(9)	297	0
Tax effect of loss attributable to non-controlled interest	0	1,279	346
Tax benefit recognized as tax expense in discontinued operations	0	0	(28,989)
Change in valuation allowance	302,373	63,341	58,341
Other	697	(825)	(392)
Total continuing operations	0	0	(85,407)
Discontinued operations	0	0	11,773
Total tax benefit	0	0	(73,634)
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest [Abstract]
Domestic	(783,963)	(134,853)	(317,520)
Foreign	91	(2,980)	0
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	(783,872)	(137,833)	(317,520)
Gain (loss) from discontinued operations	0	4,561	(62,655)
Gain (loss) on disposal of discontinued operations	0	(13,855)	83,378
Loss before income tax	(783,872)	(147,127)	(296,797)
Deferred tax assets:
Net operating loss carry forwards	371,531	263,452	155,507
Property and equipment	162,236	63,823	0
Capital loss carry forward	76,955	38,401	0
Share-based compensation	17,293	15,035	10,156
Depletion carry forwards	1,047	1,047	1,047
Tax credits	53	53	53
US investment in Canada	0	0	74,148
Other	15,354	1,562	561
Deferred tax liabilities:
Property and equipment	0	0	(90,950)
Valuation allowance
Tax credits	(53)	(53)	(53)
Depletion carry forwards	(1,047)	(1,047)	(1,047)
Capital loss carry forward	(76,955)	(38,401)	0
Net operating losses	(371,531)	(263,452)	(155,507)
Other	(59,552)	96,186	80,233
US investment in Canada	0	0	(74,148)
Net deferred tax asset (liability)	0	0	0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at January 1	3,879	3,879	3,879
Change in unrecognized tax benefits taken during a prior period	0	0	0
Change in unrecognized tax benefits taken during the current period (netted against the US net operating loss)	0	0	0
Decreases in unrecognized tax benefits from settlements with taxing authorities	0	0	0
Reductions to unrecognized tax benefits from lapse of statutes of limitations	0	0	0
Unrecognized tax benefits at December 31	3,879	3,879	3,879
NOL from excess stock based compensation deductions
Deferred income tax expense (benefit)
Net operating loss carry forwards	38,100
Deferred tax assets:
Net operating loss carry forwards	14,800
U.S. federal income tax
Deferred income tax expense (benefit)
Net operating loss carry forwards	1,031,000	710,000
Depletion carryover	2,800
Depletion carryover, tax effected	1,100
Eureka Midstream Holdings
Deferred tax liabilities:
Investment in Eureka Midstream Holdings	$ (135,331)	$ (176,606)	$ 0

MAJOR CUSTOMERS (Details)

MAJOR CUSTOMERS (Details) - Revenues - Customer concentration	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Samson Resources Company
Major customers
Concentration percentage	22.00%	24.00%	31.00%
Markwest Liberty Midstream
Major customers
Concentration percentage	14.00%	15.00%	6.00%
Tenaska Marketing Ventures
Major customers
Concentration percentage	11.00%	17.00%	10.00%
Baytex Energy USA LTD
Major customers
Concentration percentage	0.00%	7.00%	11.00%

RELATED PARTY TRANSACTIONS Bala

RELATED PARTY TRANSACTIONS Balances and Activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction
Liabilities Subject to Compromise	$ (1,096,071,000)	$ 0
Equity method investment	166,099,000	347,191,000
Gain on deconsolidation of Eureka Midstream Holdings, LLC	0	509,563,000	$ 0
Gain on dilution of interest in Eureka Midstream Holdings, LLC	4,601,000	0	0
Loss from equity method investments	186,157,000	1,038,000	994,000
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units	0	(51,692,000)	0
Other-than-temporary impairment reclassified from AOCI	$ 10,183,000	0	0
Term of consulting agreement	12 months
Share-based compensation	$ 7,578,000	12,469,000	13,624,000
GreenHunter Resources, Inc.
Related Party Transaction
Accounts receivable, net of reserve	0	21,000
Accounts Payable	(24,000)	(249,000)
Liabilities Subject to Compromise	(635,000)	0
Derivative assets	0	75,000
Investments	81,000	1,311,000
Notes receivable, net of reserve	0	1,224,000
Notes receivable	680,300,000
Prepaid expenses	5,000	1,000,000
Interest Income	113,000	154,000	205,000
Loss from equity method investments	464,000	590,000	730,000
Capitalized costs incurred	508,000	3,149,000	0
Other-than-temporary impairment reclassified from AOCI	800,000
GreenHunter Resources, Inc. | Production costs
Related Party Transaction
Related party expenses	3,675,000	4,973,000	3,315,000
GreenHunter Resources, Inc. | Midstream natural gas gathering, processing, and marketing
Related Party Transaction
Related party expenses	0	652,000	0
GreenHunter Resources, Inc. | Oilfield services
Related Party Transaction
Related party expenses	298,000	0	0
GreenHunter Resources, Inc. | General and administrative
Related Party Transaction
Related party expenses	23,000	44,000	13,000
GreenHunter Resources, Inc. | Miscellaneous income
Related Party Transaction
Miscellaneous income (expense)	(620,000)	220,000	$ 220,000
Pilatus Hunter
Related Party Transaction
Accounts receivable, net of reserve	$ 12,000	$ 12,000
Percentage of ownership in related party by member of management	100.00%	100.00%	100.00%
Pilatus Hunter | General and administrative
Related Party Transaction
Related party expenses	$ 143,000	$ 281,000	$ 166,000
Eureka Midstream Holdings
Related Party Transaction
Accounts receivable, net of reserve	5,467,000	2,898,000
Accounts Payable	(1,480,000)	(2,776,000)
Liabilities Subject to Compromise	(15,827,000)	0
Equity method investment	166,099,000	347,191,000
Gain on deconsolidation of Eureka Midstream Holdings, LLC	0	509,563,000	0
Gain on dilution of interest in Eureka Midstream Holdings, LLC	4,601,000	0	0
Loss from equity method investments	(185,693,000)	(448,000)	0
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units	0	51,692,000	0
Capitalized costs incurred	121,000	0	0
Eureka Midstream Holdings | Production costs
Related Party Transaction
Related party expenses	1,181,000	0	0
Eureka Midstream Holdings | Oilfield services
Related Party Transaction
Related party expenses	34,000	0	0
Eureka Midstream Holdings | General and administrative
Related Party Transaction
Related party expenses	8,000	32,569,000	0
Eureka Midstream Holdings | Oil and natural gas sales
Related Party Transaction
Related party expenses	347,000	0	0
Eureka Midstream Holdings | Transportation, processing, and other related costs
Related Party Transaction
Related party expenses	24,865,000	353,000	0
Classic Petroleum, Inc.
Related Party Transaction
Accounts Payable	(51,000)	0
Capitalized costs incurred	206,000	1,495,000	0
Kirk Trosclair
Related Party Transaction
Monthly compensation	10,000
Compensation (including reimbursement of expenses)	169,000
Share-based compensation	163,423
Kirk Trosclair | General and administrative
Related Party Transaction
Related party expenses	$ 169,000	$ 0	$ 0

RELATED PARTY TRANSACTIONS Narr

RELATED PARTY TRANSACTIONS Narratives (Details)	Nov. 19, 2015USD ($)	May. 04, 2015USD ($)	Dec. 29, 2014USD ($)	Feb. 17, 2012	Dec. 31, 2015USD ($)shares$ / MMBTU	Dec. 31, 2014shares	Dec. 31, 2013shares	Nov. 10, 2015Well	Nov. 05, 2015USD ($)	Oct. 31, 2015USD ($)	Mar. 31, 2015USD ($)
Related Party Transaction
Term of consulting agreement					12 months
GreenHunter Resources, Inc.
Related Party Transaction
Accounts receivable, related parties					$ 66,000
Related party transaction rental agreement term				5 years
Related party transaction, rental agreement, prepayment			$ 1,000,000
Related party transaction, rental agreement, credit for services, percent			50.00%
Notes receivable					680,300,000
Note receivable, related parties, quarterly payment of principal					137,500
Note receivable, related parties, past due amount											$ 168,437
Repayment of notes receivable from related parties		$ 168,437
Kirk Trosclair
Related Party Transaction
Monthly compensation					10,000
Compensation (including reimbursement of expenses)					$ 169,000
Common Class A | Eureka Midstream Holdings | Chief Executive Officer
Related Party Transaction
Common units issued during period shares acquisitions | shares							27,641
Common Class B | Eureka Midstream Holdings | Chief Executive Officer
Related Party Transaction
Common units issued during period shares acquisitions | shares					250,049	250,049,000
Vested | shares					50,009	0
Eureka Hunter Pipeline Gas Gathering Agreement
Related Party Transaction
Payment of demand notice, assurance of performance security	$ 5,000,000
Eureka Hunter Pipeline Gas Gathering Agreement | Triad Hunter | Eureka Midstream Holdings
Related Party Transaction
Aggregate reservation fee | $ / MMBTU					1.05
Accounts payable, related parties, past due										$ 10,700,000
Cash collateral, demand notice, assurance of performance security									$ 20,800,000
Amended and Restated Gas Gathering Services Agreement
Related Party Transaction
Administrative service fee					$ 500,000
Margin on administrative services fee					1.50%
WEST VIRGINIA | Eureka Hunter Pipeline Gas Gathering Agreement
Related Party Transaction
Wells temporarily suspended | Well								40

COMMITMENTS AND CONTINGENCIES F

COMMITMENTS AND CONTINGENCIES Future Minimum Gathering, Processing and Transportation Commitments (Details) - Gathering, processing, and transportation commitments $ in Thousands	Dec. 31, 2015USD ($)
Other Commitments [Line Items]
2,016	$ 22,562
2,017	22,517
2,018	22,517
2,019	22,517
2,020	22,517
Thereafter	$ 123,943

COMMITMENTS AND CONTINGENCIE108

COMMITMENTS AND CONTINGENCIES Future Minimum Lease Commitments Under Non-Cancelable Operating Leases (Details) $ in Thousands	Dec. 31, 2015USD ($)
Future minimum base rentals of Transtex Hunter's non-cancelable leases
2,016	$ 605
2,017	488
2,018	154
2,020	53
2,019	0
Thereafter	$ 0

COMMITMENTS AND CONTINGENCIES N

COMMITMENTS AND CONTINGENCIES Narratives (Details) Mcfe in Thousands

Mar. 10, 2016USD ($)

Nov. 19, 2015USD ($)

Oct. 30, 2014USD ($)

Oct. 08, 2014USD ($)MMBTU

Oct. 03, 2014

Aug. 18, 2014USD ($)MMBTU

May. 28, 2014USD ($)

Nov. 02, 2012

Dec. 14, 2011

Sep. 26, 2008USD ($)

Jun. 30, 2014USD ($)

Dec. 31, 2015USD ($)atransaction$ / MMBTU

Dec. 31, 2015USD ($)aMMBTUMcfetransaction$ / MMBTU

Dec. 31, 2014USD ($)a

Dec. 31, 2013USD ($)a

Jan. 21, 2016USD ($)

Dec. 15, 2015MMBTU

Nov. 10, 2015Well

Nov. 05, 2015USD ($)

Oct. 31, 2015USD ($)

Oct. 21, 2014USD ($)

Jul. 01, 2014USD ($)

Aug. 12, 2013a

Partnership Interest Purchase Agreement Commitments | Hall-Houston Exploration II, L. P.

Commitments

Percentage sales of partnership interest purchase agreement

5.33%

Partnership interest sale cash consideration

$ 8,000,000

First call

1,400,000

Partnership interest sale reimbursement for first capital call

$ 754,255

Lease Commitments | Houston, Texas

Commitments

Lease cost

$ 34,000

Lease Commitments | Grapevine, Texas

Commitments

Lease cost

$ 30,500

Lease Commitments | Triad Hunter | Maximum

Commitments

Term of commitment

12 months

The Company, Triad Hunter, MNW vs. Dux Petroleum, LLC | Triad Hunter

Commitments

Litigation settlement, amount

$ 500,000

Utica Shale Assets Acquisition

Commitments

Net mineral acres acquired | a

32,000

Payments to acquire land

$ 24,600,000

Eureka Hunter Pipeline Gas Gathering Agreement

Commitments

Payment of demand notice, assurance of performance security

$ 5,000,000

Eureka Hunter Pipeline Gas Gathering Agreement | WEST VIRGINIA

Commitments

Wells temporarily suspended | Well

40

Well production of natural gas (Mcfe/d) | Mcfe

66

Texas Gas Transportation Services Agreement, MMBtu Per Day Of Transportation Capacity

Commitments

Remaining maximum liability

$ 12,800,000

Pipeline project, term of agreement

15 years

Acquired notional amount energy measure per day | MMBTU

100,000

REX Services Agreement, MMBtu Per Day Of Firm Transportation | Triad Hunter

Commitments

Remaining maximum liability

$ 8,700,000

Pipeline project, term of agreement

15 years

Acquired notional amount energy measure per day | MMBTU

100,000

50,000,000

Asset Purchase Agreement With MNW | Triad Hunter | Utica Shale, Ohio

Commitments

Acreage of undeveloped leasehold acquired (in acres) | a

2,665

2,665

16,456

5,922

Payments to acquire land

$ 12,000,000

$ 67,300,000

Escrow deposit disbursements related to property acquisition

$ 400,000

Total disbursements to MNW for net leasehold acres acquired

$ 104,300,000

Leasehold Acreage From MNW Energy, LLC

Commitments

Net leasehold acres purchased to date | a

25,044

25,044

Percentage of total leasehold acres purchased

78.30%

78.30%

Drilling Rig Purchase | Alpha Hunter Drilling LLC

Commitments

Purchase price of rig

$ 6,500,000

Deposit on rig purchased

$ 1,300,000

Write off of deposits and equipment

$ 2,700,000

Amended and Restated Gas Gathering Services Agreement

Commitments

Margin on administrative services fee

1.50%

Administrative service fee

$ 500,000

Credit Support Agreement With REX (Rockies Express Pipeline LLC) | Line of Credit | Letter of Credit | Triad Hunter

Commitments

Maximum borrowing capacity, required period

45 days

Maximum borrowing capacity

$ 36,900,000

Decrease in borrowing capacity (every 3 months)

$ 2,800,000

Period of incremental borrowing capacity decrease

3 months

Borrowing capacity, after reduction

20,000,000

$ 20,000,000

Period until additional borrowing capacity reduction

5 years

Period Between 14 Months After and 21 Months From August 18, 2014 | Credit Support Agreement With TGT | Line of Credit | Letter of Credit | Triad Hunter

Commitments

Maximum borrowing capacity

13,000,000

Period Between 21 Months After and 28 Months From August 18, 2014 | Credit Support Agreement With TGT | Line of Credit | Letter of Credit | Triad Hunter

Commitments

Maximum borrowing capacity

36,000,000

Period Beginning 28 Months After August 18, 2014 | Credit Support Agreement With TGT | Line of Credit | Letter of Credit | Triad Hunter

Commitments

Maximum borrowing capacity

$ 65,000,000

Subsequent Event | Eclipse Resources I, LP v. Triad Hunter, LLC, Civil Action

Commitments

Escrow deposit required, pursuant stipulation

$ 2,200,000

Subsequent Event | Rejection Of TGT Transportation Services Agreement And Related Contracts

Commitments

Damages sought, value

$ 15,000,000

Subsequent Event | Settled Litigation

Commitments

Litigation settlement, amount

$ (250,000)

Equitrans, L.P. | Gathering, processing, and transportation commitments

Commitments

Term of commitment

15 years

120 months

Equitrans, L.P. | Gathering, processing, and transportation commitments | Eureka Hunter Pipelines, LLC

Commitments

Remaining maximum liability

16,800,000

$ 16,800,000

Equitrans, L.P. | Gathering, processing, and transportation commitments expiring October 31, 2029 | Eureka Hunter Pipelines, LLC

Commitments

Remaining maximum liability

44,200,000

44,200,000

Dominion Field Services, Inc. | Gathering, processing, and transportation commitments | Triad Hunter

Commitments

Remaining maximum liability

2,700,000

2,700,000

Term of commitment

120 months

Liabilities Subject To Compromise | Partnership Interest Purchase Agreement Commitments | Hall-Houston Exploration II, L. P.

Commitments

Remaining maximum liability

$ 640,695

Eureka Hunter Pipelines, LLC | Eureka Hunter Pipeline Gas Gathering Agreement | Triad Hunter

Commitments

Remaining maximum liability

$ 172,800,000

$ 172,800,000

Daily quantity committed production | MMBTU

260,000

Aggregate reservation fee | $ / MMBTU

1.05

1.05

Accounts payable, related parties, past due

$ 10,700,000

Cash collateral, demand notice, assurance of performance security

$ 20,800,000

Payment of demand notice, assurance of performance security

$ 5,000,000

Number of days after petition date

30 days

Number of days after filing of involuntary case for entry of order for relief

45 days

Eureka Hunter Pipelines, LLC | Eureka Hunter Pipeline Gas Gathering Agreement | Triad Hunter | WEST VIRGINIA

Commitments

Wells temporarily suspended | Well

40

Well production of natural gas (Mcfe/d) | Mcfe

55

Eureka Hunter Pipelines, LLC | Eureka Hunter Pipeline Gas Gathering Agreement | Triad Hunter | Minimum

Commitments

Number of individual transaction confirmations | transaction

7

7

Pipeline project, term of agreement

8 years

Eureka Hunter Pipelines, LLC | Eureka Hunter Pipeline Gas Gathering Agreement | Triad Hunter | Maximum

Commitments

Pipeline project, term of agreement

14 years

First Payment | Eureka Hunter Pipelines, LLC | Eureka Hunter Pipeline Gas Gathering Agreement | Triad Hunter

Commitments

Payment of demand notice, assurance of performance security

$ 3,000,000

Second Payment | Eureka Hunter Pipelines, LLC | Eureka Hunter Pipeline Gas Gathering Agreement | Triad Hunter

Commitments

Payment of demand notice, assurance of performance security

$ 2,000,000

SUPPLEMENTAL CASH FLOW INFOR110

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Significant Noncash Transactions [Line Items]
Cash paid for interest	$ 55,531	$ 73,192	$ 67,736
Cash paid for taxes	0	0	1,200
Non-cash transactions
Change in accrued capital expenditures - increase (decrease)	(100,774)	127,068	(65,634)
Reclassification of deposit from field equipment to other assets	2,125
Eureka Midstream Holdings, LLC Series A convertible preferred unit dividends paid in kind		1,950	8,243
Non-cash additions to asset retirement obligation	141	3,426	2,132
Common stock issued for 401k matching contributions	1,878	1,593	1,192
Non-cash consideration received from sale of assets		9,447	42,300
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units	$ 0	$ (51,692)	$ 0
Dividend Paid | Common Stock
Non-cash transactions
Common stock dividends issued in the form of warrants			17,030,622
Fair value of warrants issued as dividends on common stock			$ 21,600

SEGMENT REPORTING (Details)

SEGMENT REPORTING (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenue	$ 25,538	$ 33,664	$ 39,526	$ 55,396	$ 59,854	$ 79,670	$ 138,463	$ 113,482	$ 154,124	$ 391,469	$ 304,538
Depreciation, depletion, amortization and accretion			$ 22,300	$ 57,800					132,804	146,868	107,385
(Gain) loss on sale of assets, net									(31,358)	(2,456)	44,641
Other operating expenses									513,764	737,415	387,305
Other income (expense)									(281,647)	352,525	(82,727)
Reorganization items, net									(41,139)	0	0
Income (loss) from continuing operations before income tax									(783,872)	(137,833)	(317,520)
Income tax benefit									0	0	85,407
Income (loss) from discontinued operations, net of tax									0	(9,294)	8,949
Net income (loss)									(783,872)	(147,127)	(223,164)
Total assets	1,060,158				1,677,955				1,060,158	1,677,955	1,856,651
Total capital expenditures									$ 66,878	700,608	$ 570,712
Midstream
Segment Reporting Information [Line Items]
Percentage of revenues									38.60%		40.70%
Operating Segments | Upstream
Segment Reporting Information [Line Items]
Total revenue									$ 134,812	270,615	$ 225,498
Depreciation, depletion, amortization and accretion									128,973	127,607	92,713
(Gain) loss on sale of assets, net									(31,409)	(2,075)	44,629
Other operating expenses									454,984	556,085	267,935
Other income (expense)									(10,091)	1,340	(656)
Reorganization items, net									0
Income (loss) from continuing operations before income tax										(409,662)	(180,435)
Income tax benefit											56,418
Income (loss) from discontinued operations, net of tax										3,481	9,018
Net income (loss)									(427,827)	(406,181)	(114,999)
Total assets	756,265				1,168,829				756,265	1,168,829	1,441,408
Total capital expenditures									63,981	470,843	459,737
Operating Segments | Midstream
Segment Reporting Information [Line Items]
Total revenue									867	109,658	69,306
Depreciation, depletion, amortization and accretion									0	15,737	12,318
(Gain) loss on sale of assets, net									0	(12)	8
Other operating expenses									736	93,138	60,497
Other income (expense)									(181,092)	(99,221)	(22,358)
Reorganization items, net									0
Income (loss) from continuing operations before income tax										(98,426)	(25,875)
Income tax benefit											0
Income (loss) from discontinued operations, net of tax										0	0
Net income (loss)									(180,961)	(98,426)	(25,875)
Total assets	166,107				347,645				166,107	347,645	296,739
Total capital expenditures									0	221,455	87,498
Operating Segments | Oilfield Services
Segment Reporting Information [Line Items]
Total revenue									18,973	31,392	21,527
Depreciation, depletion, amortization and accretion									3,926	3,524	2,354
(Gain) loss on sale of assets, net									51	(369)	4
Other operating expenses									19,637	26,642	19,252
Other income (expense)									(577)	(813)	(507)
Reorganization items, net									0
Income (loss) from continuing operations before income tax										782	(590)
Income tax benefit											0
Income (loss) from discontinued operations, net of tax										0	0
Net income (loss)									(5,218)	782	(590)
Total assets	37,787				47,009				37,787	47,009	44,193
Total capital expenditures									650	8,079	22,440
Corporate Unallocated
Segment Reporting Information [Line Items]
Total revenue									0	0	0
Depreciation, depletion, amortization and accretion									0	0	0
(Gain) loss on sale of assets, net									0	0	0
Other operating expenses									38,794	81,746	49,241
Other income (expense)									(89,887)	454,921	(61,446)
Reorganization items, net									(41,139)
Income (loss) from continuing operations before income tax										373,175	(110,687)
Income tax benefit											28,989
Income (loss) from discontinued operations, net of tax										(12,775)	0
Net income (loss)									(169,820)	360,400	(81,698)
Total assets	100,040				116,849				100,040	116,849	77,684
Total capital expenditures									2,247	231	1,037
Intersegment Eliminations
Segment Reporting Information [Line Items]
Total revenue									(528)	(20,196)	(11,793)
Depreciation, depletion, amortization and accretion									(95)	0	0
(Gain) loss on sale of assets, net									0	0	0
Other operating expenses									(387)	(20,196)	(9,620)
Other income (expense)									0	(3,702)	2,240
Reorganization items, net									0
Income (loss) from continuing operations before income tax										(3,702)	67
Income tax benefit											0
Income (loss) from discontinued operations, net of tax										0	(69)
Net income (loss)									(46)	(3,702)	(2)
Total assets	$ (41)				$ (2,377)				(41)	(2,377)	(3,373)
Total capital expenditures									$ 0	$ 0	$ 0

CONDENSED CONSOLIDATED GUARA112

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Current assets	$ 83,548	$ 128,322
Property and equipment (using successful efforts accounting)	768,538	1,175,658
Investment in affiliates, equity method	166,099	347,191
Total assets	1,060,158	1,677,955	$ 1,856,651
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	145,900	176,571
Liabilities subject to compromise	1,096,071	0
Shareholders' equity (deficit)	(312,484)	431,855	$ 450,730	$ 711,652
Total liabilities and shareholders’ equity	1,060,158	1,677,955
Magnum Hunter Resources Corporation | 9.75% Senior Notes Due May 15, 2020
ASSETS
Current assets	52,010	88,542
Intercompany accounts receivable	1,159,346	1,113,417
Property and equipment (using successful efforts accounting)	6,221	5,506
Investment in subsidiaries	(516,241)	(91,595)
Investment in affiliates, equity method	166,099	347,191
Other assets	41,809	22,804
Total assets	909,244	1,485,865
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	127,469	28,242
Intercompany accounts payable	0	0
Liabilities subject to compromise	994,120
Long-term liabilities	139	925,767
Redeemable preferred stock	100,000	100,000
Shareholders' equity (deficit)	(312,484)	431,856
Total liabilities and shareholders’ equity	909,244	1,485,865
Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
ASSETS
Current assets	31,359	41,569
Intercompany accounts receivable	0	0
Property and equipment (using successful efforts accounting)	762,361	1,170,122
Investment in subsidiaries	91,759	94,134
Investment in affiliates, equity method	0	0
Other assets	164	3,980
Total assets	885,643	1,309,805
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	18,390	148,145
Intercompany accounts payable	1,120,148	1,073,091
Liabilities subject to compromise	101,951
Long-term liabilities	30,532	43,762
Redeemable preferred stock	0	0
Shareholders' equity (deficit)	(385,378)	44,807
Total liabilities and shareholders’ equity	885,643	1,309,805
Non Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
ASSETS
Current assets	177	589
Intercompany accounts receivable	0	0
Property and equipment (using successful efforts accounting)	0	30
Investment in subsidiaries	0	0
Investment in affiliates, equity method	0	0
Other assets	0	0
Total assets	177	619
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	39	2,567
Intercompany accounts payable	41,434	42,560
Liabilities subject to compromise	0
Long-term liabilities	0	0
Redeemable preferred stock	0	0
Shareholders' equity (deficit)	(41,296)	(44,508)
Total liabilities and shareholders’ equity	177	619
Magnum Hunter Resources Corporation Consolidated | 9.75% Senior Notes Due May 15, 2020
ASSETS
Current assets	83,548	128,322
Intercompany accounts receivable	0	0
Property and equipment (using successful efforts accounting)	768,538	1,175,658
Investment in subsidiaries	0	0
Investment in affiliates, equity method	166,099	347,191
Other assets	41,973	26,784
Total assets	1,060,158	1,677,955
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	145,900	176,571
Intercompany accounts payable	0	0
Liabilities subject to compromise	1,096,071
Long-term liabilities	30,671	969,529
Redeemable preferred stock	100,000	100,000
Shareholders' equity (deficit)	(312,484)	431,855
Total liabilities and shareholders’ equity	1,060,158	1,677,955
Eliminations | 9.75% Senior Notes Due May 15, 2020
ASSETS
Current assets	2	(2,378)
Intercompany accounts receivable	(1,159,346)	(1,113,417)
Property and equipment (using successful efforts accounting)	(44)	0
Investment in subsidiaries	424,482	(2,539)
Investment in affiliates, equity method	0	0
Other assets	0	0
Total assets	(734,906)	(1,118,334)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	2	(2,383)
Intercompany accounts payable	(1,161,582)	(1,115,651)
Liabilities subject to compromise	0
Long-term liabilities	0	0
Redeemable preferred stock	0	0
Shareholders' equity (deficit)	426,674	(300)
Total liabilities and shareholders’ equity	$ (734,906)	$ (1,118,334)

CONDENSED CONSOLIDATED GUARA113

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed consolidating statements of operations
Total revenue	$ 25,538	$ 33,664	$ 39,526	$ 55,396	$ 59,854	$ 79,670	$ 138,463	$ 113,482	$ 154,124	$ 391,469	$ 304,538
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(783,872)	(137,833)	(317,520)
Income tax benefit									0	0	85,407
LOSS FROM CONTINUING OPERATIONS, NET OF TAX					103,320	(123,189)	(61,407)	(56,557)	(783,872)	(137,833)	(232,113)
Income (loss) from discontinued operations, net of tax					0	0	1,192	3,369	0	4,561	(62,561)
Gain (loss) on disposal of discontinued operations, net of tax					128	(258)	(5,212)	(8,513)	0	(13,855)	71,510
NET LOSS									(783,872)	(147,127)	(223,164)
Net loss attributable to non-controlling interests									0	3,653	988
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	(543,096)	(113,181)	(21,676)	(105,919)	103,448	(120,683)	(64,647)	(61,592)	(783,872)	(143,474)	(222,176)
Dividends on preferred stock									(33,817)	(54,707)	(56,705)
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units									0	(51,692)	0
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ (550,370)	$ (122,029)	$ (30,523)	$ (114,767)	$ 42,767	$ (136,175)	$ (79,997)	$ (76,468)	(817,689)	(249,873)	(278,881)
Magnum Hunter Resources Corporation | 9.75% Senior Notes Due May 15, 2020
Condensed consolidating statements of operations
Total revenue									16	142	2,629
Expenses									351,749	(370,646)	112,754
Loss from continuing operations before equity in net income of subsidiaries									(351,733)	370,788	(110,125)
Equity in net income of subsidiaries									(432,139)	(513,580)	(298,775)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(783,872)	(142,792)	(408,900)
Income tax benefit									0	0	28,989
LOSS FROM CONTINUING OPERATIONS, NET OF TAX										(142,792)	(379,911)
Income (loss) from discontinued operations, net of tax										0	(7,813)
Gain (loss) on disposal of discontinued operations, net of tax										(20,027)	144,378
NET LOSS									(783,872)	(162,819)	(243,346)
Net loss attributable to non-controlling interests										0	0
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION										(162,819)	(243,346)
Dividends on preferred stock									(33,817)	(35,364)	(35,464)
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units										(51,692)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(817,689)	(249,875)	(278,810)
Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
Condensed consolidating statements of operations
Total revenue									155,270	368,537	277,854
Expenses									587,612	772,355	461,173
Loss from continuing operations before equity in net income of subsidiaries									(432,342)	(403,818)	(183,319)
Equity in net income of subsidiaries									(2,374)	(8,181)	(424)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(434,716)	(411,999)	(183,743)
Income tax benefit									0	0	56,422
LOSS FROM CONTINUING OPERATIONS, NET OF TAX										(411,999)	(127,321)
Income (loss) from discontinued operations, net of tax										0	22,661
Gain (loss) on disposal of discontinued operations, net of tax										97	0
NET LOSS									(434,716)	(411,902)	(104,660)
Net loss attributable to non-controlling interests										0	0
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION										(411,902)	(104,660)
Dividends on preferred stock									0	0	0
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units										0
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(434,716)	(411,902)	(104,660)
Non Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
Condensed consolidating statements of operations
Total revenue									1,036	43,611	35,848
Expenses									789	144,714	59,991
Loss from continuing operations before equity in net income of subsidiaries									247	(101,103)	(24,143)
Equity in net income of subsidiaries									0	0	0
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									247	(101,103)	(24,143)
Income tax benefit									0	0	(4)
LOSS FROM CONTINUING OPERATIONS, NET OF TAX										(101,103)	(24,147)
Income (loss) from discontinued operations, net of tax										4,561	(77,340)
Gain (loss) on disposal of discontinued operations, net of tax										6,075	(72,868)
NET LOSS									247	(90,467)	(174,355)
Net loss attributable to non-controlling interests										0	0
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION										(90,467)	(174,355)
Dividends on preferred stock									0	(19,343)	(21,241)
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units										0
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									247	(109,810)	(195,596)
Magnum Hunter Resources Corporation Consolidated | 9.75% Senior Notes Due May 15, 2020
Condensed consolidating statements of operations
Total revenue									154,124	391,469	304,538
Expenses									937,996	529,302	622,058
Loss from continuing operations before equity in net income of subsidiaries									(783,872)	(137,833)	(317,520)
Equity in net income of subsidiaries									0	0	0
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									(783,872)	(137,833)	(317,520)
Income tax benefit									0	0	85,407
LOSS FROM CONTINUING OPERATIONS, NET OF TAX										(137,833)	(232,113)
Income (loss) from discontinued operations, net of tax										4,561	(62,561)
Gain (loss) on disposal of discontinued operations, net of tax										(13,855)	71,510
NET LOSS									(783,872)	(147,127)	(223,164)
Net loss attributable to non-controlling interests										3,653	988
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION										(143,474)	(222,176)
Dividends on preferred stock									(33,817)	(54,707)	(56,705)
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units										(51,692)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									(817,689)	(249,873)	(278,881)
Eliminations | 9.75% Senior Notes Due May 15, 2020
Condensed consolidating statements of operations
Total revenue									(2,198)	(20,821)	(11,793)
Expenses									(2,154)	(17,121)	(11,860)
Loss from continuing operations before equity in net income of subsidiaries									(44)	(3,700)	67
Equity in net income of subsidiaries									434,513	521,761	299,199
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX									434,469	518,061	299,266
Income tax benefit									0	0	0
LOSS FROM CONTINUING OPERATIONS, NET OF TAX										518,061	299,266
Income (loss) from discontinued operations, net of tax										0	(69)
Gain (loss) on disposal of discontinued operations, net of tax										0	0
NET LOSS									434,469	518,061	299,197
Net loss attributable to non-controlling interests										3,653	988
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION										521,714	300,185
Dividends on preferred stock									0	0	0
Loss on extinguishment of Eureka Midstream Holdings, LLC Series A Preferred Units										0
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS									$ 434,469	$ 521,714	$ 300,185

CONDENSED CONSOLIDATED GUARA114

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Statements of Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income (loss)	$ (783,872)	$ (147,127)	$ (223,164)
Foreign currency translation gain (loss)	99	(1,204)	(10,928)
Unrealized loss on available for sale securities	(2,771)	(7,401)	(84)
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(19)	0	(8,262)
Amounts reclassified for other than temporary impairment of available for sale securities	10,183	0	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	0	20,741	0
Comprehensive loss	(776,380)	(134,991)	(234,176)
Comprehensive loss attributable to non-controlling interests	0	3,653	988
Comprehensive loss attributable to Magnum Hunter Resources Corporation	(776,380)	(131,338)	(233,188)
9.75% Senior Notes Due May 15, 2020 | Magnum Hunter Resources Corporation
Net income (loss)	(783,872)	(162,819)	(243,346)
Foreign currency translation gain (loss)	0	0	0
Unrealized loss on available for sale securities	0	0	8,262
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	0		(8,262)
Amounts reclassified for other than temporary impairment of available for sale securities	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		20,741
Comprehensive loss	(783,872)	(142,078)	(243,346)
Comprehensive loss attributable to non-controlling interests		0	0
Comprehensive loss attributable to Magnum Hunter Resources Corporation		(142,078)	(243,346)
9.75% Senior Notes Due May 15, 2020 | Wholly-Owned Guarantor Subsidiaries
Net income (loss)	(434,716)	(411,902)	(104,660)
Foreign currency translation gain (loss)	99	0	0
Unrealized loss on available for sale securities	(2,771)	(7,401)	(84)
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(19)		0
Amounts reclassified for other than temporary impairment of available for sale securities	10,183
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		0
Comprehensive loss	(427,224)	(419,303)	(104,744)
Comprehensive loss attributable to non-controlling interests		0	0
Comprehensive loss attributable to Magnum Hunter Resources Corporation		(419,303)	(104,744)
9.75% Senior Notes Due May 15, 2020 | Non Guarantor Subsidiaries
Net income (loss)	247	(90,467)	(174,355)
Foreign currency translation gain (loss)	0	(1,204)	(10,928)
Unrealized loss on available for sale securities	0	0	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	0		0
Amounts reclassified for other than temporary impairment of available for sale securities	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		0
Comprehensive loss	247	(91,671)	(185,283)
Comprehensive loss attributable to non-controlling interests		0	0
Comprehensive loss attributable to Magnum Hunter Resources Corporation		(91,671)	(185,283)
9.75% Senior Notes Due May 15, 2020 | Magnum Hunter Resources Corporation Consolidated
Net income (loss)	(783,872)	(147,127)	(223,164)
Foreign currency translation gain (loss)	99	(1,204)	(10,928)
Unrealized loss on available for sale securities	(2,771)	(7,401)	8,178
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	(19)		(8,262)
Amounts reclassified for other than temporary impairment of available for sale securities	10,183
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		20,741
Comprehensive loss	(776,380)	(134,991)	(234,176)
Comprehensive loss attributable to non-controlling interests		3,653	988
Comprehensive loss attributable to Magnum Hunter Resources Corporation		(131,338)	(233,188)
Eliminations | 9.75% Senior Notes Due May 15, 2020
Net income (loss)	434,469	518,061	299,197
Foreign currency translation gain (loss)	0	0	0
Unrealized loss on available for sale securities	0	0	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	0		0
Amounts reclassified for other than temporary impairment of available for sale securities	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		0
Comprehensive loss	$ 434,469	518,061	299,197
Comprehensive loss attributable to non-controlling interests		3,653	988
Comprehensive loss attributable to Magnum Hunter Resources Corporation		$ 521,714	$ 300,185

CONDENSED CONSOLIDATED GUARA115

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	$ 25,026	$ (18,665)	$ 111,711
Cash flow from investing activities	(165,941)	(318,119)	(127,860)
Cash flow from financing activities	128,634	348,195	656
Effect of foreign exchange rate changes on cash	(28)	56	(417)
Net change in cash and cash equivalents	(12,309)	11,467	(15,910)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	53,180	41,713	57,623
CASH AND CASH EQUIVALENTS, END OF YEAR	40,871	53,180	41,713
Magnum Hunter Resources Corporation | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities		(347,898)	(371,351)
Cash flow from investing activities		107,595	422,303
Cash flow from financing activities		250,194	(29,929)
Effect of foreign exchange rate changes on cash		0	0
Net change in cash and cash equivalents		9,891	21,023
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	57,786	47,895	26,872
CASH AND CASH EQUIVALENTS, END OF YEAR		57,786	47,895
Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities		255,088	397,213
Cash flow from investing activities		(248,928)	(411,473)
Cash flow from financing activities		301	796
Effect of foreign exchange rate changes on cash		0	0
Net change in cash and cash equivalents		6,461	(13,464)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	(11,190)	(17,651)	(4,187)
CASH AND CASH EQUIVALENTS, END OF YEAR		(11,190)	(17,651)
Non Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities		74,145	99,153
Cash flow from investing activities		(176,786)	(138,690)
Cash flow from financing activities		97,700	16,485
Effect of foreign exchange rate changes on cash		56	(417)
Net change in cash and cash equivalents		(4,885)	(23,469)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	6,584	11,469	34,938
CASH AND CASH EQUIVALENTS, END OF YEAR		6,584	11,469
Magnum Hunter Resources Corporation Consolidated | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities		(18,665)	111,711
Cash flow from investing activities		(318,119)	(127,860)
Cash flow from financing activities		348,195	656
Effect of foreign exchange rate changes on cash		56	(417)
Net change in cash and cash equivalents		11,467	(15,910)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	53,180	41,713	57,623
CASH AND CASH EQUIVALENTS, END OF YEAR		53,180	41,713
Eliminations | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities		0	(13,304)
Cash flow from investing activities		0	0
Cash flow from financing activities		0	13,304
Effect of foreign exchange rate changes on cash		0	0
Net change in cash and cash equivalents		0	0
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	0	0	0
CASH AND CASH EQUIVALENTS, END OF YEAR		0	$ 0
Eureka Midstream Holdings | Magnum Hunter Resources Corporation | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	(113,263)
Cash flow from investing activities	(43,305)
Cash flow from financing activities	134,733
Effect of foreign exchange rate changes on cash	0
Net change in cash and cash equivalents	(21,835)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	64,165
CASH AND CASH EQUIVALENTS, END OF YEAR	42,330	64,165
Eureka Midstream Holdings | Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	138,429
Cash flow from investing activities	(122,776)
Cash flow from financing activities	(6,099)
Effect of foreign exchange rate changes on cash	(28)
Net change in cash and cash equivalents	9,526
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	(10,985)
CASH AND CASH EQUIVALENTS, END OF YEAR	(1,459)	(10,985)
Eureka Midstream Holdings | Non Guarantor Subsidiaries | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	0
Cash flow from investing activities	0
Cash flow from financing activities	0
Effect of foreign exchange rate changes on cash	0
Net change in cash and cash equivalents	0
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	0
CASH AND CASH EQUIVALENTS, END OF YEAR	0	0
Eureka Midstream Holdings | Magnum Hunter Resources Corporation Consolidated | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	25,026
Cash flow from investing activities	(165,941)
Cash flow from financing activities	128,634
Effect of foreign exchange rate changes on cash	(28)
Net change in cash and cash equivalents	(12,309)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	53,180
CASH AND CASH EQUIVALENTS, END OF YEAR	40,871	53,180
Eureka Midstream Holdings | Eliminations | 9.75% Senior Notes Due May 15, 2020
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	(140)
Cash flow from investing activities	140
Cash flow from financing activities	0
Effect of foreign exchange rate changes on cash	0
Net change in cash and cash equivalents	0
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	0
CASH AND CASH EQUIVALENTS, END OF YEAR	$ 0	$ 0

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) $ in Thousands	Mar. 10, 2016USD ($)	Jan. 14, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 15, 2015MMBTU	Oct. 08, 2014MMBTU
Second DIP Draw | Term Loan | Line of Credit | Subsequent Event
Subsequent Event [Line Items]
Repayments of debt		$ 70,200
Rejection Of TGT Transportation Services Agreement And Related Contracts | Subsequent Event
Subsequent Event [Line Items]
Damages sought, value	$ 15,000
Settled Litigation | Subsequent Event
Subsequent Event [Line Items]
Litigation settlement, amount	$ 250
Triad Hunter | Credit Support Agreement With REX (Rockies Express Pipeline LLC) | Line of Credit | Letter of Credit
Subsequent Event [Line Items]
Decrease in borrowing capacity (every 3 months)			$ 2,800
Period of incremental borrowing capacity decrease			3 months
Borrowing capacity, after reduction			$ 20,000
Period until additional borrowing capacity reduction			5 years
REX Services Agreement, MMBtu Per Day Of Firm Transportation | Triad Hunter
Subsequent Event [Line Items]
Acquired notional amount energy measure per day | MMBTU				50,000,000	100,000

OTHER INFORMATION Quarterly Una

OTHER INFORMATION Quarterly Unaudited Summary Financial Results (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 03, 2015	Dec. 31, 2014	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Details of unaudited summary financial results
Total revenue			$ 25,538	$ 33,664	$ 39,526	$ 55,396	$ 59,854	$ 79,670	$ 138,463	$ 113,482	$ 154,124		$ 391,469		$ 304,538
Operating income (loss)			(303,475)	(84,652)	4,529	(77,488)	(401,575)	(57,576)	1,555	(32,762)	(461,086)		(490,358)		(234,793)
Income (loss) from continuing operations							103,320	(123,189)	(61,407)	(56,557)	(783,872)		(137,833)		(232,113)
Income from discontinued operations, net of tax							0	0	1,192	3,369	0		4,561		(62,561)
Gain (loss) on disposal of discontinued operations, net of tax							128	(258)	(5,212)	(8,513)	0		(13,855)		71,510
Net Income (loss) attributable to Magnum Hunter Resources Corporation			(543,096)	(113,181)	(21,676)	(105,919)	103,448	(120,683)	(64,647)	(61,592)	(783,872)		(143,474)		(222,176)
Net Income (loss) attributable to common shareholders			$ (550,370)	$ (122,029)	$ (30,523)	$ (114,767)	$ 42,767	$ (136,175)	$ (79,997)	$ (76,468)	$ (817,689)		$ (249,873)		$ (278,881)
Income (loss) from continuing operations per share, basic and diluted (in usd per share)							$ 0.23	$ (0.68)	$ (0.41)	$ (0.41)	$ (3.63)		$ (1.27)		$ (1.69)
Income (loss) per common share, basic and diluted (in usd per share)			$ (2.11)	$ (0.53)	$ (0.15)	$ (0.57)	$ 0.23	$ (0.68)	$ (0.43)	$ (0.44)	$ (3.63)		$ (1.32)		$ (1.64)
Depreciation, depletion, amortization and accretion					$ 22,300	$ 57,800					$ 132,804		$ 146,868		$ 107,385
Impairment of proved oil and gas properties			$ 211,600	$ 49,800	100	13,900	$ 261,500				275,375		301,276		89,041
Exploration expense			$ 45,500	$ 4,400	$ 1,500	$ 8,500	66,100
General and administrative expense							$ 32,600				47,260	[1]	108,687	[1]	82,461	[1]
Loss on derivative contracts								$ 49,600	$ 42,800
Gain on deconsolidation											0		$ 509,563		$ 0
Eureka Midstream Holdings
Details of unaudited summary financial results
Impairment of equity method investments	$ 180,300	$ 0									180,254
Gain on deconsolidation											$ 4,600
[1]	2014 includes the recognition of a $32.6 million non-cash loss related to the downward adjustment of the Company’s equity interest in Eureka Midstream Holdings, LLC related to excess capital expenditures in 2014. See “Note 4 - Eureka Midstream Holdings” in the accompanying Notes to Consolidated Financial Statements.

OTHER INFORMATION Supplemental

OTHER INFORMATION Supplemental Oil and Gas Disclosures (Unaudited) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities
Purchase of non-producing leases	$ 18,906	$ 124,411	$ 149,592
Purchase of producing properties	0	12,246	1,358
Exploration costs	0	9,907	11,531
Development costs	45,075	327,138	276,130
Costs incurred, acquisition of oil and gas properties, Total	$ 63,981	$ 473,702	$ 438,611

OTHER INFORMATION Oil and Gas R

OTHER INFORMATION Oil and Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2015MMcfMBbls	Dec. 31, 2014MMcfMBbls	Dec. 31, 2013MMcfMBbls
Summary of estimating quantities of proved reserves data
Extensions, discoveries, and other additions		26,988	862
Crude Oil and Liquids
Summary of estimating quantities of proved reserves data
Beginning balance	10,521	24,335	36,827
Revisions of previous estimates	(6,075)	(6,540)	3,766
Purchase of reserves in place			0
Extensions, discoveries, and other additions	0	1,705	577
Sale of reserves in place		(7,321)	(14,506)
Production	(1,016)	(1,658)	(2,329)
Ending balance	3,430	10,521	24,335
Developed reserves, included above (Volume)	3,430	6,938	12,085
Proved undeveloped reserves (Volume)	0	3,583	12,250
NGL
Summary of estimating quantities of proved reserves data
Beginning balance	14,403	10,422	9,125
Revisions of previous estimates	(6,959)	2,149	2,382
Purchase of reserves in place			0
Extensions, discoveries, and other additions	0	3,226	71
Sale of reserves in place		(434)	(698)
Production	(1,263)	(960)	(458)
Ending balance	6,181	14,403	10,422
Developed reserves, included above (Volume)	6,181	10,587	6,990
Proved undeveloped reserves (Volume)	0	3,816	3,432
Natural Gas
Summary of estimating quantities of proved reserves data
Beginning balance | MMcf	353,001	246,782	162,620
Revisions of previous estimates | MMcf	(162,147)	(511)	100,456
Purchase of reserves in place | MMcf			88
Extensions, discoveries, and other additions | MMcf	25,309	132,345	1,285
Sale of reserves in place | MMcf		(3,768)	(4,185)
Production | MMcf	(34,778)	(21,847)	(13,482)
Ending balance | MMcf	181,385	353,001	246,782
Developed reserves, included above (Volume) | MMcf	156,076	251,628	176,585
Proved undeveloped reserves (Volume) | MMcf	25,309	101,373	70,197

OTHER INFORMATION Standardized

OTHER INFORMATION Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Details of standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash inflows	$ 598,161	$ 3,282,768	$ 3,711,260
Future production costs	(369,478)	(1,443,121)	(1,423,306)
Future development costs	(16,712)	(219,509)	(421,797)
Future income tax expense	0	0	(149,367)
Future net cash flows	211,971	1,620,138	1,716,790
10% annual discount for estimated timing of cash flows	(101,382)	(710,875)	(872,280)
Standardized measure of discounted future net cash flows	$ 110,589	$ 909,263	$ 844,510	$ 847,653

OTHER INFORMATION Changes in St

OTHER INFORMATION Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MMcfMBbls	Dec. 31, 2014USD ($)MMcfMBbls	Dec. 31, 2013USD ($)MMcfMBbls
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Balance, beginning of period	$ 909,263	$ 844,510	$ 847,653
Net changes in prices and production costs	(640,645)	(281,352)	(7,355)
Changes in estimated future development costs	137,578	(57,348)	(261,591)
Sales and transfers of oil and gas produced during the period	(20,851)	(166,611)	(190,151)
Net changes due to extensions, discoveries, and improved recovery	12,630	332,684	12,829
Net changes due to revisions of previous quantity estimates	(458,945)	(55,176)	341,003
Previously estimated development costs incurred during the period	44,976	269,017	283,736
Accretion of discount	77,077	95,547	90,153
Purchase of minerals in place	0	0	218
Sale of minerals in place	0	(141,847)	(236,885)
Changes in timing and other	49,506	(7,720)	(91,088)
Net change in income taxes	0	77,559	55,988
Standardized measure of discounted future net cash flows	$ 110,589	$ 909,263	$ 844,510
Crude Oil and Liquids
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Revisions of previous estimates (volume) | MBbls	(6,075)	(6,540)	3,766
Natural Gas
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Revisions of previous estimates (volume) | MMcf	(162,147)	(511)	100,456
NGL
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Revisions of previous estimates (volume) | MBbls	(6,959)	2,149	2,382

OTHER INFORMATION Commodity Pri

OTHER INFORMATION Commodity Prices Related to the Standardized Measure Calculation (Details)	12 Months Ended
	Dec. 31, 2015$ / Mcf$ / bbl	Dec. 31, 2014$ / Mcf$ / bbl	Dec. 31, 2013$ / Mcf$ / bbl
Oil (per bbl)
Average Sales Price and Production Costs Per Unit of Production
Commodity prices inclusive of adjustments for quality and location	41.83	85.21	93.13
Natural gas liquids (per bbl)
Average Sales Price and Production Costs Per Unit of Production
Commodity prices inclusive of adjustments for quality and location	16.90	50.64	43.79
Gas (per mcf)
Average Sales Price and Production Costs Per Unit of Production
Commodity prices inclusive of adjustments for quality and location | $ / Mcf	1.93	4.69	4.14

OTHER INFORMATION Narratives (D

OTHER INFORMATION Narratives (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MBoeMMcf	Dec. 31, 2014USD ($)MBoeMMcfMBbls	Dec. 31, 2013MBoeMMcfMBbls
Segment Reporting Information
Increase (decrease) in proved reserves		26,126
Extensions, discoveries, and other additions | MBbls		26,988	862
U.S. federal income tax
Segment Reporting Information
Net operating loss carry forwards | $	$ 1,031	$ 710
Eagle Ford Hunter
Segment Reporting Information
Proved reserves included in sale (energy)			11,459
Certain North Dakota Oil and Gas Properties
Segment Reporting Information
Proved reserves included in sale (energy)			4,308
Natural Gas
Segment Reporting Information
Extensions, discoveries, and other additions | MMcf	25,309	132,345	1,285
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy)	4,218