Magnum Hunter Resources 10-K 2 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 23, 2015	Jun. 30, 2014
Document And Entity Information
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Entity Registrant Name	Magnum Hunter Resources Corp
Entity Central Index Key	1335190
Entity Filer Category	Large Accelerated Filer
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$1,560,087,080
Entity Common Stock, Shares Outstanding		200,935,464
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$53,180,000	$41,713,000
Restricted cash	0	5,000,000
Oil and natural gas sales	16,319,000	25,099,000
Joint interests and other, net of allowance for doubtful accounts of $308 and $196 at December 31, 2014 and 2013, respectively	23,888,000	30,582,000
Derivative assets	16,586,000	608,000
Inventory	2,268,000	7,158,000
Investments	3,864,000	2,262,000
Prepaid expenses and other assets	4,091,000	2,938,000
Assets held for sale	0	5,366,000
Total current assets	120,196,000	120,726,000
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method of accounting	1,346,645,000	1,355,288,000
Accumulated depletion, depreciation, and accretion	-248,410,000	-130,629,000
Total oil and natural gas properties, net	1,098,235,000	1,224,659,000
Gas transportation, gathering and processing equipment and other, net	77,423,000	289,420,000
Total property, plant and equipment, net	1,175,658,000	1,514,079,000
OTHER ASSETS
Deferred financing costs, net of amortization of $15,099 and $9,735 as of December 31, 2014 and 2013, respectively	22,856,000	20,008,000
Derivative assets	0	25,000
Intangible assets, net	0	6,530,000
Goodwill	0	30,602,000
Other assets	3,928,000	1,644,000
Investment in affiliates, equity method	347,191,000	350,000
Assets held for sale	0	162,687,000
Total assets	1,669,829,000	1,856,651,000
CURRENT LIABILITIES
Current portion of long-term debt	10,770,000	3,804,000
Accounts payable	130,502,000	107,837,000
Accounts payable to related parties	90,000	23,000
Accrued liabilities	20,277,000	44,629,000
Revenue payable	5,450,000	6,313,000
Derivative liabilities	0	1,903,000
Other liabilities	1,356,000	6,491,000
Liabilities associated with assets held for sale	0	12,865,000
Total current liabilities	168,445,000	183,865,000
Long-term debt, net of current portion	937,963,000	876,106,000
Asset retirement obligations	26,229,000	16,163,000
Derivative liabilities, long-term	0	76,310,000
Other long-term liabilities	5,337,000	2,279,000
Long-term liabilities associated with assets held for sale	0	14,523,000
Total liabilities	1,137,974,000	1,169,246,000
COMMITMENTS AND CONTINGENCIES (Note 18)
REDEEMABLE PREFERRED STOCK
Redeemable preferred stock	100,000,000	236,675,000
SHAREHOLDERS' EQUITY:
Common stock	2,014,000	1,724,000
Additional paid in capital	909,783,000	733,753,000
Accumulated deficit	-784,546,000	-586,365,000
Accumulated other comprehensive loss	-7,765,000	-19,901,000
Treasury Stock, at cost	-1,914,000	-1,914,000
Total Magnum Hunter Resources Corporation shareholders' equity	431,855,000	441,580,000
Non-controlling interest	0	9,150,000
Total shareholders' equity	431,855,000	450,730,000
Total liabilities and shareholders’ equity	1,669,829,000	1,856,651,000
Series C Cumulative Perpetual Preferred Stock
REDEEMABLE PREFERRED STOCK
Redeemable preferred stock	100,000,000	100,000,000
Series A Convertible Preferred Units
REDEEMABLE PREFERRED STOCK
Redeemable preferred stock	0	136,675,000
Series D Cumulative Preferred Stock
SHAREHOLDERS' EQUITY:
Preferred stock	221,244,000	221,244,000
Series E Cumulative Convertible Preferred Stock
SHAREHOLDERS' EQUITY:
Preferred stock	95,069,000	95,069,000
Treasury Stock, at cost	($2,030,000)	($2,030,000)

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Accounts receivable, allowance for doubtful accounts (in dollars)	$308,000	$308,000	$196,000
Amortization of deferred financing costs (in dollars)	15,099,000	15,099,000	9,735,000
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	201,420,701	172,409,023
Common stock, shares outstanding	200,505,749	200,505,749	171,494,071
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 A Convertible Preferred Units
Cumulative dividend rate for Series C Cumulative and Series A Convertible Preferred Stock (as a percent)		8.00%	8.00%
Preferred Stock, shares issued	9,885,048	9,885,048	9,885,048
Preferred Stock, shares outstanding	9,885,048	9,885,048	9,885,048
Preferred Stock, liquidation preference	$0	$0	$200,620
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
Exchangeable common stock
Common stock, par value (in dollars per share)	$0	$0	$0
Common stock, shares issued	0	0	0
Common stock, shares outstanding	0	0	0

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
REVENUES AND OTHER
Oil and natural gas sales	$268,501,000		$220,699,000		$133,728,000
Midstream natural gas gathering, processing, and marketing	97,916,000		61,178,000		13,040,000
Oilfield services	23,134,000		18,431,000		12,333,000
Other revenue	1,918,000		4,230,000		836,000
Total revenue	391,469,000		304,538,000		159,937,000
OPERATING EXPENSES
Production costs	47,857,000		46,689,000		30,119,000
Severance taxes and marketing	17,344,000		18,282,000		8,043,000
Transportation, processing, and other related costs	43,292,000		22,549,000		10,775,000
Exploration	118,509,000		100,389,000		80,375,000
Midstream natural gas gathering, processing, and marketing	84,764,000		52,099,000		8,028,000
Oilfield services	15,686,000		14,825,000		10,037,000
Impairment of proved oil and gas properties	301,276,000		50,011,000		3,839,000
Depreciation, depletion, amortization and accretion	146,868,000		107,385,000		72,438,000
(Gain) loss on sale of assets, net	-2,456,000		44,641,000		596,000
General and administrative (1)	108,687,000	[1]	82,461,000	[1]	62,347,000	[1]
Total operating expenses	881,827,000		539,331,000		286,597,000
OPERATING LOSS	-490,358,000		-234,793,000		-126,660,000
OTHER INCOME (EXPENSE)
Interest income	156,000		265,000		202,000
Interest expense	-86,463,000		-72,621,000		-51,846,000
Gain (loss) on derivative contracts, net	-72,254,000		-25,274,000		22,239,000
Gain on deconsolidation of Eureka Hunter Holdings, LLC	509,563,000		0		0
Loss from equity method investment	-1,038,000		-994,000		-1,971,000
Other income	2,561,000		15,897,000		4,014,000
Total other income (expense), net	352,525,000		-82,727,000		-27,362,000
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	-137,833,000		-317,520,000		-154,022,000
Income tax benefit	0		85,407,000		24,665,000
LOSS FROM CONTINUING OPERATIONS, NET OF TAX	-137,833,000		-232,113,000		-129,357,000
Income (loss) from discontinued operations, net of tax	4,561,000		-62,561,000		-9,773,000
Gain (loss) on disposal of discontinued operations, net of tax	-13,855,000	[2],[3]	71,510,000	[2],[3]	2,409,000	[2],[3]
NET LOSS	-147,127,000		-223,164,000		-136,721,000
Net loss attributable to non-controlling interests	3,653,000		988,000		4,013,000
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	-143,474,000		-222,176,000		-132,708,000
Dividends on preferred stock	-54,707,000		-56,705,000		-34,706,000
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units	-51,692,000		0		0
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	-249,873,000		-278,881,000		-167,414,000
Weighted average number of common shares outstanding, basic and diluted	189,135,500		170,088,108		155,743,418
Loss from continuing operations per share, basic and diluted	($1.27)		($1.69)		($1.03)
Income (loss) from discontinued operations per share, basic and diluted	($0.05)		$0.05		($0.04)
NET LOSS PER COMMON SHARE, BASIC AND DILUTED	($1.32)		($1.64)		($1.07)
Loss from continuing operations, net of tax	-134,180,000		-231,125,000		-125,344,000
Income (loss) from discontinued operations, net of tax	-9,294,000		8,949,000		-7,364,000
Non-cash loss, downward adjustment of equity interests	$32,600,000
[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 Hunter Holdings related to excess capital expenditures in 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” in the accompanying Notes to Consolidated Financial Statements.
[2]	(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[3]	(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.

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
NET LOSS	($147,127)	($223,164)	($136,721)
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation gain (loss)	-1,204	-10,928	3,883
Unrealized gain (loss) on available for sale investments	-7,401	8,178	-309
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	0	-8,262	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	20,741	0	0
Total other comprehensive income (loss)	12,136	-11,012	3,574
COMPREHENSIVE LOSS	-134,991	-234,176	-133,147
Comprehensive loss attributable to non-controlling interests	3,653	988	4,013
COMPREHENSIVE LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES CORPORATION	($131,338)	($233,188)	($129,134)

CONSOLIDATED_STATEMENTS_OF_SHA

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (USD $)	Total	Common Stock	Exchangeable Common Stock	Additional Paid in Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Unearned Common Shares in KSOP	Non-controlling Interest	Series D Preferred Stock	Series D Preferred Stock	Series E Preferred Stock
In Thousands, except Share data, unless otherwise specified	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)		Preferred Stock	Preferred Stock
											USD ($)	USD ($)
BALANCE at Dec. 31, 2011	$490,652	$1,298	$37	$569,690	($140,070)	($12,463)	($1,310)	($604)	$2,196		$71,878	$0
BALANCE (in shares) at Dec. 31, 2011		129,803,000	3,694,000								1,438,000	0
Increase (Decrease) in Shareholders' Equity
Share based compensation (in shares)		108,000
Share based compensation	15,696	1		15,695
Issued shares as Employer Match on 401K (in shares)		199,000
Issued shares as Employer Match on 401K	874	2		872
Issued shares of Preferred Stock for Cash (in cash)		0									2,771,000	1,000
Issued shares of Preferred Stock for cash	144,635			-18,928							138,563	25,000
Issued shares of stock for cash (in shares)		35,000,000								2,771,263
Issued shares of Common Stock for cash	148,241	350		147,891
Issued shares of Common Stock upon exercise of warrants and options (in shares)		1,438,000
Issued shares of Common Stock upon exercise of warrants and options	2,331	14		2,317
Preferred dividends	-34,706				-34,706
Issued shares of common stock for acquisition of assets (in shares)		297,000
Issued shares of common stock for acquisition of assets	1,902	3		1,899
Issued shares of Preferred Stock for acquisition of assets (in shares)												3,000
Issued shares of Preferred Stock for acquisition of assets	64,968			-4,403								69,371
Common stock issued upon exchange of MHR Exchangeco Corporation's exchangeable shares (in shares)		-3,188,000	-3,188,000
Issued shares of common stock upon exchange of MHR Exchangeco Corporation's exchangeable shares	0	32	-32
Repurchase of non-controlling interest	-497								-497
Issued common units of Eureka Hunter Holdings for asset acquisition / Noncontrolling interest acquired in NGAS acqusition for the years ended December 31, 2012 and 2011, respectively	12,453								12,453
Common stock returned to treasury and on Triad Acquisition for the years ended December 31, 2012 and 2010, respectively	0						-604	604
Shares of Series E Preferred Stock received in reimbursement	-1,750						-1,750
Net income (loss)	-136,721				-132,708				-4,013
Foreign currency translation	3,883					3,883
Unrealized gain on available for sale securities	-309					-309
BALANCE at Dec. 31, 2012	711,652	1,700	5	715,033	-307,484	-8,889	-3,664	0	10,139		210,441	94,371
BALANCE (in shares) at Dec. 31, 2012		170,033,000	506,000								4,209,000	4,000
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)											216,000	0
Issued shares of Preferred Stock for cash	10,181			-1,320							10,803	698
Issued shares of stock for cash (in shares)										216,068
Preferred dividends	-56,705				-56,705
Common stock issued upon exchange of MHR Exchangeco Corporation's exchangeable shares (in shares)		-506,000	-506,000
Issued shares of common stock upon exchange of MHR Exchangeco Corporation's exchangeable shares	0	5	-5
Net income (loss)	-223,164				-222,176				-988
Foreign currency translation	-10,928					-10,928
Unrealized gain on available for sale securities	-84					-84
Fees on equity issuance	-109			-109
Depositary shares representing Series E Preferred Stock returned from escrow	-280						-280
Issued shares of Common Stock upon redemption of Series B Convertible Preferred Stock (in shares)		1,466,000
Issued shares of Common Stock upon redemption of Series B Convertible Preferred Stock	5,352	15		5,337
Other	-1								-1
BALANCE at Dec. 31, 2013	450,730	1,724	0	733,753	-586,365	-19,901	-3,944	0	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
Issued shares of stock for cash (in shares)		25,729,000
Issued shares of Common Stock for cash	178,410	257		178,153							0	0
Preferred dividends	-54,707				-54,707
Repurchase of non-controlling interest	-2,875			-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
Fees on equity issuance	40,000								40,000
Issued shares of Common Stock upon redemption of Series B Convertible Preferred Stock (in shares)		2,375,000
Issued shares of Common Stock upon redemption of Series B Convertible Preferred Stock	9,663	24		9,639
Shares withheld for taxes	-480			-480
Extinguishment of Eureka Hunter Holdings Series A Preferred Units	337,543			-51,692					389,235
Forfeiture of Eureka Hunter Holdings Series A-1 Units	32,569			32,569
Deconsolidation of Eureka Hunter Holdings	-436,968								-436,968
Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.	20,741					20,741			0
BALANCE at Dec. 31, 2014	$431,855	$2,014	$0	$909,783	($784,546)	($7,765)	($3,944)	$0	$0		$221,244	$95,069
BALANCE (in shares) at Dec. 31, 2014		201,421,000	0								4,425,000	4,000

CONSOLIDATED_STATEMENTS_OF_SHA1

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Warrants issued for payment of dividend	17,030,622
Warrants for payment of dividends on common stock, fair market value (in dollars)	$21.60

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
NET LOSS	($147,127)	($223,164)	($136,721)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	146,868	134,867	135,896
Share-based compensation	12,469	13,624	15,696
Impairment of proved oil and gas properties	301,276	89,041	4,096
Exploration	116,945	115,069	116,686
Impairment of other operating assets	730	0	0
(Gain) loss on sale of assets	11,399	-7,318	-3,074
Cash paid for plugging wells	-107	-14	0
Gain on deconsolidation of Eureka Hunter Holdings	-509,563	0	0
Loss from capital account adjustment of Eureka Hunter Holdings	32,569	0	0
Loss from equity method investment	1,038	994	1,971
Unrealized loss (gain) on open derivative contracts	-18,232	17,058	-10,945
Loss on extinguished embedded derivative	91,792	0	0
Unrealized loss (gain) on investments	0	-8,003	229
Amortization and write off of deferred financing cost and discount on Senior Notes included in interest expense	9,679	4,836	7,399
Deferred tax benefit	0	-84,527	-21,595
Changes in operating assets and liabilities:
Accounts receivable, net	8,533	22,781	-73,549
Inventory	4,381	4,658	-6,198
Prepaid expenses and other current assets	-3,071	-1,073	-538
Accounts payable	-51,930	42,050	16,390
Revenue payable	-2,953	-11,589	8,776
Accrued liabilities	-23,361	2,421	3,492
Net cash provided by (used in) operating activities	-18,665	111,711	58,011
CASH FLOWS FROM INVESTING ACTIVITIES
Change in restricted cash	5,000	-3,500	0
Capital expenditures and advances	-562,324	-631,511	-568,610
Cash paid in acquisitions, net of cash received of $0; $0; and $34, respectively	0	0	-444,844
Deconsolidation of the cash of Eureka Hunter Holdings	-6,380	0	0
Proceeds from sale of assets	193,139	506,297	4,158
Proceeds from partial sale of equity interest in Eureka Hunter Holdings	55,000	0	0
Change in deposits and other long-term assets	-2,554	854	89
Net cash used in investing activities	-318,119	-127,860	-1,009,207
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuing Senior Notes	0	0	596,907
Proceeds from borrowings on debt	629,392	373,991	546,043
Principal repayments of debt	-467,745	-380,923	-542,654
Proceeds from sale of Series A preferred units in Eureka Hunter Holdings	11,956	35,280	149,655
Issue Series A Common units of Eureka Hunter Holdings, net of costs	8,180	0	0
Issue Series A-2 Units of Eureka Hunter Holdings, net of costs	40,000	0	0
Net proceeds from sale of common stock	178,410	0	148,241
Net proceeds from sale of preferred shares	0	10,072	144,635
Net proceeds from sale of preferred shares	-2,875	0	0
Proceeds from exercise of warrants and options	9,663	5,352	2,331
Change in other long-term liabilities	1,023	-1,222	186
Purchase of treasury shares	0	0	-1,750
Payment of deferred financing costs	-14,208	-1,246	-20,313
Preferred stock dividends paid	-45,601	-40,648	-26,839
Net cash provided by financing activities	348,195	656	996,442
Effect of foreign exchange rate changes on cash	56	-417	-2,474
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	11,467	-15,910	42,772
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	41,713	57,623	14,851
CASH AND CASH EQUIVALENTS, END OF YEAR	$53,180	$41,713	$57,623

CONSOLIDATED_STATEMENTS_OF_CAS1

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Cash Flows [Abstract]
Cash Acquired from Acquisition	$0	$0	$34

ORGANIZATION_NATURE_OF_OPERATI

ORGANIZATION, NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Notes)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
ORGANIZATION, NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 1 - ORGANIZATION, NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Magnum Hunter Resources Corporation, a Delaware corporation, operating directly and indirectly through its subsidiaries (“Magnum Hunter” or the “Company”), is a Houston, Texas based independent oil and gas company engaged primarily in the exploration for and the exploitation, acquisition, development and production of natural gas and natural gas liquids resources predominantly in shale plays in the United States, along with certain oil field service activities and a substantial investment in midstream operations.
	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. Our 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 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 our wholly-owned subsidiary, Magnum Hunter Production, Inc. (“MHP”), and in various managed drilling partnerships. The Company accounts for the interests in these 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.
	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.
	Non-recurring items subject to significant estimates include the fair value of the Company’s retained financial interest in equity method investees.
	Actual results could differ from the estimates and assumptions utilized.
	Non-Controlling Interest in Consolidated Subsidiaries
	For the years ended December 31, 2013 and 2012, the Company consolidated Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”) in which it owned a 56.4% and 61.0% interest at December 31, 2013 and 2012, respectively. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline”), TransTex Hunter, LLC (“TransTex Hunter”), and Eureka Hunter Land, LLC. Eureka Hunter Pipeline 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 Hunter sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating natural gas at the wellhead.
	Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company no longer holds a controlling financial interest in Eureka Hunter Holdings. Accordingly, the results of operations of Eureka Hunter Holdings have been consolidated in the accompanying consolidated financial statements up to December 18, 2014. The Company held a 48.6% equity interest in Eureka Hunter Holdings at December 18, 2014 and at year-end 2014 and accounts for this retained interest under the equity method of accounting with the Company’s share of Eureka Hunter Holdings’ earnings recorded in “loss from equity method investment” in the accompanying consolidated statements of operations. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 10 - Investments and Derivatives”.
	Changes in the non-controlling interests attributable to entities in which the Company holds a controlling financial interest are accounted for as equity transactions, as they are considered investments by owners and distributions to owners acting in their capacity as owners. No gains or losses are recognized as the carrying value of the non-controlling interest is adjusted to reflect the change in the Company’s ownership interest in the subsidiary.
	Reclassification of Prior-Year Balances
	Certain prior year balances have been reclassified to correspond with the current year presentation. As a result of the Company’s decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented, and all assets and liabilities that were previously reported as assets and liabilities held for sale in our consolidated balance sheet have been reclassified to assets and liabilities held for use as of December 31, 2014. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
	The Company has separately classified transportation and processing expenses incurred to deliver gas to processing plants and/or to selling points, which were previously included as components of lease operating expenses and severance taxes and marketing, in the accompanying consolidated statements of operations for all periods presented. The Company has also renamed lease operating expenses as “Production costs” and presented transportation and processing expenses as “Transportation, processing, and other related costs” in order to provide more meaningful information on costs associated with production and development.
	SIGNIFICANT ACCOUNTING POLICIES
	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, 2014 and 2013. 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, 2014, the Company had cash deposits in excess of FDIC insured limits at various financial institutions.
	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, 2014 and 2013, 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, 2014 and 2013, the Company had $308 thousand and $196 thousand, respectively, in allowances for doubtful accounts with respect to its joint interest accounts receivable.
	Commodity and Financial Derivative Instruments
	The Company uses 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 has purchased certain investments that contain an embedded derivative. If the 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 the bifurcated derivative in “Gain (loss) on derivative contracts, net”.
	Inventory
	The Company’s materials and supplies inventory is acquired for use in future well completion and repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and to oilfield services expense in the accompanying consolidated statements of operations. As of December 31, 2014, the Company’s materials and supplies inventory is anticipated to be entirely used within the coming year, and all inventories are classified as current. See “Note 7 - Inventory”.
	The Company’s commodities inventories consist of crude oil held in storage and is carried at the lower of average lifting cost or market, on a first in, first out basis. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to production costs expense in the consolidated statements of operations. See “Note 7 - Inventory”.
	Investments
	Available for sale investments are comprised of common and preferred stock of companies publicly traded with quoted prices in active markets. Available-for-sale assets are securities and other financial investments that are neither held for trading, nor held to maturity, nor held for strategic reasons, and that have a readily available market price. As such, the gains and losses resulting from marking available-for-sale investments to market are not included in net income but are reflected in other comprehensive income until they are realized. The Company has no investments classified as trading securities or held to maturity securities.
	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 investees 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 Hunter Holdings and determined that impairment was not indicated as of December 31, 2014.
	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. A sale of an entire field is generally assessed for treatment as a discontinued operation.
	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 prices, which may make it uneconomic to drill for and produce from 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.
	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.
	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 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 December 31, 2014, the Company had net deferred financing costs of $22.9 million and recorded interest expense of $9.7 million related to the amortization and write-off of deferred financing costs for the year ended December 31, 2014.
	The Company evaluates changes and modifications of debt instruments under the guidance provided in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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.
	Goodwill and Other Intangible Assets
	In accordance with GAAP, goodwill is not amortized to earnings, but is assessed annually for impairment, or whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely. The Company has established April 1 as its annual assessment date, and all goodwill had been allocated to the Company’s midstream segment. If the carrying value of goodwill is determined to be impaired, it is reduced to its implied fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. ASC Topic 350, Intangibles - Goodwill and Other, permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Company used this approach, and performed a qualitative analysis as of April 1, 2014 and determined that no impairment existed.
	As a result of the Company’s loss of its controlling financial interest in Eureka Hunter Holdings, the Company determined an event had occurred which required a reassessment of its goodwill as of December 18, 2014. The Company performed a qualitative assessment of goodwill as of December 18, 2014 and determined that no impairment existed prior to deconsolidation. The Company also performed an analysis to determine the amount of goodwill allocated to the Eureka Hunter Holdings business. As a result, all goodwill and intangible assets were derecognized as part of the gain on deconsolidation. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	Intangible assets consisted primarily of acquired gas treating agreements and customer relationships of Eureka Hunter Holdings.  Such assets were being amortized over the estimated useful lives, which ranged from 2 to 13 years, up to December 18, 2014, when they were 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 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.
	Asset Retirement Obligation
	The asset retirement obligation (“ARO”) primarily represents 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.
	The 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 our 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 our 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 our 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, 2014 or 2013.
We apply 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 we meet 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. 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. 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. During the years ended December 31, 2014, 2013, and 2012 the Company recognized a translation loss of $1.2 million, a loss of $10.9 million, and a gain of $3.9 million, respectively.
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.
Unrealized gains and losses on changes in fair value of common and preferred stock of publicly traded companies designated as available for sale securities, are included in accumulated other comprehensive income. As of September 30, 2013, the Company had completed the sale of all of the shares of the Penn Virginia common stock it acquired in connection with its sale of Eagle Ford Hunter in April 2013. The Company received gross proceeds of $50.6 million, resulting in a reclassification out of comprehensive income of $8.3 million, which is classified within other income.
As of December 31, 2014, the Company had recorded $7.4 million in unrealized losses on available for sale securities in “Accumulated other comprehensive loss”.
Regulated Activities
Energy Hunter Securities, Inc. (“Energy Hunter Securities”) is a 100%-owned subsidiary and was a registered broker-dealer and member of the Financial Industry Regulatory Authority (“FINRA”) at December 31, 2013. Among other regulatory requirements, it was subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended. Because it did not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities was required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness.
On September 26, 2014, Energy Hunter Securities filed a Uniform Request for Withdrawal From Broker-Dealer Registration with the Securities and Exchange Commission (“SEC”). As of December 31, 2014, Energy Hunter Securities’ had fulfilled all requests from FINRA and its broker-dealer registration has been terminated.
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, 2014, 2013, and 2012, 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 $718,000, $216,000, and $511,000, 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 April 2014, the FASB issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 updates the requirements for reporting discontinued operations in ASC Subtopic 205-20, Presentation of Financial Statements - Discontinued Operations, by requiring classification as discontinued operations of a component of an entity or a group of components of an entity if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when either 1) the component or group of components of an entity meet the criteria to be classified as held for sale, 2) are disposed of by sale, or 3) are disposed of other than by sale (e.g. abandonment or a distribution to owners in a spinoff). The amendments in this update expand the disclosure requirements related to discontinued operations and disposals of individually significant components that do not qualify for discontinued operations presentation in the financial statements. This ASU is effective prospectively for all disposals (or classification as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: identify the contract(s) with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. This amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, however early application is not permitted. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In June 2014, the FASB issued ASU 2014-12, Compensation - Stock Compensation: Accounting for Share Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 clarifies that a performance target that affects vesting and that could be achieved after the requisite service period should be treated as a performance condition. An entity should apply existing guidance in ASC Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. This amendment is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
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 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. 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 is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging: Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity. This update requires that, for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering the economic characteristics and risks of the entire hybrid financial instrument, including the embedded derivative feature that is being evaluated for separate accounting from the host contract. The effects of initially adopting the amendment should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. This amendment is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
In November 2014, the FASB issued ASU 2014-17, Business Combinations: Pushdown Accounting. ASU 2014-17 provides an acquired entity with the option to apply pushdown accounting in its separate financial statements upon the occurrence of an event in which an acquirer obtains control of the acquired entity. The election to apply pushdown accounting may be made each time there is a change-in-control event. If the acquired entity does not elect to apply pushdown accounting upon a change-in-control event, it can elect to apply pushdown accounting to its most recent change-in-control event in a subsequent reporting period as a change in accounting principle. This amendment is effective as of November 18, 2014. The adoption of this updated standard did not have any impact on the Company’s consolidated financial statements and financial statement disclosures.

DECONSOLIDATION_OF_EUREKA_HUNT

DECONSOLIDATION OF EUREKA HUNTER HOLDINGS (Notes)	12 Months Ended
	Dec. 31, 2014
Noncontrolling Interest [Abstract]
Deconsolidation Of Eureka Hunter Holdings	NOTE 2 - DECONSOLIDATION OF EUREKA HUNTER HOLDINGS
	On September 16, 2014, the Company entered into an agreement (the “Transaction Agreement”) with MSIP II Buffalo Holdings LLC, an affiliate of Morgan Stanley Infrastructure, Inc. (“MSI”) and a non-related party, and Eureka Hunter 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 Hunter 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 Hunter Holdings and the execution of the Second Amended and Restated Limited Liability Company Agreement of Eureka Hunter Holdings (the “New LLC Agreement”) (the “First Closing”); and (ii) the purchase by MSI of an additional equity interest in Eureka Hunter 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.
	Contemporaneously with the First Closing, the New LLC Agreement for Eureka Hunter Holdings became effective. In accordance with the terms of the New LLC Agreement, all of the Eureka Hunter Holdings Series A Preferred Units and Class A Common Units of Eureka Hunter Holdings acquired by MSI from Ridgeline were converted into Series A-2 Common Units, a new class of equity interests of Eureka Hunter Holdings (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 Hunter 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 Hunter 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 Hunter Holdings Series A Preferred Units and the fair value associated with the embedded derivative attached to the Eureka Hunter 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 Hunter 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 Hunter 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 Hunter Holdings, which collectively would constitute an approximate 98% equity interest in Eureka Hunter Holdings.
	The Transaction Agreement and the Letter Agreement (described below) further provide that the Company has the right, under certain circumstances, to not make its portion of certain required future capital contributions to Eureka Hunter 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. We refer 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. As of December 31, 2014, the Company had deferred capital contributions of $30 million, for which it has the right to make future catch-up contributions.
	On November 18, 2014, the Company, Eureka Hunter 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 Hunter Holdings, and MSI agreed to reduce the Company’s capital account in Eureka Hunter 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 Hunter Pipeline in connection with certain of Eureka Hunter Pipeline’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 Hunter Holdings and MSI also agreed to adjust the amount and timing of (i) certain capital contributions by the Company and MSI to Eureka Hunter Holdings and (ii) MSI’s purchase of a portion of the Company’s equity interests in Eureka Hunter Holdings pursuant to the Second Closing as follows:
	i.	In connection with certain of Eureka Hunter Pipeline’s capital projects for fiscal year 2014, on November 20, 2014, MSI made a $30 million capital contribution in cash to Eureka Hunter 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 Hunter 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 Hunter Holdings in exchange for additional Series A-2 Units.
	iv.	The Second Closing was accelerated to the date of 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 has also agreed to make a $13.3 million capital contribution in cash to Eureka Hunter Holdings on or before March 31, 2015 in exchange for additional Series A-1 Units. However, the Company and MSI subsequently entered into discussions regarding Eureka Hunter Holdings’ 2015 capital expenditure budget, including the amount, timing and expected funding of the various anticipated capital expenditures. The Company anticipates that, as a result of these discussions, the parties will determine the priority, timing and (to the extent not funded by operating cash flows or borrowings) allocation between the parties of the funding of the anticipated expenditures that will most effectively serve the 2015 project plans of Eureka Hunter Pipeline. The Company also anticipates that, as part of these determinations, MSI will make the $13.3 million cash capital contribution referred to above in exchange for additional Series A-2 Units under the terms of the carried interest provisions discussed above. See “Note 11 - Long-Term Debt” for a description of the Company’s revolving credit facility, including a description of the restrictions under that facility on the Company’s ability to make investments in Eureka Hunter Holdings.
	At December 31, 2014, the Company and MSI owned 48.60% and 49.84%, respectively of the equity interests of Eureka Hunter Holdings.
	The Transaction Agreement also provided MSI with certain substantive participation rights which allow MSI to participate in the management and operation of Eureka Hunter Holdings. As a result of MSI acquiring additional Series A-2 Units, which brought their total equity interest in Eureka Hunter Holdings to 49.84% as of December 18, 2014, the board of managers of Eureka Hunter Holdings was expanded from five to six members and MSI appointed the sixth manager, so that the board of managers of Eureka Hunter 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 Hunter 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 Hunter Holdings and, therefore, the Company deconsolidated Eureka Hunter 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 Hunter Holdings was 48.60%, 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 Hunter 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 Hunter Holdings at December 18, 2014. Approximately $187.2 million of the pre-tax gain is 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 Hunter Holdings. Eureka Hunter Holdings is considered an affiliate and a related party subsequent to the deconsolidation as the Company as a result of the Company’s continued investment in and transactions with Eureka Hunter Holdings.
	Summarized income information for Eureka Hunter Holdings from December 18, 2014 through December 31, 2014 is as follows:
			Fourteen days ended December 31, 2014
			(in thousands)
	Operating revenues		$	2,124
	Operating income		$	74
	Net loss		$	(207	)
	Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014		$	(101	)
	Summarized balance sheet information for Eureka Hunter Holdings as of December 31, 2014 is as follows:
			31-Dec-14
			(in thousands)
	Current assets		$	17,113
	Non-current assets		$	445,450
	Current liabilities		$	63,313
	Non-current liabilities		$	100,037
	The following table reconciles the carrying value of the Company’s equity method investment in Eureka Hunter Holdings to the net assets of Eureka Hunter Holdings.
			31-Dec-14
			(in thousands)
	Net Assets of Eureka Hunter Holdings attributable to Magnum Hunter, at December 18, 2014		$	145,418
	Basis difference		201,874
	Loss from equity method investment Eureka Hunter Holdings for the period from December 18, 2014 to December 31, 2014		(101		)
	Magnum Hunter’s investment in Eureka Hunter Holdings		$	347,191
	The recognition of the Company's retained interest in Eureka Hunter Holdings at fair value upon deconsolidation resulted in a basis difference between the carrying value of the Company’s investment in Eureka Hunter Holdings and its proportionate share in net assets of Eureka Hunter Holdings.  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 Hunter Holdings will be accounted for as if Eureka Hunter Holdings were a consolidated subsidiary.  Under this method, the basis difference will be allocated to the Company's proportionate share of Eureka Hunter Holdings’ identifiable assets and liabilities.  The portion of the basis difference attributable to tangible and definite lived intangible assets will be amortized over their respective estimated useful lives and reflected as a component of “Income (loss) from equity method investment”.
	Magnum Hunter is currently determining the fair value of certain assets of Eureka Hunter Holdings.  The valuation is expected to be finalized in the first half of 2015.  The Company has estimated that the amortization of the basis difference allocable to the 14 day period from December 18, 2014 to December 31, 2014 (the “short period”) was not material.  However, once a final allocation of fair value is made, the related depreciation and amortization for the short period may be significantly different from its initial estimate.  The Company does not expect that its loss from equity method investment in Eureka Hunter Holdings during the short period will be materially different as a result of the fair value determination.

ACQUISITIONS_DIVESTITURES_AND_

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS (Notes)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
ACQUISITIONS	NOTE 3 - ACQUISITIONS, DIVESTITURES, AND DISCONTINUED OPERATIONS
	Acquisitions
	The Company has recognized $27,000, $2.8 million, and $4.7 million of transaction expenses related to acquisitions in its general and administrative expenses for the years ended December 31, 2014, 2013, and 2012, respectively. Substantially all of the Company's acquisitions contained a significant amount of unproved acreage, as is consistent with the Company's business strategy.
	Eagle Operating Assets Acquisition
	On March 30, 2012, the Company, through its wholly-owned subsidiary, Williston Hunter ND, LLC, a Delaware limited liability company (“Williston Hunter”), closed on the purchase of operating working interest in certain oil and gas leases and wells located in several counties in North Dakota from Eagle Operating, Inc. (“Eagle Operating”), an unrelated third party, effective April 1, 2011.  Total consideration was $52.9 million consisting of $51.0 million in cash and 296,859 shares of Magnum Hunter restricted common stock valued at $1.9 million based on a price of $6.41 per share. The purpose of the acquisition was to expand the Company’s position in the Williston Basin. The Company already owned a non-operated ownership interest in the properties acquired.
	TransTex Gas Services, LP Assets Acquisition
	On April 2, 2012, the Company, through Eureka Hunter Holdings, and its wholly-owned subsidiary, Eureka Hunter Acquisition Sub, LLC, closed on their purchase of certain assets of TransTex Gas Services, LP (“TransTex”), a related third party, under an asset purchase agreement dated March 21, 2012, which resulted in the recognition of approximately $30.6 million in goodwill and $10.5 million of intangible assets.  The goodwill acquired in the TransTex acquisition, which is associated with the Eureka Hunter Holdings, was deductible for tax purposes prior to the deconsolidation of Eureka Hunter Holdings. The purpose of the acquisition was to complement the Company’s existing midstream assets.  The total purchase price paid for the acquired assets was $58.5 million, comprised of $46.0 million in cash and 622,641 Eureka Hunter Holdings Class A Common Units representing membership interests in Eureka Hunter Holdings, with a value of $12.5 million based on an estimated enterprise value of $400.0 million determined at that time utilizing a discounted future cash flow analysis.  The goodwill and intangible assets associated with the TransTex acquisition were derecognized as a result of the deconsolidation of Eureka Hunter Holdings on December 18, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	Gary C. Evans, the Company’s Chairman and CEO, previously held a small limited partnership interest in TransTex and participated in the purchase of certain Eureka Hunter Holdings Class A Common Units offered to all limited partners of TransTex in connection with the acquisition. See “Note 17 - Related Party Transactions”.
	Baytex Energy USA Assets Acquisition
	On May 22, 2012, the Company, through its wholly-owned subsidiary, Bakken Hunter, LLC (“Bakken Hunter”), closed on the acquisition of certain Williston Basin assets of Baytex Energy USA, Ltd. (“Baytex Energy USA”), an affiliate of Baytex Energy Corporation, an unrelated third party, for a total purchase price of $312.0 million.  The purpose of the acquisition was to significantly increase the Company’s ownership interest in existing mineral leases in a key shale play where the Company has increased its drilling activities. To a lesser extent, proved reserves were added attributable to the acquired properties. The acquired assets include all of Baytex Energy USA’s non-operated working interest in oil and gas properties and wells located in Divide and Burke Counties, North Dakota, within an area subject to an operating agreement among Samson Resources Company, as operator, Baytex Energy Corporation, and Williston Hunter, Inc., a wholly-owned subsidiary of Magnum Hunter.
	Acquisition of Viking International Resources Co., Inc.
	On November 2, 2012, Triad Hunter, LLC (“Triad Hunter”), a wholly-owned subsidiary of the Company, closed on the acquisition of all outstanding capital stock of Viking International Resources Co., Inc. (“Virco”) effective January 1, 2012.  The total fair market value of the consideration paid was approximately $100.8 million, made up of approximately $37.3 million paid in cash and 2,774,850 depositary shares representing 2,774.85 shares of 8.0% Series E Cumulative Convertible Preferred Stock of the Company with market value of approximately $65.2 million and stated liquidation preference of approximately $69.4 million. See “Note 13 - Shareholders' Equity” regarding the Series E Preferred Stock. The primary purpose of the acquisition was to acquire leasehold acreage and wells complementary to the Company's existing acreage position of this region and expand its ownership interest in the Marcellus Shale and Utica Shale plays in West Virginia and Ohio.
	The following summarizes the revenue and operating income (loss) from the acquisitions included in the Company's consolidated statements of operations for the years ended December 31, 2014, 2013, and 2012 (TransTex revenues and operating loss were included through December 18, 2014, the date of deconsolidation of Eureka Hunter Holdings):
		For the year ended December 31,
		2014							2013						2012
		Revenues				Operating Income (loss)			Revenues			Operating Income (loss)			Revenues		Operating Income (loss)
		(in thousands)
	Eagle Operating assets	$	2			$	938		$	7,331		$	(26,867	)	$	5,500	$	(3,019	)
	TransTex assets	$	9,729			$	(2,995	)	$	12,765		$	(812	)	$	7,014	$	(393	)
	Baytex Energy USA assets	$	102,146			$	(352,151	)	$	100,572		$	(101,627	)	$	18,430	$	(6,649	)
	VIRCO acquisition	$	3,194			$	(7,936	)	$	4,453		$	(177	)	$	1,094	$	450
	The following unaudited summary, prepared on a pro forma basis, presents the results of operations for the year ended December 31, 2012, as if the above acquisitions along with transactions necessary to finance the acquisitions, had occurred as of the beginning of 2011. The pro forma information includes the effects of adjustments for interest expense, depreciation and depletion expense, and dividend expense. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of 2011, nor are they necessarily indicative of future consolidated results.
		Pro Forma
		For the Year Ended December 31,
			2012
		(in thousands except for per share amount, unaudited)
	Oil and natural gas sales		$	159,085
	Operating loss		$	(108,177	)
	Net loss		$	(150,777	)
	Net loss attributable to Magnum Hunter Resources Corporation		$	(146,764	)
	Net loss attributable to common shareholders		$	(188,736	)
	Loss per common share, basic and diluted		$	(1.21	)
	Samson Resources Assets Acquisition
	On December 20, 2012, Bakken Hunter, a wholly-owned subsidiary of the Company, closed on the acquisition of certain existing wells and Williston Basin lease acres located in Divide County, North Dakota from Samson Resources Company. The purchase price for the assets was $30.0 million in cash, subject to customary adjustments. The effective date of the transaction was August 1, 2012.
	With the closing of this transaction, the Company owns varied working ownership interests in these properties up to approximately 100%. The acquisition established the Company as an operator in certain of this Bakken acreage, covering four Townships and Ranges in northern Divide County, North Dakota, previously operated by Samson Resources Company.
	Agreements to Purchase Utica Shale Acreage
	On August 12, 2013, Triad Hunter entered into an asset purchase agreement, with MNW Energy, LLC (“MNW”). MNW is an Ohio limited liability company that represents an informal association of various land owners, lessees and sub-lessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the purchase agreement, Triad Hunter 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, 2014 and 2013, Triad Hunter purchased 16,456 and 5,922 net leasehold acres, respectively, from MNW for an aggregate purchase price of $67.3 million and $24.6 million, respectively. 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
	In September 2013, the Company adopted a plan to divest all of its interests in (i) MHP, whose oil and natural gas operations are located primarily in the southern Appalachian Basin in Kentucky and Tennessee, and (ii) the Canadian operations of WHI Canada, which was a wholly-owned subsidiary of the Company.
	Planned Divestiture of Magnum Hunter Production
	In connection with the Company’s adoption of a plan to divest of its interest in MHP in September 2013, 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 classified the associated assets and liabilities of MHP as assets and liabilities held for sale in the consolidated balance sheet as of September 30, 2013 and reflected the results of MHP’s operations as discontinued operations in the consolidated statements of operations for the three and nine months ended September 2013 and 2012. 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. Consequently, the Company continued to report the results of operations for MHP, including the results of operations of MHP for comparable periods presented from a preceding year, as a component of discontinued operations in the Company’s consolidated financial statements for each interim and annual period from September 30, 2013 through June 30, 2014, and reported the assets and liabilities of MHP as assets and liabilities held for sale on the corresponding consolidated balance sheets.
	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.
	The Company reclassified the results of MHP’s operations from discontinued operations to continuing operations for all periods presented in these consolidated financial statements, and MHP’s assets and liabilities have been reclassified out of assets and liabilities held for sale and included with the Company’s other assets held and used as of December 31, 2014.
	Williston Hunter Canada Asset Sale
	On April 10, 2014, WHI Canada closed on the sale of certain oil and natural gas properties and assets located in Alberta, Canada for cash consideration of CAD $9.5 million in cash (approximately U.S. $8.7 million at the exchange rate as of the close of business on April 10, 2014). The effective date of the sale was January 1, 2014. The Company recognized a gain of $6.1 million which is recorded in gain (loss) on disposal of discontinued operations.
	Sale of Williston Hunter Canada
	On May 12, 2014, the Company closed on the sale of 100% of its ownership interest in the Company’s Canadian subsidiary, WHI Canada, whose assets consisted primarily of oil and natural gas properties located in the Tableland Field in Saskatchewan, Canada, for a purchase price of CAD $75.0 million (approximately U.S. $68.8 million at the exchange rate as of the close of business on May 12, 2014), prior to customary purchase price adjustments, with an effective date of March 1, 2014, of which CAD $18.4 million was placed in escrow pending final approval from the Canadian Revenue Authority. 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 our foreign operation.
	There were no assets or liabilities held for sale at December 31, 2014. The following shows the Company’s assets and liabilities held for sale at December 31, 2013:
		31-Dec-13
		(in thousands)
	Accounts receivable	$	4,362
	Other current assets	1,004
	Oil and natural gas properties, net	150,770
	Gas transportation, gathering, and processing equipment and other, net	11,721
	Other long-term assets	196
	Total assets held for sale	$	168,053
	Accounts payable	$	7,292
	Accrued liabilities and other liabilities	5,573
	Asset retirement obligations	8,678
	Other long-term liabilities	5,845
Total liabilities held for sale	$	27,388
Sale of Hunter Disposal
On February 17, 2012, the Company, through its wholly-owned subsidiary Triad Hunter, sold 100% of its equity ownership interest in Hunter Disposal to a wholly-owned subsidiary of GreenHunter Resources, Inc. (“GreenHunter”), for total consideration of $9.3 million, comprised of cash of $2.2 million, 1,846,722 restricted common shares of GreenHunter, valued at $2.6 million based on a closing price of $1.79 per share, discounted for restrictions, 88,000 shares of GreenHunter 10% Series C Preferred Stock, with a fair value of $1.9 million, and a promissory note of $2.2 million which is convertible, at the option of the Company, into 880,000 shares of GreenHunter common stock based on the conversion price of $2.50 per share. The Company recognized an embedded derivative asset resulting from the conversion option on the convertible promissory note with an initial fair value of $405,000. See “Note 9 - Fair Value of Financial Instruments”. The cash proceeds from the sale were adjusted downward to $783,000 for changes in working capital and certain fees to reflect the effective date of the sale of December 31, 2011. Triad Hunter recognized a gain on the sale of discontinued operations of $3.7 million, $2.4 million net of tax of $1.3 million. GreenHunter is a related party as described in “Note 17 - Related Party Transactions”.
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 our Canadian Upstream segment, through May 12, 2014, Eagle Ford Hunter, which has historically been included as part of the U.S. Upstream segment, through April 24, 2013, and Hunter Disposal, which has historically been included as part of the Oilfield Services segment, through February 17, 2012 in discontinued operations as follows:
	Year Ended December 31,
	2014				2013			2012
	(in thousands)
Revenues	$	8,533			$	67,490		$	114,068
Expenses (1)	(3,975		)		(130,331		)	(122,099		)
Other income (expense)	3				186			(94		)
Income (loss) from discontinued operations before tax	4,561				(62,655		)	(8,125		)
Income tax benefit (expense) (2)	—				94			(1,648		)
Income (loss) from discontinued operations, net of tax	4,561				(62,561		)	(9,773		)
Gain (loss) on disposal of discontinued operations, net of taxes (3)(4)	(13,855		)		71,510			2,409
Income (loss) from discontinued operations, net of tax	$	(9,294	)		$	8,949		$	(7,364	)
_____________________
-1	Includes impairment expense of $65.4 million, and $0.3 million for the years ended December 31, 2013 and 2012, respectively, and exploration expense of $0.1 million, $19.9 million, and $36.8 million for the years ended December 31, 2014, 2013, and 2012, 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, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, 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.
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 pending final adjustments.
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 $2.7 million pending final adjustments.
Sale of Certain Other Eagle Ford Shale Assets
On January 28, 2014, the Company, through its wholly-owned subsidiary Shale Hunter, LLC (“Shale Hunter”) and certain other affiliates, closed on the sale of certain of 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 have been designated as available for sale securities, which are recorded at fair value of approximately $2.5 million and included in investments in the consolidated balance sheet as of December 31, 2014. The Company recognized a loss on the sale of the Shale Hunter assets of $4.5 million during the first quarter of 2014.
In connection with the closing of the sale, Shale Hunter and NSE Texas entered into a transition services agreement which provides that, during a specified transition period ending on July 28, 2015 unless otherwise extended or modified, Shale Hunter will provide NSE Texas with certain transitional services relating to the assets sold for which Shale Hunter is receiving a monthly fee.
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 $1.1 million pending final adjustments.

OIL_NATURAL_GAS_SALES_Notes

OIL & NATURAL GAS SALES (Notes)	12 Months Ended
	Dec. 31, 2014
Oil and Natural Gas Sales [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	NOTE 4 - OIL & NATURAL GAS SALES
	During the years ended December 31, 2014, 2013, and 2012, the Company recognized sales from oil, natural gas, and natural gas liquids (“NGLs”) as follows:
		Year Ended December 31,
		2014		2013		2012
				(in thousands)
	Oil	$	131,109	$	147,798	$	82,225
	Natural gas	91,277		53,821		45,825
	NGLs	46,115		19,080		5,678
	Total oil and natural gas sales	$	268,501	$	220,699	$	133,728

PROPERTY_PLANT_EQUIPMENT_Notes

PROPERTY, PLANT, & EQUIPMENT (Notes)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant & Equipment	NOTE 5 - 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,
		2014			2013
		(in thousands)
	Mineral interests in properties:
	Unproved leasehold costs	$	481,643		$	469,337
	Proved leasehold costs	257,185			336,357
	Wells and related equipment and facilities	560,060			438,275
	Uncompleted wells, equipment and facilities	46,346			97,748
	Advances to operators for wells in progress	1,411			13,571
	Total costs	1,346,645			1,355,288
	Less accumulated depreciation, depletion, and amortization	(248,410		)	(130,629		)
	Net capitalized costs	$	1,098,235		$	1,224,659
	Depreciation, depletion, and amortization expense for proved oil and natural gas properties was $121.9 million, $69.0 million, and $49.2 million for the years ended December 31, 2014, 2013, and 2012, respectively.
	During the years ended December 31, 2014, 2013 and 2012, the Company recorded proved property impairments as follows:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Williston Basin	$	261,270		$	8,498		$	3,631
	Appalachian Basin	6,001			1,151			76
	Western Kentucky	33,811			40,043			67
	South Texas	194			319			65
		$	301,276		$	50,011		$	3,839
	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 2014, 2013 and 2012:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Geological and geophysical	$	1,564		$	1,402		$	2,570
	Leasehold impairments:
	Williston Basin	103,147			89,167			59,214
	Appalachian Basin	9,978			6,773			15,033
	Western Kentucky	3,820			3,047			2,154
	South Texas	—			—			1,404
		$	118,509		$	100,389		$	80,375
	The Company did not drill any dry holes during the years ended December 31, 2014, 2013, or 2012. All wells drilled were completed as producing wells.
	Capitalized Exploratory Well Costs Greater Than a Year
	As of December 31, 2014, the Company had suspended exploratory well costs capitalized for periods greater than one year related to the Farley pad in Washington County, Ohio and the Farley #1305H well. The Farley pad was constructed to drill multiple horizontal wells into a previously untested zone in the Utica formation. The Company spud the Farley #1305H in April of 2013 and experienced well pressure instability during the fracture stimulation stage of completion. Further fracture stimulation and evaluation of this well will depend on the outcome of the drilling and completion of the Farley #1306H and #1304H wells, which were drilled in 2014 and are expected to be fracture stimulated and tested during mid-year 2015. Aggregate cost incurred through December 31, 2014 for the Farley pad and the Farley #1305H well were $1.1 million and $13.8 million, respectively.
	Gas Transportation, Gathering, and Processing Equipment and Other
	The historical cost of gas transportation, gathering, and processing equipment and other property, presented on a gross basis with accumulated depreciation, as of December 31, 2014 and 2013, is summarized as follows:
		December 31,
		2014			2013
		(in thousands)
	Gas transportation, gathering and processing equipment and other	$	100,436		$	315,642
	Less accumulated depreciation and depletion	(23,013		)	(26,222		)
	Net capitalized costs	$	77,423		$	289,420
	Depreciation expense for other property and equipment was $22.1 million, $15.6 million, and $8.1 million, for the years ended December 31, 2014, 2013, and 2012, respectively.
	As a result of the deconsolidation of Eureka Hunter Holdings, the Company derecognized gas transportation, gathering and processing equipment relating to Eureka Hunter Holdings of $439.0 million, net of accumulated depreciation and depletion of $30.3 million.

INTANGIBLE_ASSETS_Notes

INTANGIBLE ASSETS (Notes)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	NOTE 6 - INTANGIBLE ASSETS
	Following the change in accounting treatment of the Company’s investment in Eureka Hunter Holdings on December 18, 2014, the net unamortized intangible assets of TransTex were derecognized and included in the carrying amount of Eureka Hunter Holdings in determining the gain on deconsolidation. There are no remaining intangible assets as of December 31, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	The following table summarizes the Company's net intangible assets during the year ended December 31, 2013:
		December 31,
		2013
		(in thousands)
	Customer relationships	$	5,434
	Trademark	859
	Existing contracts	4,199
	Total intangible assets	10,492
	Accumulated amortization:
	Customer relationships	(1,248		)
	Trademark	(137		)
	Existing contracts	(2,577		)
	Intangible assets, net of accumulated amortization	$	6,530
	Amortization expense for intangible assets was $2.0 million, $2.5 million, and $1.5 million for the years ended December 31, 2014, 2013, and 2012, respectively. As a result of the deconsolidation of the Company’s interest in Eureka Hunter Holdings, the Company expects no additional aggregate amortization of intangible assets over the next five years.

INVENTORY_Notes

INVENTORY (Notes)	12 Months Ended
	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventory	NOTE 7 - INVENTORY
	The following table sets forth the composition of the Company's inventory as of December 31, 2014 and December 31, 2013.
		December 31,
		2014		2013
		(in thousands)
	Materials and supplies	$	1,436	$	6,790
	Oil in tanks	832		368
	Inventory	$	2,268	$	7,158

ASSET_RETIREMENT_OBLIGATIONS_N

ASSET RETIREMENT OBLIGATIONS (Notes)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 8 - ASSET RETIREMENT OBLIGATIONS
	The Company's ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the 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 liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with a corresponding increase to proved properties. The Company records accretion of the estimated liability as accretion expense in depreciation, depletion, amortization, and accretion in the consolidated statements of operations.
	The Company's 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 $26.5 million and $16.2 million at December 31, 2014 and 2013, respectively.
	The following table summarizes the changes in the Company’s ARO balances during the years ended December 31, 2014 and 2013:
		December 31,
		2014			2013
		(in thousands)
	Asset retirement obligation at beginning of period	$	16,216		$	30,680
	Assumed in acquisition	—			17
	Liabilities incurred	218			253
	Liabilities settled	(107		)	(98		)
	Liabilities sold	(2,598		)	(7,614		)
	Accretion expense	1,478			2,264
	Revisions in estimated liabilities	3,208			1,935
	Reclassified as liabilities associated with assets held for sale	—			(11,148		)
	Reclassified from liabilities associated with assets held for sale	8,109			—
	Correction of prior year error	—			(73		)
	Asset retirement obligation at end of period	26,524			16,216
	Less: current portion	(295		)	(53		)
	Asset retirement obligation at end of period	$	26,229		$	16,163

FAIR_VALUE_OF_FINANCIAL_INSTRU

FAIR VALUE OF FINANCIAL INSTRUMENTS (Notes)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	NOTE 9 - FAIR VALUE OF FINANCIAL INSTRUMENTS
	Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standards also establish a framework for measuring fair value and a valuation hierarchy based upon the transparency of inputs used in the valuation of an asset or liability.  Classification within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The valuation hierarchy contains three levels:
	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 1 and 2 occur at the end of the reporting period in which it is determined that the observability of significant inputs has increased or decreased. There were no transfers between levels of the fair value hierarchy during 2014 and 2013.
	The Company used the following fair value measurements for certain of its assets and liabilities during the years ended December 31, 2014 and 2013:
	Level 1 Classification:
	Available for Sale Securities
	At December 31, 2014 and 2013, the Company held common and preferred stock of publicly traded companies with quoted prices in an active market. Accordingly, the fair market value measurements of these securities have been classified as Level 1.
	Level 2 Classification:
	Commodity Derivative Instruments
	At December 31, 2014 and December 31, 2013, the Company had commodity derivative financial instruments in place.  The Company does not designate its derivative instruments as hedges and therefore does not apply hedge accounting.  Changes in fair value of derivative instruments subsequent to the initial measurement are recorded as gain (loss) on derivative contracts, in other income (expense).  The estimated fair values 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”.
	As of December 31, 2014 and December 31, 2013, the Company’s derivative contracts were with financial institutions, many of which were either senior lenders to the Company or affiliates of such senior lenders, and some of which had investment grade credit ratings. Certain counterparties to the Company’s commodity derivatives positions are no longer participants in the Company’s credit facilities following the execution of new credit agreements on October 22, 2014. See “Note 11 - Long-Term Debt”. All of the counterparties are believed to have minimal credit risk.  Although the Company is exposed to credit risk to the extent of nonperformance by the counterparties to these derivative contracts, the Company does not anticipate such nonperformance and monitors the credit worthiness of its counterparties on an ongoing basis.
	Level 3 Classification:
	Preferred Stock Embedded Derivative
	At December 31, 2013, the Company had a preferred stock derivative liability resulting from its Eureka Hunter Holdings Series A Preferred Units, which contained certain conversion features, redemption options, and other features.
	The fair value of the bifurcated conversion feature was valued using the “with and without” analysis in a simulation model based upon management’s estimate of the expected life of the conversion feature. The key inputs used in the model to determine fair value were estimated volatility, credit spread, and the estimated enterprise value of Eureka Hunter Holdings.
	The selection of assumptions for expected term and total enterprise value were made based on a weighting of possible outcomes. The term of the conversion feature, which was linked to the terms of the Eureka Hunter Holdings Amended and Restated Limited Liability Company Agreement (“Eureka Hunter Holdings LLC Agreement”), could range from zero to six years. During the three-month period ended June 30, 2014, the Company changed the estimated term to one to two years due to changes in the Company's expectation of when the conversion feature with respect to the Eureka Hunter Holdings Series A Preferred Units would be exercised. On October 3, 2014, MSI purchased all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units and Class A Common Units held by Ridgeline, which constituted all of the issued and outstanding Eureka Hunter Holdings Series A Preferred Units. In making the Company's determination of the total enterprise value for Eureka Hunter Holdings, the Company considered the purchase price associated with MSI's purchase of the Eureka Hunter Holdings Series A Preferred Units, and its implied value to the enterprise as a whole. The issued and outstanding Eureka Hunter Holdings Series A Preferred Units were converted at fair value to a new class of preferred equity of Eureka Hunter Holdings on October 3, 2014, pursuant to the provisions of the New LLC Agreement, which became effective October 3, 2014. See “Note 14 - Redeemable Preferred Stock”.
	The fair value calculation is sensitive to movements in volatility, estimated remaining term, and the total enterprise value of Eureka Hunter Holdings. A decrease in the estimated term of the conversion feature results in a higher fair value of the conversion feature. As the implied volatility of the instruments increases so too does the fair value of the derivative liability arising from the conversion and redemption features. Similarly, as the total enterprise value of Eureka Hunter Holdings increases, the fair value of the derivative liability increases. Decreases in volatility and total enterprise value would result in a reduction to the fair value of the derivative liability associated with these instruments.
	Convertible Security Embedded Derivative
	The Company recognized an embedded derivative asset resulting from the fair value of the bifurcated conversion feature associated with the convertible note received as partial consideration upon the sale of Hunter Disposal to GreenHunter, a related party. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.  The convertible security embedded derivative was valued using a Black-Scholes model valuation of the conversion option.
	The key inputs used in the Black-Scholes option pricing model were as follows:
		31-Dec-14
	Life	2.1			years
	Risk-free interest rate	0.95			%
	Estimated volatility	91			%
	Dividend	—
	GreenHunter Resources Stock price at end of period	$	0.71
	The sensitivity of the estimate of volatility used in determining the fair value of the convertible security embedded derivative would not have a significant impact to the Company’s financial statements based on the value of the assets as compared to the financial statements as a whole.
	The following tables present financial assets and liabilities which are adjusted to fair value on a recurring basis at December 31, 2014 and 2013:
		Fair Value Measurements on a Recurring Basis
		31-Dec-14
		(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
		Fair Value Measurements on a Recurring Basis
		31-Dec-13
		(in thousands)
		Level 1				Level 2				Level 3
	Available for sale securities	$	1,819			$	—			$	—
	Commodity derivative assets	—				554				—
	Convertible security derivative assets	—				—				79
	Total assets at fair value	$	1,819			$	554			$	79
	Commodity derivative liabilities	$	—			$	2,279			$	—
	Convertible preferred stock derivative liabilities	—				—				75,934
	Total liabilities at fair value	$	—			$	2,279			$	75,934
	The following table presents 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, 2014, 2013 and 2012:
		Embedded Derivatives
		Series A Preferred Units				Convertible Security
		(in thousands)
	Fair value at December 31, 2011	$	—			$	—
	Issuance of embedded derivative (liability) asset	(52,240		)		405
	Decrease in fair value recognized in gain on derivative contracts, net	8,692				(141		)
	Fair value at December 31, 2012	$	(43,548	)		$	264
	Issuance of embedded liability	(14,645		)		—
	Increase 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		)		—
	Increase in fair value recognized in loss on derivative contracts, net	(91,792		)		(4		)
	Conversion of Eureka Hunter Holdings Series A Preferred Units to Series A-2 Units	173,205				—
Fair value as of December 31, 2014	$	—			$	75
During the year ended December 31, 2014, the valuation of the conversion feature embedded in the Eureka Hunter Holdings Series A Preferred Units increased the fair value of the embedded derivative liability by approximately $91.8 million as a result of changes in the total enterprise value of Eureka Hunter Holdings and the Company’s estimate of the expected remaining term of the conversion feature 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 Hunter Holdings.
Other Fair Value Measurements
The following table presents the carrying amounts and fair values categorized by fair value hierarchy level of the Company’s financial instruments not carried at fair value:
		Fair Value		31-Dec-14								31-Dec-13
		Hierarchy Level		Carrying Amount				Estimated Fair Value				Carrying Amount		Estimated Fair Value
				(in thousands)
Senior Notes		Level 2		$	597,355			$	498,000			$	597,230	$	651,300
MHR Senior Revolving Credit Facility		Level 3		—				—				218,000		218,000
MHR Second Lien Term Loan		Level 3		329,140				329,140				—		—
Eureka Hunter Pipeline term loan		Level 3		—				—				50,000		58,291
Equipment notes payable		Level 3		22,238				22,150				18,615		17,676
The fair value of the Company's Senior Notes is based on quoted market prices available for Magnum Hunter’s Senior Notes.   The fair value hierarchy for the Company's Senior Notes is Level 2 (quoted prices for identical or similar assets in markets that are not active).
The carrying values of the Company's senior revolving credit facility (“MHR Senior Revolving Credit Facility”) approximate fair value as the facility is subject to short-term floating interest rates that approximate the rates available to the Company at these dates.  The fair value hierarchy for the MHR Senior Revolving Credit Facility is Level 3.
The carrying value of the Company’s second lien term loan as of December 31, 2014 approximates fair value based upon to 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 fair value of Eureka Hunter Pipeline's term loan as of December 31, 2013 is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate.  The credit spread is the Company’s default or repayment risk.  The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt.  Eureka Hunter Pipeline’s second lien term loan was paid in full in March 2014.
The fair value of all fixed-rate notes and the credit facility is based on interest rates currently available to the Company.
Fair Value on a Non-Recurring Basis
The Company follows the provisions of ASC Topic 820, Fair Value Measurement, for non-financial assets and liabilities measured at fair value on a non-recurring basis. As it relates to 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, 2014, 2013, and 2012 consist of the following:
Fair Value Measurements on a Non-recurring Basis
		(Level 1)				(Level 2)				(Level 3)
Year ended December 31, 2014		(in thousands)
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 Hunter Holdings		—				—				347,291
Year ended December 31, 2013
Fair value of proved properties impaired		$	—			$	—			$	329,409
Fair value of long-lived assets of MHP		—				—				87,149
Year ended December 31, 2012
Fair value of proved properties impaired		$	—			$	—			$	372,450
Fair value of acquisitions		—				—				532,150
Proved Properties Impairment
The Company recorded impairment charges from continuing operations of $301.3 million, $50.0 million and $3.8 million during the years ended December 31, 2014, 2013 and 2012, respectively, as a result of writing down the carrying value of certain properties to fair value. In order to determine the amounts of the impairment charges, Magnum Hunter compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management's expectations of economically recoverable proved, probable, and possible reserves. If the net capitalized cost exceeds the undiscounted future net cash flows, Magnum Hunter impairs the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a discounted cash flow model utilizing a 10 percent discount rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with third party analyst 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
As of September 30, 2014, the Company has 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 3 - 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 Hunter Holdings
On December 18, 2014, the Company sold to MSI a common equity interest in Eureka Hunter Holdings comprising approximately 5.5% of the total common equity interests in Eureka Hunter 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 Hunter Holdings changing from a controlling financial interest in a consolidated subsidiary to an equity method investment in Eureka Hunter Holdings. As a result, the Company remeasured its retained interest in Eureka Hunter Holdings at fair value. See “Note 2 - Deconsolidation of Eureka Hunter 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 upon were as follows: (i) the pricing to be achieved upon a liquidating event or initial public offering, (ii) the cost of equity for Eureka Hunter Holdings, (iii) the timing and probability of an initial public offering as contemplated in the New LLC Agreement of Eureka Hunter Holdings at discreet points in time, and (iv) the expected volatility of the equity of Eureka Hunter Holdings.
Acquisitions
Magnum Hunter records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2012, Magnum Hunter acquired oil and natural gas properties with a fair value of $532.2 million. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with third party analyst 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. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

INVESTMENTS_AND_DERIVATIVES_No

INVESTMENTS AND DERIVATIVES (Notes)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
FINANCIAL INSTRUMENTS AND DERIVATIVES	NOTE 10 - INVESTMENTS AND DERIVATIVES
	Investment Holdings
	On February 17, 2012, the Company received 1,846,722 restricted common shares of GreenHunter and 88,000 shares of GreenHunter 10% Series C Preferred Stock as partial consideration for the sale by Triad Hunter, of its equity ownership interest in Hunter Disposal to GreenHunter. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”. The GreenHunter common stock investment is accounted for under the equity method and had no carrying value as of December 31, 2014 and $0.6 million at December 31, 2013. The GreenHunter common shares are publicly traded and have a fair value of $1.3 million and $2.1 million at December 31, 2014 and 2013, respectively, which is not reflected in the carrying value since the Company’s investment is accounted for using the equity method. The Series C Preferred Stock had a fair value of $1.3 million and $1.7 million at December 31, 2014 and 2013, respectively. The GreenHunter Series C Preferred Stock is publicly traded with a readily determinable fair value and is classified as available for sale.
	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 our 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 out of comprehensive income and into other income.
	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. These shares have a fair value of $2.5 million at December 31, 2014 and are classified as available for sale.
	On December 18, 2014, the Company lost its controlling financial interest in Eureka Hunter Holdings as a result of capital contributions made by MSI to Eureka Hunter Holdings and a subsequent sale by the Company of a portion of its equity interest in Eureka Hunter Holdings to MSI. The Company will continue to exercise significant influence through its retained equity interest of 48.6% and through representation on Eureka Hunter Holdings’ board of managers. As a result, the Company determined the equity method should be used to account for its retained interest. The Company recorded its retained interest in Eureka Hunter Holdings initially at a fair value of $347.3 million. After recording the Company’s equity in net loss of Eureka Hunter Holdings of $0.1 million for the period from December 18, 2014 to December 31, 2014, the carrying value of the Company’s equity interest in Eureka Hunter Holdings was $347.2 million.
	Below is a summary of changes in investments for the years ended December 31, 2014 and 2013:
		Available for Sale Securities (1)				Equity Method Investments
		(in thousands)
	Carrying value at December 31, 2011	$	497			$	—
	Additional cost basis from acquisition	—				4,043
	Transfers from cost method investments	1,770				—
	Loss from equity method investment, including impairment of carrying value	—				(1,971		)
	Change in fair value recognized in other comprehensive loss	(309		)		—
	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				—
	Equity in net loss recognized in other income (expense)	—				—
	Fair value of retained interest in Eureka Hunter 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 as of December 31, 2014	$	3,864			$	347,191
	(1) Available for sale securities above includes $147,000 that has been classified as held for sale associated with MHP
	as of December 31, 2013.
	The Company's investments have been presented in the consolidated balance sheet as of December 31, 2014 and December 31, 2013 as follows:
		31-Dec-14
		(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
		31-Dec-13
		(in thousands)
		Available for Sale Securities				Equity Method Investments			Total
	Investments - Current	$	1,672			$	590		$	2,262
	Investments - Non-current	—				350			350
	Investments - Held for Sale	147				—			147
	Carrying value as of December 31, 2013	$	1,819			$	940		$	2,759
	The cost for equity securities and their respective fair values as of December 31, 2014 and 2013 are as follows:
		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
		December 31, 2013
		Cost				Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
		(in thousands)
	Securities available for sale, carried at fair value:
	Equity securities	$	428			$	—		$	(281	)	$	147
	Equity securities - related party (see “Note 17 - Related Party Transactions”)	2,200				—			(528		)	1,672
	Total Securities available for sale	$	2,628			$	—		$	(809	)	$	1,819
	Commodity and Financial Derivative Instruments
	The Company periodically enters 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 commodity derivatives as hedges.
	In a commodities swap agreement, the Company trades the fluctuating market prices of oil or natural gas at specific delivery points over a specified period, for fixed prices. As a producer of oil and natural gas, the Company holds these commodity derivatives to protect the operating revenues and cash flows related to a portion of its future natural gas and crude oil sales from the risk of significant declines in commodity prices, which 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 also enters 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.
The Company's failure to service any of its debt or to comply with any of its debt covenants could result in a default under the related debt agreement, and under any commodity derivative contract under which such debt default is a cross-default, which could result in the early termination of the commodity derivative contract (and an early termination payment obligation) and/or otherwise materially adversely affect its business, financial condition and results of operations.
The table below is a summary of the Company's commodity derivatives as of December 31, 2014:
				Weighted Avg
Natural Gas	Period	MMBtu/d		Price per MMBtu
Swaps	Jan 2015 - Dec 2015	40,000		$4.09
				Weighted Avg
Crude Oil	Period	Bbl/d		Price per Bbl
Collars (1)	Jan 2015 - Dec 2015	259		$85.00 - $91.25
Ceilings sold (call)	Jan 2015 - Dec 2015	1,570		$120.00
Floors sold (put)	Jan 2015 - Dec 2015	259		$70.00
________________________________
(1) A collar is a sold call and a purchased put. Some collars are “costless” collars with the premiums netting to approximately zero.
As of December 31, 2014, Bank of America, Bank of Montreal, Citibank, N.A., and the Royal Bank of Canada are the only counterparties to the Company's commodity derivatives positions. All but one of these counterparties were participants in the MHR Senior Revolving Credit Facility.  Although borrowings under the MHR Senior Revolving Credit Facility are used as collateral for the Company’s commodity derivatives with those counterparties participating in the MHR Senior Revolving Credit Facility, the Company had no outstanding borrowings under that credit facility as of December 31, 2014. Additionally, certain counterparties to the Company's commodity derivatives positions are no longer participants in the Company's credit facilities following the execution of new credit agreements on October 22, 2014.  As a result, the Company is exposed to credit losses in the event of nonperformance by the counterparties where the Company’s open commodity derivative contracts are in a gain position.  The Company does not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. See “Note 11 - Long-Term Debt”.
At December 31, 2013, the Company had preferred stock derivative liabilities resulting from certain conversion features, redemption options, and other features of its Series A Convertible Preferred Units of Eureka Hunter Holdings. See “Note 9 - Fair Value of Financial Instruments” and “Note 13 - Shareholders' Equity”. During October 2014, all issued and outstanding Eureka Hunter Holdings Series A Preferred Units were converted to a new class of preferred equity of Eureka Hunter Holdings. See “Note 14 - Redeemable Preferred Stock”. As a result of the conversion, the preferred stock derivative liability was extinguished.
At December 31, 2014 and 2013, the Company has 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. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
The following table summarizes the fair value of the Company's derivative contracts as of the dates indicated:
	Derivatives not designated as hedging instruments
	Derivative Assets							Derivative Liabilities
	December 31,							December 31,
	2014				2013			2014			2013
Commodity	(in thousands)
Derivative assets	$	16,511			$	529		$	—		$	—
Derivatives assets, long term	—				25			—			—
Derivative liabilities	—				—			—			(1,903		)
Derivative liabilities, long term	—				—			—			(376		)
Total commodity	$	16,511			$	554		$	—		$	(2,279	)
Financial
Derivative assets	$	75			$	79		$	—		$	—
Derivative liabilities, long term	—				—			—			(75,934		)
Total financial	$	75			$	79		$	—		$	(75,934	)
Total derivatives	$	16,586			$	633		$	—		$	(78,213	)
Certain of the Company's derivative instruments are subject to enforceable master netting arrangements that provide for the net settlement of all derivative contracts between the Company and a counterparty in the event of default or upon the occurrence of certain termination events. The tables below summarize the Company's commodity derivatives and the effect of master netting arrangements on the presentation in the Company's consolidated balance sheets as of:
	December 31, 2014
	Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset on the Consolidated Balance Sheet			Net Amount
	(in thousands)
Current assets:  Fair value of derivative contracts	$	18,146			$	(1,635	)	$	16,511
Long-term assets:  Fair value of derivative contracts	—				—			—
Current liabilities:  Fair value of derivative contracts	(1,635		)		1,635			—
Long-term liabilities:  Fair value of derivative contracts	—				—			—
Total fair value of derivative contracts	$	16,511			$	—		$	16,511
	December 31, 2013
	Gross Amounts of Assets and Liabilities				Gross Amounts Offset on the Consolidated Balance Sheet			Net Amount
	(in thousands)
Current assets:  Fair value of derivative contracts	$	4,034			$	(3,505	)	$	529
Long-term assets:  Fair value of derivative contracts	516				(491		)	25
Current liabilities:  Fair value of derivative contracts	(5,408		)		3,505			(1,903		)
Long-term liabilities:  Fair value of derivative contracts	(867		)		491			(376		)
Total fair value of derivative contracts	$	(1,725	)		$	—		$	(1,725	)
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, 2014, 2013 and 2012:
	For the Year Ended December 31,
	2014				2013			2012
	(in thousands)
Gain (loss) on settled transactions	$	1,306			$	(8,216	)	$	11,294
Gain (loss) on open contracts	18,232				(17,058		)	10,945
Loss on extinguished embedded derivative	(91,792		)		—			—
Total gain (loss), net	$	(72,254	)		$	(25,274	)	$	22,239

LONGTERM_DEBT_Notes

LONG-TERM DEBT (Notes)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
LONG-TERM DEBT	NOTE 11 - LONG-TERM DEBT
	Notes payable at December 31, 2014 and 2013 consisted of the following:
		As of December 31,
		2014			2013
		(in thousands)
	Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.6 million and $2.8 million at December 31, 2014 and 2013, respectively	$	597,355		$	597,230
	Various equipment and real estate notes payable with maturity dates February 2015 - November 2017, interest rates of 4.25% - 7.94% (1)	22,238			18,615
	Eureka Hunter Pipeline Credit Agreement due March 28, 2018, interest rate of 3.66% (2)	—			—
	Eureka Hunter Pipeline second lien term loan due August 16, 2018, interest rate of 12.5%	—			50,000
	MHR Senior Revolving Credit Facility due April 13, 2018, interest rate of 2.92% at December 31, 2014	—			218,000
	MHR 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	329,140			—
		$	948,733		$	883,845
	Less: current portion	(10,770		)	(3,967		)
	Total long-term debt obligations, net of current portion	$	937,963		$	879,878
	_________________
	(1) Balance as of December 31, 2013 includes notes classified as liabilities associated with assets held for sale of which $0.2 million is current and $3.8 million is long term.
	(2)	As a result of the deconsolidation of Eureka Hunter Holdings, this loan or revolver was derecognized with Eureka Hunter Holdings’ other liabilities. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”
	The following table presents the approximate annual maturities of debt, gross of unamortized discount:
		(in thousands)
	2015	$	10,770
	2016	12,129
	2017	5,948
	2018	3,959
	2019	325,757
	Thereafter	602,825
		$	961,388
	Senior Notes
	On May 16, 2012, the Company completed the issuance of $450.0 million aggregate principal amount of its 9.75% Unregistered Senior Notes which mature on May 15, 2020 for total proceeds of $431.2 million net of issuing costs of $12.8 million, resulting in a discount of $6.0 million.
	On December 18, 2012, the Company completed the issuance of an additional $150.0 million aggregate principal amount of its 9.75% Unregistered Senior Notes for total proceeds of $149.9 million net of issuing costs of $3.1 million, resulting in a premium of $3.0 million.
	On November 8, 2013, the Company completed an exchange offer pursuant to which we exchanged $600 million of Senior Notes registered under the Securities Act for all of the Unregistered Notes. We refer to the exchanged Senior Notes as the Exchange Notes or our Senior Notes. The Exchange Notes have substantially identical terms to our former Unregistered Senior Notes except the Exchange Notes are generally freely transferable under the Securities Act.
	The Senior Notes are unsecured and are guaranteed, jointly and severally, on a senior unsecured basis by certain of the Company’s domestic subsidiaries. The indenture governing the Senior Notes permits a guarantor of the Senior Notes to be released from its guarantee under certain circumstances, including in connection with a sale or other disposition of all or substantially all of the assets of the guarantor, a sale or other disposition of the capital stock of the guarantor to a third party, or upon the liquidation or dissolution of the guarantor.
	Interest on the Senior Notes is paid semi-annually in arrears on May 15 and November 15 of each year. The Company paid penalty interest totaling $1.1 million during 2013 due to its untimely filing of a Registration Statement on Form S-4 to consummate an exchange offer.
	The Company used the net proceeds of the Senior Notes, together with other sources of liquidity, (i) to finance a portion of the $312.0 million acquisition of oil properties in the Williston Basin from Baytex Energy USA, which closed on May 22, 2012, (ii) to pay off all amounts outstanding under the Company’s second lien term loan, (iii) to repay outstanding debt under the Company’s senior revolving credit facility, (iv) for capital expenditures and (v) general corporate purposes.
	The Senior Notes were issued pursuant to an indenture entered into on May 16, 2012 as supplemented, among the Company, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as the trustee, and Citibank, N.A., as the paying agent, registrar and authenticating agent.  The terms of the Senior Notes are governed by the indenture, which contains affirmative and restrictive covenants that, among other things, limit the Company’s and the guarantors’ ability to incur or guarantee additional indebtedness or issue certain preferred stock; pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness or make certain other restricted payments; transfer or sell assets; make loans and other investments; create or permit to exist certain liens; enter into agreements that restrict dividends or other payments from restricted subsidiaries to the Company; consolidate, merge or transfer all or substantially all of their assets; engage in transactions with affiliates; and create unrestricted subsidiaries.
	The indenture also contains events of default.  Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the Senior Notes.  Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.
	At December 31, 2014, the Company was in compliance with all of its requirements under the indenture related to the Senior Notes.
	The Senior Notes are redeemable by the Company at any time on or after May 15, 2016, at the redemption price of 104.875%, after May 15, 2017, at the redemption price of 102.438%, and after May 15, 2018, at the redemption price of 100.00%. The Senior Notes are redeemable by the Company prior to May 15, 2016 at the redemption price equal to 100.00% of the principal amount of the notes redeemed, plus a “make-whole” premium equal to the greater of:
	i.	1.0% of the principal amount of the note; and
	ii.	The excess of:
	(a)	The present value at such redemption date of (i) the redemption price of the note at May 15, 2016 plus (ii) all required interest payments due on the note through May 15, 2016 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points discounted to such redemption date on a semi-annual basis, over
	(b)	The principal amount of the note.
	The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before May 15, 2015 with net proceeds that the Company raises in certain equity offerings at a redemption price of 109.750%, so long as at least 65% of the aggregate principal amount of the Senior Notes issued under the indenture (excluding Senior Notes held by the Company) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.  If the Company experiences certain change of control events, each holder of Senior Notes may require the Company to repurchase all or a portion of the Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued and unpaid interest up to, but not including the date of repurchase.
	MHR Senior Revolving Credit Facility and Second Lien Term Loan
	Revolving Credit Facility
	On December 13, 2013, the Company entered into a Third Amended and Restated Credit Agreement (“Credit Agreement”) by and among the Company, Bank of Montreal, as Administrative Agent, the lenders a party thereto and the agents a party thereto. The Credit Agreement amended and restated that certain Second Amended and Restated Credit Agreement, dated as of April 13, 2011, by and among such parties, as amended (“Prior Credit Agreement”).
	On May 6, 2014, the Company and the other parties to the Credit Agreement entered into the First Amendment to Third Amended and Restated Credit Agreement (the “Amendment”). The Amendment increased the borrowing base from $232.5 million to $325.0 million in connection with the regular semi-annual redetermination of the Company's borrowing base derived from the Company's proved crude oil and natural gas reserves. The borrowing base could have been increased or decreased in connection with such redeterminations up to a maximum commitment level of $750.0 million. The Amendment provided that such increased borrowing base shall be reduced (i) by the lesser of $25.0 million or 50% of the net proceeds from issuances by the Company of common equity on or before July 1, 2014 (other than common equity issued pursuant to any stock incentive or stock option plan or any other compensatory arrangements); (ii) by certain specified reductions in connection with certain proposed asset dispositions; (iii) on July 1, 2014 by $25.0 million less any prior adjustment of the borrowing base due to an equity issuance as contemplated by clause (i); and (iv) by $0.25 for each $1.00 of any additional Senior Notes issued by the Company. The Amendment further provided that from May 6, 2014 through July 1, 2014 the Applicable Margin (as defined in the Credit Agreement) component of the interest charged on revolving borrowings under the Credit Agreement was 2.75% for alternate base rate (“ABR”) Loans (as defined in the Credit Agreement) and 3.75% for Eurodollar Loans (as defined in the Credit Agreement). From and after July 1, 2014 through the date of the Company’s delivery of a certificate for the quarter ended June 30, 2014, with respect to, among other things, the Company’s compliance with the covenants in the Credit Agreement (the “Compliance Certificate”), the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement ranged from 1.50% to 2.25% for ABR Loans and from 2.50% to 3.25% for Eurodollar Loans. From and after the Company’s delivery of the Compliance Certificate, the Applicable Margin component of interest charged on revolving borrowings under the Credit Agreement ranged from 1.00% to 1.75% for ABR Loans and from 2.00% to 2.75% for Eurodollar Loans.
	In addition, the Amendment modified certain of the Credit Agreement’s financial covenants, including:
	i.	permitting the Company to take into account the borrowing base increase as though it occurred on March 31, 2014 for purposes of maintaining a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;
	ii.	providing for a ratio of EBITDAX to Interest Expense of not less than (a) 2.0 to 1.0 for the fiscal quarter ended March 31, 2014, (b) 2.25 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, and (c) 2.50 to 1.0 for the fiscal quarter ended December 31, 2014 and for each fiscal quarter ending thereafter; and
	iii.	beginning with the fiscal quarter ended June 30, 2014, providing for a ratio of total Debt to EBITDAX of not more than (a) 4.75 to 1.0 for the fiscal quarters ending June 30, 2014 and September 30, 2014, (b) 4.50 to 1.0 for the fiscal quarter ended December 31, 2014, and (c) 4.25 to 1.0 for the fiscal quarter ending March 31, 2015 and for each fiscal quarter ending thereafter.
	The Amendment also (i) amended the definition of EBITDAX and provided that certain acquisitions and dispositions be given pro forma effect in the calculation of EBITDAX; (ii) increased the letter of credit commitment from $10.0 million to $50.0 million and provided that outstanding letter of credit exposure not be included in certain determinations of Debt; (iii) required the total value of the Company’s oil and gas properties included in the reserve reports for the borrowing base determinations in which the lenders under the Credit Agreement have perfected liens be increased from 80% to 90%; and (iv) modified certain covenants in the Credit Agreement with respect to permitted investments by the Company to increase flexibility.
	On October 22, 2014, the Company entered into the Fourth Amended and Restated Credit Agreement by and among the Company, as borrower, Bank of Montreal, as administrative agent, the lenders a party thereto and the agents a party thereto as amended by that certain First Amendment to the Credit Agreement and Waiver, dated February 24, 2015 (as amended, the “New Credit Agreement”). The New Credit Agreement amended and restated the Credit Agreement, dated as of December 13, 2013, by and among those parties, as amended.
	The New Credit Agreement provides for an asset-based, senior secured revolving credit facility maturing October 22, 2018 (the “Revolving Facility”) with an initial borrowing base of $50 million. The Revolving Facility is governed by a semi-annual borrowing base redetermination derived from the Company's proved crude oil and natural gas reserves, and based on such redeterminations, the borrowing base may be decreased or increased up to a maximum commitment level of $250 million. As discussed below, however, provisions of the Second Lien Credit Agreement (“Second Lien Term Loan Agreement”) limit the amount of indebtedness that the Company may incur under the New Credit Agreement.
	The terms of the New Credit Agreement provide that the Revolving Facility may be used for loans, and subject to a $50 million sublimit, letters of credit. The New Credit Agreement provides for a commitment fee of 0.5% of the unused portion of the borrowing base under the Revolving Facility.
	Borrowings under the Revolving Facility will, at the Company’s election, bear 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 is payable in arrears on the last day of each March, June, September and December and accrued interest on each adjusted LIBO Rate loan is payable in arrears on the last day of the Interest Period (as defined in the New Credit Agreement) applicable to the borrowing of which such adjusted LIBO Rate loan is a part and, in the case of an adjusted LIBO Rate borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.
	The New Credit Agreement contains negative covenants 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) make certain payments, (iv) change the nature of its business, (v) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions, (vi) make investments, loans or advances, (vii) pay cash dividends, unless certain conditions are met, and with respect to the payment of dividends on preferred stock, subject to (a) no Event of Default (as defined in the New Credit Agreement) existing, (b) after giving effect to any such preferred stock dividend payment, the Company maintaining availability under the borrowing base in an amount greater than the greater of (x) 2.50% percent of the borrowing base then in effect or (y) $5,000,000 and (c) a “basket” of $45,000,000 per year, (viii) enter into transactions with affiliates, and (ix) enter into hedging transactions.
	In addition, the New Credit Agreement requires the Company to satisfy certain financial covenants, including maintaining:
	i.	commencing with the fiscal quarter ending March 31, 2015, a current ratio (as defined in the New Credit Agreement) of not less than (a) 0.75 to 1.0 for the fiscal quarter ending March 31, 2015 and (b) 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and for each fiscal quarter ending thereafter;
	ii.	a leverage ratio (secured net debt to EBITDAX (as defined in the New Credit Agreement) with, beginning with the fiscal quarter ending March 31, 2016, a limitation on netting of up to $100,000,000 of unencumbered cash) of not more than (a) 2.5 to 1.0 as of the last day of the fiscal quarter ended December 31, 2014, (b) 2.50 to 1.00 as of the last day of the fiscal quarters ending March 31, June 30, September 30, and December 31, 2015 and (c) 2.0 to 1.0 as of the last day of each fiscal quarter ending March 31, 2016 and each fiscal quarter ending thereafter; and
	iii.	the proved reserves based asset coverage ratios contained in the Second Lien Term Loan Agreement described below.
	At December 31, 2014, the Company would not have been compliance with its current ratio financial covenant under the New Credit Agreement, which required the Company maintain a current ratio of not less than 1.0 to 1.0 as of that date. The Company has obtained a waiver from its lenders, effective December 31, 2014, of the current ratio covenant requirement for the December 31, 2014 compliance period and entered into a First Amendment to Credit Agreement and Limited Waiver, dated February 24, 2015 (the “First Amendment”), that, among other things, lowers the current ratio requirement to 0.75 to 1.0 for the fiscal quarter ending March 31, 2015. The current ratio requirement increases to 1.0 to 1.0 for the fiscal quarter ending June 30, 2015 and each fiscal quarter ending thereafter. The First Amendment also modified the leverage ratio requirement to remain at not more than 2.5x beginning with the December 31, 2014 compliance period through the December 31, 2015 compliance period. The Company believes that these waivers and modifications to its financial covenant ratios together with the successful execution of certain contemplated asset sales and other transactions will enable it to maintain compliance with such ratios for 2015.
	Pursuant to the First Amendment, until such time as the Company can demonstrate a (i) current ratio of 1.0 to 1.0 as of the last day of a fiscal quarter or, if there is a proposed Liquidity Event (described below) or other arms-length liquidity event with a non-affiliate or unrestricted subsidiary, demonstrate a current ratio of 1.0 to 1.0 on a pro forma basis as of the last day of a calendar month assuming that the Liquidity Event (or other liquidity event) had occurred during such calendar month and (ii) in the case of a decrease of the Rates for ABR Loans and Eurodollar Loans, pro forma compliance with the other applicable financial covenants as of the last day of the fiscal quarter most recently ended, (such period, the “Adjusted Period”), then:
	i.	neither the Company nor any of its restricted subsidiaries may make additional investments in excess of $2 million in the aggregate in oil and gas properties (other than acreage swaps and associated assets) and other applicable assets;
ii.	neither the Company nor any of its restricted subsidiaries may make additional capital contributions to or other investments in unrestricted subsidiaries in amounts in excess of $2 million in the aggregate; and
iii.	the Company cannot make any additional capital contributions to or other investments in Eureka Hunter Holdings.
For purposes of the First Amendment, a “Liquidity Event” means any event or events resulting in (i) an increase in Liquidity (as defined in the New Credit Agreement) of at least $36,000,000 as a result of an arm’s length transaction with a person or entity that is not an affiliate of the Company or (ii) the receipt by the Company or any restricted subsidiary of aggregate net cash proceeds of at least $73,000,000 as a result of one or more arm’s length transactions with either (a) persons or entities who are not affiliates of the Company or (b) the Company’s unrestricted subsidiaries.
In addition, effective March 31, 2015, if a Liquidity Event (described in clause (i) of the preceding paragraph) has not occurred prior to such date, or April 30, 2015 if a proposed Liquidity Event described in clause (ii) of the preceding paragraph for which a pro forma current ratio calculation is used has not occurred prior to such date, the rates for ABR Loans and Eurodollar Loans shall automatically increase by 1.00% and the commitment fee shall automatically increase by 0.25% and such elevated rates shall continue until the day immediately preceding the date on which the Adjusted Period ends.
The Company posted letters of credit for $39.3 million million using availability under the Company’s Senior Revolving Credit Facility. The borrowing capacity under the Senior Revolving Credit Facility was reduced by $39.3 million. No amounts are outstanding under the Senior Revolving Credit Facility as of December 31, 2014.
The obligations of the Company under the New Credit Agreement may be accelerated upon the occurrence of an Event of Default. Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy of representations and warranties, bankruptcy or related defaults, defaults relating to judgments and the occurrence of a Change of Control (as defined in the New Credit Agreement) and any “Event of Default” under the Second Lien Term Loan Agreement, subject to certain cure periods.
Subject to certain exceptions, the Revolving Facility is 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) is required to be pledged as security for the New Credit Agreement. In connection with the New Credit Agreement, the Company and its restricted subsidiaries also entered into customary ancillary agreements and arrangements, which among other things, provide that the Revolving Facility is unconditionally guaranteed by such restricted subsidiaries. The Company’s restricted subsidiaries under the New Credit Agreement and the Second Lien Term Loan do not include the Company’s investee, which conducts midstream operations, Eureka Hunter Holdings, and its subsidiaries, Eureka Hunter Pipeline, and TransTex Hunter.
Second Lien Term Loan
On October 22, 2014, 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 (“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 its Credit Agreement, to pay transaction expenses related to the New Credit Agreement 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 will, at the Company’s election, bear 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 substantially similar to those in the New Credit Agreement 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 New Credit Agreement. The Second Lien Term Loan Agreement limits the amount of indebtedness that the Company may incur under the New Credit Agreement 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.
At December 31, 2014, the Company was in compliance with all of its covenants applicable for the period, contained in the Second Lien Term Loan Agreement.
The obligations of the Company under the Second Lien Term Loan Agreement may be accelerated upon the occurrence of an Event of Default (as defined in the Second Lien Term Loan Agreement). Events of Default are substantially similar to Events of Default under the New Credit Agreement (except that a breach of a financial covenant under the New Credit Agreement will not constitute an Event of Default under the Second Lien Term Loan Agreement until acceleration) and include customary events for these types of financings.
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.
The Company incurred direct financing costs associated with entering into the Amendment and the New Credit Agreement and the Second Lien Term Loan Agreement in the amount of $12.0 million, which were deferred and are being amortized over the remaining term of the agreements.
Eureka Hunter Pipeline Credit Facilities
Upon executing the new Eureka Hunter Pipeline Credit Agreement on March 28, 2014, Eureka Hunter Pipeline terminated its revolving credit agreement with SunTrust Bank and the term loan agreement with Pennant Park (“Original Eureka Hunter Credit Facilities”). Eureka Hunter Pipeline used proceeds from the Eureka Hunter Pipeline Credit Agreement to pay in full all outstanding obligations related to the termination of the Original Eureka Hunter Credit Facilities, which included the principal outstanding amount of $50.0 million, a prepayment penalty of $2.2 million, and accrued, unpaid interest of $1.5 million.
Eureka Hunter Pipeline Credit Agreement
On March 28, 2014, Eureka Hunter Pipeline entered into the Eureka Hunter Pipeline Credit Agreement, by and among Eureka Hunter Pipeline, as borrower, ABN AMRO Capital USA, LLC, as a lender and as administrative agent, and the other lenders a party thereto.
The credit agreement, which has a maturity date of March 28, 2018, provides for a revolving credit facility in an aggregate principal amount of up to $117.0 million (with the potential to increase the aggregate commitment under the credit agreement to an aggregate principal amount of up to $150.0 million, subject to the consent of the lender parties and the satisfaction of certain conditions), secured by a first lien on substantially all of the assets of Eureka Hunter Pipeline and its subsidiaries, which include TransTex Hunter, as well as by Eureka Hunter Pipeline’s pledge of the equity in its subsidiaries. The subsidiaries of Eureka Hunter Pipeline also guarantee Eureka Hunter Pipeline’s obligations under the credit agreement. The credit agreement is non-recourse to Magnum Hunter. The Company incurred deferred financing costs directly associated with entering into the Eureka Hunter Pipeline Credit Agreement in the amount of $1.2 million which are being amortized straight-line over the term of the revolving credit facility. The straight-line method of amortization results in substantially the same periodic amortization as the effective interest method.
On November 19, 2014, Eureka Hunter Pipeline entered into an amendment to the Eureka Hunter Pipeline Credit Agreement. Pursuant to the amendment, the number of lenders under the Eureka Hunter Pipeline Credit Agreement increased from five to thirteen and the aggregate loan commitments available to Eureka Hunter Pipeline under the Eureka Hunter Pipeline Credit Agreement correspondingly increased from an aggregate principal amount of $117.0 million to $225.0 million. In addition, the amendment lowered the commitment fee and the interest rates payable under the Eureka Hunter Pipeline Credit Agreement.
On December 18, 2014, the Company’s investment in Eureka Hunter Holdings, the parent of Eureka Hunter Pipeline, changed from a controlling financial interest in a consolidated subsidiary to an equity method investment in Eureka Hunter Holdings. As a result, the outstanding balance under the Eureka Hunter Pipeline Credit Agreement has been deconsolidated as of December 31, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
Equipment Note Payable
On January 23, 2014, the Company’s wholly owned subsidiary, Alpha Hunter Drilling, LLC, entered into a master loan and security agreement with CIT Finance LLC to borrow $5.6 million at an interest rate of 7.94% over a term of forty-eight months. The note is collateralized by field equipment, and the Company is a guarantor on the note.
Building Note Payable
Effective September 30, 2014, MHP refinanced its $3.8 million term loan with Traditional Bank, Inc. that was due to mature in early 2015. The new loan is collateralized by an office building owned by MHP and carried an initial principal balance of $3.8 million at an interest rate of 4.875% with a maturity date of September 30, 2024.
Interest Expense
The following table sets forth interest expense for the years ended December 31, 2014, 2013 and 2012:
	Year Ended December 31,
	2014			2013			2012
	(in thousands)
Interest expense incurred on debt, net of amounts capitalized	$	76,784		$	67,803		$	44,447
Amortization and write-off of deferred financing costs	9,679			4,818			7,399
Total interest expense	$	86,463		$	72,621		$	51,846
The Company capitalizes interest on expenditures for significant construction projects that last more than six months while activities are in progress to bring the assets to their intended use. Interest of $2.0 million was capitalized as part of the construction of Eureka Hunter Holdings’ gas gathering system during the year ended 2014, prior to deconsolidation on December 18, 2014, and $2.6 million and $4.4 million was capitalized during the years ended December 31, 2013 and 2012 respectively.
For the year ended December 31, 2014, interest expense incurred on debt includes a $2.2 million prepayment penalty incurred by Eureka Hunter Pipeline as a result of its early termination of the Original Eureka Hunter Credit Facilities on March 28, 2014, which penalty represents an additional cost of borrowing for a period shorter than contractual maturity. In addition, interest expense includes the write-off of $2.7 million in unamortized deferred financing costs related to those terminated agreements, which costs were expensed at the time of early extinguishment, $1.7 million in unamortized deferred financing costs related to the May 6, 2014, Amendment of the MHR Senior Revolving Credit Facility and the write-off of $1.4 million in unamortized deferred financing costs related to the New Credit Agreement.

SHAREBASED_COMPENSATION_Notes

SHARE-BASED COMPENSATION (Notes)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
SHARE-BASED COMPENSATION	NOTE 12 - SHARE-BASED COMPENSATION
	Employees, officers, directors and other persons who contribute to the success of Magnum Hunter are eligible for grants of unrestricted common stock, restricted common stock, common stock options, and stock appreciation rights under the Company's Amended and Restated Stock Incentive Plan. At December 31, 2014, 27,500,000 shares of the Company's common stock are authorized to be issued under the plan, and 11,035,482 shares have been issued as of December 31, 2014, of which 2,317,013 shares remained unvested at December 31, 2014. Additionally, 13,194,956 options to purchase shares and stock appreciation rights were outstanding as of December 31, 2014, of which 3,973,183 remained unvested at December 31, 2014.
	The Company recognized share-based compensation expense of $12.5 million, $13.6 million, and $15.7 million for the years ended December 31, 2014, 2013, and 2012 respectively.
	A summary of stock option and stock appreciation rights activity for the years ended December 31, 2014, 2013, and 2012 is presented below:
		2014					2013				2012
				Weighted-Average Exercise Price					Weighted-Average Exercise Price				Weighted-Average Exercise Price
		Shares					Shares				Shares
	Outstanding at beginning of the year	16,891,419		$	5.69		14,846,994		$	6.01	12,566,199		$	5.64
	Granted	—		$	—		4,937,575		$	4.11	4,978,750		$	6
	Exercised	(2,375,273	)	$	4.09		(1,466,025	)	$	3.66	(1,304,050	)	$	1.54
	Forfeited or expired	(1,321,190	)	$	6.27		(1,427,125	)	$	5.51	(1,393,905	)	$	7.14
	Outstanding at end of the year	13,194,956		$	5.91		16,891,419		$	5.69	14,846,994		$	6.01
	Exercisable at end of the year	9,140,323		$	6.22		9,983,743		$	5.96	8,683,622		$	5.97
	A summary of the Company’s non-vested common stock options and stock appreciation rights for the years ended December 31, 2014, 2013, and 2012 is presented below:
	Non-vested Options	2014		2013		2012
	Non-vested at beginning of the year	6,907,476		6,163,372		5,650,782
	Granted	—		4,937,575		4,978,750
	Vested	(1,915,526	)	(3,133,700	)	(3,405,434	)
	Forfeited	(1,018,767	)	(1,059,771	)	(1,060,726	)
	Non-vested at end of the year	3,973,183		6,907,476		6,163,372
	Total unrecognized compensation cost related to the non-vested common stock options and stock appreciation rights was $3.2 million, $14.1 million, and $12.6 million as of December 31, 2014, 2013, and 2012, respectively. The unrecognized compensation cost at December 31, 2014 is expected to be recognized over a weighted-average period of 0.95 years. At December 31, 2014, the aggregate intrinsic value for the outstanding options and stock appreciation rights was $6.4 million; and the weighted average remaining contract life of the outstanding options was 5.57 years.
	No options or stock appreciation rights were granted during the year ended December 31, 2014. The assumptions used in the fair value method calculations for the years ended 2013 and 2012 are disclosed in the following table:
			Year Ended December 31,
			2013	2012
	Weighted average fair value per option granted during the period (1)		$2.52	$3.72
	Assumptions (2) :
	Weighted average stock price volatility (3)		80.61%	82.64%
	Weighted average risk free rate of return		0.78%	0.77%
	Weighted average estimated forfeiture rate (4)		2.45%	—%
	Weighted average expected term		4.65 years	4.51 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.
	(4)	For the year 2012, the Company estimated forfeitures to be zero based on the majority of options being granted to executive officers who are less likely to forfeit shares.
	During the years ended December 31, 2014 and 2013, the Company granted 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.
	A summary of the Company’s non-vested common shares granted under the Stock Incentive Plan as of December 31, 2014, 2013, and 2012 is presented below:
		2014					2013				2012
				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	27,500		$	7.24		65,025		$	6.09	155,049		$	4.43
	Granted	3,239,796		$	5.66		210,494		$	4.66	69,791		$	4.29
	Forfeited	(170,000	)	$	7.26		—		$	—	—		$	—
	Vested	(780,283	)	$	4.48		(248,019	)	$	4.75	(159,815	)	$	4.46
	Non-vested at end of the year	2,317,013		$	5.97		27,500		$	7.24	65,025		$	6.09
	Total unrecognized compensation cost related to the above non-vested shares amounted to $9.7 million, $0.2 million, and $0.4 million as of December 31, 2014, 2013, and 2012, respectively. The unrecognized compensation cost at December 31, 2014 is expected to be recognized over a weighted-average period of 1.96 years.
	Eureka Hunter Holdings, LLC Management Incentive Compensation Plan
	On May 12, 2014, the Board of Directors of Eureka Hunter Holdings approved the Eureka Hunter Holdings, LLC Management Incentive Compensation Plan (the “Eureka Hunter Holdings Plan”) to provide long-term incentive compensation to attract and retain officers and employees of Eureka Hunter Holdings and its affiliates and allow such individuals to participate in the economic success of Eureka Hunter Holdings and its affiliates.
	The Eureka Hunter Holdings Plan consists of (i) 2,336,905 Class B Common Units representing membership interests in Eureka Hunter Holdings (“Class B Common Units”), and (ii) 2,336,905 Incentive Plan Units issuable pursuant to a management incentive compensation plan, which represent the right to receive a dollar value up to the baseline value of a corresponding Class B Common Unit (“Incentive Plan Units”). The Eureka Hunter Holdings Plan is administered by the board of managers of Eureka Hunter Holdings, and, as administrator of the Eureka Hunter Holdings Plan, the board may from time to time make awards under the Eureka Hunter Holdings Plan to selected officers and employees of Eureka Hunter Holdings or its affiliates (“Award Recipients”).
	Upon approval of the plan on May 12, 2014, the board of managers of Eureka Hunter Holdings granted 894,102 Class B Common Units and 894,102 Incentive Plan Units to key employees of Eureka Hunter Holdings and its subsidiaries. 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 of Eureka Hunter Holdings and its subsidiaries. The Class B Common Units and Incentive Plan Units are accounted for in accordance with ASC 718, Compensation - Stock Compensation. In accordance with ASC 718, compensation cost is accrued when the performance condition (i.e. 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 Hunter Holdings and concluded that as of December 18, 2014, a liquidity event, as defined, was not probable, and therefore, no compensation cost has been recognized.

SHAREHOLDERS_EQUITY_Notes

SHAREHOLDERS' EQUITY (Notes)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
SHAREHOLDERS' EQUITY	NOTE 13 - SHAREHOLDERS' EQUITY
	Common Stock
	During the years ended December 31, 2014, 2013, and 2012, the Company issued:
	i.	657,317, 182,994, and 108,397 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.	2,375,273, 1,466,025, and 1,438,275 shares, respectively, of the Company’s common stock upon the exercise of warrants and options for total proceeds of approximately $9.7 million, $5.4 million, and $2.3 million, respectively.
	On March 30, 2012, the Company issued 296,859 restricted shares of the Company’s common stock valued at approximately $1.9 million based on a price of $6.41 per share as partial consideration for the acquisition of the assets of Eagle Operating.
	On May 16, 2012, the Company issued 35,000,000 shares of the Company’s common stock in an underwritten public offering at a price of $4.50 per share for total proceeds of $157.5 million.  The net proceeds of the offering, after deducting underwriting discounts and commissions and offering expenses, were approximately $148.2 million.
	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.
	Magnum Hunter Resources Corporation 401(k) Employee Stock Ownership Plan
	During the years ended December 31, 2014, 2013, and 2012, the Company issued an aggregate of 249,531; 221,170; and 199,055 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, 2014, except for statutorily required “safe harbor” matching contributions. Shares issued to and held by the Plan are included in our EPS calculation.
	During the years ended December 31, 2014, 2013, and 2012, the Company recognized $1.6 million, $1.2 million and $0.9 million, respectively in compensation attributable to its KSOP. As of December 31, 2014 the KSOP held 585,239 shares of the Company’s common stock.
	On August 13, 2012, the Company rescinded the loan of 153,300 Magnum Hunter common shares to the Company's KSOP and the common shares were returned to the Company and held in treasury at cost of $3.94 per share. The loan was rescinded to correct a mutual mistake by the parties in connection with the Company’s original acquisition of the shares through open market purchases. The Company has agreed that 153,300 shares of the Company’s common stock will either be (i) offered for sale to the participants in the Plan at a price not to exceed the lesser of $3.94 per share (the basis of these treasury shares) or the fair market value of the shares on the date of the sale, or (ii) contributed to the Plan as one or more discretionary matching contributions.  Such sale or contribution shall be made at such time or times as determined by the trustee of the Plan, except to the extent that the Company elects prior to that time to contribute all or a part of such shares as a discretionary matching contribution.
	Exchangeable Common Stock
	On May 3, 2011, in connection with the acquisition of NuLoch Resources, Inc., 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 years ended December 31, 2013 and 2012, 505,835 and 3,188,036, respectively, of the exchangeable shares were exchanged for common shares of the Company. As of December 31, 2014 and 2013, there were no exchangeable shares outstanding.
	Common Stock Warrants
	On April 13, 2011, at the time of the NGAS acquisition, NGAS had 4,609,038 warrants outstanding which were converted, based on the exchange ratio of 0.0846, to 389,924 warrants exercisable for Magnum Hunter common stock. The warrants had a cash-out option, which remained available to the holder for 30 days from the date of the acquisition, based on the fair market value of the warrants at April 13, 2011. The Company paid cash of $1.0 million upon exercise of the cash-out option on the warrants exercisable for 251,536 shares of the Company’s common stock. The remaining warrants which were not exercised consisted of 97,780 warrants with an exercise price of $15.13 which expired on February 13, 2014 and 40,608 warrants with an exercise price of $19.04 which expired on November 17, 2014.
	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 became exercisable on August 5, 2014, the date that our registration statement was declared effective by the SEC with respect to the issuance of the common stock underlying the warrants. 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, 2012, 48 of the Company's $10.50 common stock warrants and 134,177 of the Company's $2.50 common stock warrants were exercised for total combined proceeds of approximately $328,000, and 15,330 of the Company's $10.50 common stock warrants were canceled upon the rescission of the 153,300 Magnum Hunter common shares loaned to the Company’s KSOP. During the year ended December 31, 2013, 13,237,889 of the Company's $10.50 common stock warrants expired.
	A summary of warrant activity for the years ended December 31, 2014, 2013, and 2012 is presented below:
		2014						2013				2012
				Weighted -						Weighted -				Weighted -
				Average						Average				Average
		Shares		Exercise Price				Shares		Exercise Price		Shares		Exercise Price
	Outstanding at beginning of year	17,169,010		$	8.56			13,376,277		$	10.56	13,525,832		$	10.48
	Granted	2,142,858		$	8.5			17,030,622		$	8.5	—		$	—
	Exercised, forfeited, or expired	(138,388	)	$	16.28			(13,237,889	)	$	10.5	(149,555	)	$	3.32
	Outstanding at end of year	19,173,480		$	8.5			17,169,010		$	8.56	13,376,277		$	10.56
	Exercisable at end of year	19,173,480		$	8.5			17,169,010		$	8.56	13,376,277		$	10.56
	At December 31, 2014, the warrants had no aggregate intrinsic value; and the weighted average remaining contract life was 1.29 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. The Series D Preferred Stock cannot be converted 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. Dividends accrue and are payable monthly on the Series D Preferred Stock at a fixed rate of 8.0% per annum of the $50.00 per share liquidation preference.
	During the year ended December 31, 2012, the Company issued an aggregate of 2,771,263 shares of its 8.0% Series D Preferred Stock for cumulative net proceeds of approximately $122.5 million, which included various offering expenses of approximately $3.1 million. The 2,771,263 shares of our 8.0% Series D Preferred Stock issued during the year ended December 31, 2012 included (i) 1,721,263 shares issued under an ATM sales agreement for net proceeds of approximately $77.9 million, which included approximately $1.5 million of offering and underwriting fees and (ii) 1,050,000 shares issued pursuant to an underwritten public offering on September 7, 2012 at a price of $44.00 per share for net proceeds of approximately $44.6 million, which included approximately $1.6 million of underwriting discounts, commissions and offering expenses.
	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.
	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.
	In November 2012, the Company issued 2,774,850 Depositary Shares to the shareholders of Virco as partial consideration for the Company’s purchase of 100% of the outstanding stock of Virco. The Company also issued 70,000 Depositary Shares into an escrow account which were returned and held in treasury at cost of $1.8 million upon an indemnification settlement in favor of the Company.
	Each Depositary Share is a 1/1000th 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.
	In December 2012, the Company sold in a public offering an aggregate of 1,000,000 Depositary Shares.  The Depositary Shares were sold to the public at a price of $23.50 per Depositary Share, and the net proceeds to the Company were $22.44 per Depositary Share after deducting underwriting commissions, but before deducting expenses related to the offering.
	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.
	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 Hunter Holdings, then a majority owned subsidiary, issued 622,641 Class A Common Units representing membership interests in Eureka Hunter 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 Hunter 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 Hunter Holdings in the Company’s consolidated balance sheet. As a result of the deconsolidation of Eureka Hunter Holdings, the Company derecognized the non-controlling interests attributed to Eureka Hunter Holdings as part of the gain on deconsolidation (see “Note 2 - Deconsolidation of Eureka Hunter Holdings”).
	Preferred Dividends Incurred
	A summary of dividends incurred by the Company for the years ended December 31, 2014, 2013, and 2012 is presented below:
		Year Ended December 31,
		2014				2013				2012
		(in thousands)
	Dividend on Eureka Hunter Holdings Series A Preferred Units	$	12,760			$	14,323			$	8,090
	Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	6,583				6,918				3,775
	Dividend on Series C Preferred Stock	10,248				10,248				10,248
	Dividend on Series D Preferred Stock	17,698				17,655				11,699
	Dividend on Series E Preferred Stock	7,418				7,561				894
	Total dividends on Preferred Stock	$	54,707			$	56,705			$	34,706
	Net Income or Loss per Share Data
	The Company has issued potentially dilutive instruments in the form of our restricted common stock granted and not yet issued, common stock warrants, common stock options granted to our employees and directors, and our 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 periods because to include them would be anti-dilutive due to the Company's loss from continuing operations during the periods.
	The following table summarizes the types of potentially dilutive securities outstanding as of December 31, 2014, 2013 and 2012:
		December 31,
		2014			2013			2012
		(in thousands of shares)
	Series E Preferred Stock	10,946			10,946			10,897
Warrants	19,173			17,169			13,376
Restricted shares granted, not yet issued	2,369			28			—
Common stock options	13,195			16,891			14,847
Total	45,683			45,034			39,120

REEDEMABLE_PREFERRED_STOCK_Not

REEDEMABLE PREFERRED STOCK (Notes)	12 Months Ended
	Dec. 31, 2014
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. The Series C Preferred Stock cannot be converted 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. Dividends accrue and are payable monthly on the Series C Preferred Stock at a fixed rate of 10.25% per annum of the $25.00 per share liquidation preference.
	Eureka Hunter Holdings Series A Preferred Units
	On March 21, 2012, Eureka Hunter Holdings entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Unit Purchase Agreement”) with Magnum Hunter and Ridgeline. Pursuant to this Unit Purchase Agreement, Ridgeline committed, subject to certain conditions, to purchase up to $200 million of Eureka Hunter Holdings Series A Preferred Units, of which $200 million were purchased through September 16, 2014.
	During the years ended December 31, 2014, 2013, and 2012, Eureka Hunter Holdings issued 610,000, 1,800,000, and 7,590,000 Eureka Hunter Holdings Series A Preferred Units, respectively, to Ridgeline for net proceeds of $12.0 million, $35.3 million, and $148.6 million, respectively, net of transaction costs. Eureka Hunter Holdings paid cumulative distributions quarterly on the Eureka Hunter 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 Hunter 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 Hunter Holdings Series A Preferred Units were convertible into Class A Common Units of Eureka Hunter Holdings upon demand by Ridgeline or by Eureka Hunter 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 Hunter Holdings was allowed to redeem all outstanding Eureka Hunter 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 Hunter Holdings Series A Preferred Units could force the redemption of all outstanding Eureka Hunter Holdings Series A Preferred Units any time after March 21, 2020. The Eureka Hunter 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 Hunter Holdings.
	During the years ended December 31, 2014, 2013, and 2012, the Company paid cash distributions of $10.2 million, $5.2 million, and $3.4 million, respectively. The Company accrued distributions not yet paid of $3.9 million and $3.0 million during the years ended December 31, 2013 and 2012, respectively, to the holder of the Eureka Hunter Holdings Series A Preferred Units. During such years, distributions in the amount of $1.9 million, $8.2 million, and $1.7 million, respectively, were paid-in-kind to the holder of the Eureka Hunter Holdings Series A Preferred Units, and the Company issued 97,492, 412,157, and 82,892 Eureka Hunter Holdings Series A Preferred Units, respectively, as payment.
	The Company evaluated the Eureka Hunter 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 Hunter Holdings Series A Preferred Units and presented in long term liabilities. The fair value of this embedded feature was $173.2 million and $75.9 million at October 3, 2014 and December 31, 2013, respectively. See “Note 9 - Fair Value of Financial Instruments”. The embedded derivative associated with the Eureka Hunter Holdings Series A Preferred Units was extinguished upon conversion as discussed in “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	On October 3, 2014, the outstanding Eureka Hunter Holdings Series A Preferred Units were purchased from Ridgeline by MSI and converted into Series A-2 Units of Eureka Hunter Holdings.
	As a result of the conversion of the Eureka Hunter 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 Hunter Holdings. The Series A-2 Units non-controlling interest was derecognized upon deconsolidation and included as part of the gain on deconsolidation. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	Extinguishment of Eureka Hunter 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 Hunter 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 Hunter 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 million and recognized a loss on extinguishment of the Eureka Hunter 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 Hunter 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_Notes

INCOME TAXES (Notes)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013			2012
		(in thousands)
	Deferred income tax benefit
	Federal	$	—		$	(78,743	)	$	(24,584	)
	State	—			(6,664		)	(81		)
	Total deferred tax benefit	$	—		$	(85,407	)	$	(24,665	)
	Total income tax benefit	$	—		$	(85,407	)	$	(24,665	)
	At December 31, 2014, the Company had net operating loss carry forwards (“NOLs”) available for U.S. federal income tax purposes of approximately $710 million, which expire in varying amounts during the tax years 2018 through 2034. 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, 2014, the Company was not under examination by any federal or state taxing jurisdiction, nor had the Company been contacted by any examining agency.
	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 $206.8 million against the net deferred tax assets of the Company at December 31, 2014. 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, 2014, 2013, and 2012 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Income tax benefit at statutory U.S. rate	$	(48,242	)	$	(111,132	)	$	(53,908	)
	State income taxes (net of federal benefit)	(3,616		)	(4,331		)	(53		)
	Tax effect of permanent differences	(498		)	750			(555		)
	Provision to return adjustment	(11,736		)	—			—
	Foreign statutory tax rate differences	297			—			—
	Tax effect of loss attributable to non-controlled interest	1,279			346			797
	Tax benefit recognized as tax expense in discontinued operations	—			(28,989		)	—
	Change in valuation allowance	63,341			58,341			29,047
	Other	(825		)	(392		)	7
	Total continuing operations	—			(85,407		)	(24,665		)
	Discontinued operations	—			11,773			3,071
	Total tax benefit	$	—		$	(73,634	)	$	(21,594	)
	Income (loss) before income taxes was as follows:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Domestic	$	(134,853	)	$	(317,520	)	$	(154,022	)
	Foreign	(2,980		)	—			—
	Loss from continuing operations	(137,833		)	(317,520		)	(154,022		)
	Gain (loss) from discontinued operations	4,561			(62,655		)	(8,125		)
	Gain (loss) on disposal of discontinued operations	(13,855		)	83,378			3,830
	Loss before income tax	$	(147,127	)	$	(296,797	)	$	(158,317	)
	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,
		2014			2013			2012
		(in thousands)
	Deferred tax assets:
	Net operating loss carry forwards	$	263,452		$	155,507		$	193,310
	Property and equipment	63,823			—			—
	Capital loss carry forward	38,401			—			—
	Share-based compensation	15,035			10,156			7,950
	Depletion carry forwards	1,047			1,047			997
	Tax credits	53			53			53
	US investment in Canada	—			74,148			—
	Other	1,562			561			532
	Deferred tax liabilities:
	Property and equipment	—			(90,950		)	(206,650		)
	Investment in Eureka Hunter Holdings	(176,606		)	—			—
	Valuation allowance
	Tax credits	(53		)	(53		)	(53		)
	Depletion carry forwards	(1,047		)	(1,047		)	(997		)
	Capital loss carry forward	(38,401		)	—			—
	Net operating losses	(167,266		)	(75,274		)	(69,400		)
	US investment in Canada	—			(74,148		)	—
Net deferred tax asset (liability)	$	—		$	—		$	(74,258	)
The increase in valuation allowance above of $56.2 million includes a $7.1 million decrease related to discontinued operations.
As of December 31, 2014, 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, 2014, 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, 2014, 2013 and 2012:
	Year Ended December 31,
	2014			2013			2012
	(in thousands)
Unrecognized tax benefits at January 1	$	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)	—			—			3,879
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_Notes

MAJOR CUSTOMERS (Notes)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 and 2012. 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. Although the Company is exposed to a concentration of credit risk, the Company believes that all of its purchasers are credit worthy.
	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,
		2014		2013		2012
	Samson Resources Company	24	%	31	%	17	%
	Teneska Marketing Ventures	17	%	10	%	14	%
	Markwest Liberty Midstream	15	%	6	%	—
	Baytex Energy USA LTD	7	%	11	%	15	%
	Continuum Midstream, LLC	5	%	6	%	13	%
	South Jersey	2	%	5	%	14	%
	Plains Marketing, LP	—		4	%	11	%

RELATED_PARTY_TRANSACTIONS_Not

RELATED PARTY TRANSACTIONS (Notes)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:
		As of December 31,
		2014				2013
		(in thousands)
	GreenHunter (1)
	Accounts receivable (payable) - net	$	(228	)		$	23
	Derivative assets (2)	$	75			$	79
	Investments (2)	$	1,311			$	2,262
	Notes receivable (2)	$	1,224			$	1,768
	Prepaid expenses	$	1,000			$	9
	Eureka Hunter Holdings (3)
	Accounts receivable (payable) - net	$	122			$	—
	Equity method investment	$	347,191			$	—
	Pilatus Hunter
	Accounts receivable (payable) - net	$	12			$	—
	The following table sets forth the related party transaction activities for the years ended December 31, 2014, 2013 and 2012:
				Years Ended
				December 31,
				2014				2013		2012
				(in thousands)
	GreenHunter
		Salt water disposal (1)		$	4,682			$	3,033	$	2,400
		Equipment rental (1)		291				282		1,000
		Gas gathering-trucking (1)		652				—		—
		MAG tank panels (1)		800				—		—
		Office space rental		44				13		—
		Interest income from note receivable (2)		154				205		191
		Dividends earned from Series C shares (2)		220				220		—
		Unrealized loss on investments (2)		951				730		1,333
	Pilatus Hunter, LLC
		Airplane rental expenses (4)		281				166		174
	Executive of the Company
		Corporate apartment rental expense (5)		—				—		23
	Eureka Hunter (3)
		Transportation costs		353				—		—
	_________________________________
	(1)	GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and Virco., wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.
	(2)	On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water, 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 other long-term assets and an available for sale investment in GreenHunter included in investments.
	(3)	Following a sequence of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. The Company deconsolidated Eureka Hunter Holdings and accounts for its retained interest as of December 31, 2014 under the equity method of accounting. See “Note 2 - Deconsolidation of Eureka Hunter 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)	During the year ended December 31, 2012, the Company paid rent under a lease for a Houston, Texas corporate apartment from an executive of the Company, which apartment was used by other Company employees when in Houston for Company business.  The lease terminated in May 2012.
	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.  See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”. 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 will provide a 50% credit for all services performed under the agreement until the prepayment amount is utilized in full, which is anticipated to occur during the year ending December 31, 2015.
	As of December 31, 2013, Mr. Evans, the Company's Chairman and Chief Executive Officer, held 27,641 Class A Common Units of Eureka Hunter Holdings. On October 3, 2014, in connection with the New LLC Agreement, these Class A Common Units were converted into Series A-1 Units.
	Triad Hunter and Eureka Hunter Pipeline are parties to an Amended and Restated Gas Gathering Services Agreement, which was executed on March 21, 2012, and amended on October 3, 2014 in contemplation of the New LLC Agreement. Under the terms of the gathering agreement, Triad Hunter reserved throughput capacity in the gas gathering pipeline system of Eureka Hunter Holdings for which Triad Hunter has committed to minimum reservation fees of approximately $0.75 per MMBtu. See “Note 18 - Commitments and Contingencies”.
	In addition, the Company and Eureka Hunter Holdings entered into a Services Agreement on March 20, 2012, and amended on September 15, 2014, under which the Company agreed to provide administrative services to Eureka Hunter Holdings related to its operations. The terms of the Services Agreement provide that the Company will receive an administrative fee of $500,000 per annum and a personnel services fee equal to the Company’s employee cost plus 1.5% subject to mutually agreed upon increases from time to time. Under the terms of the New LLC Agreement, on or before March 31, 2015, unless extended, certain specified employees of the Company that perform service for Eureka Hunter Holdings and its subsidiaries and for whom, the Company previously billed a personnel services fee, will become employees of Eureka Hunter Holdings or a subsidiary of Eureka Hunter Holdings. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Holdings and its subsidiaries became related parties of the Company.
	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, 2014, the Company paid Mr. Trosclair $71,000, which includes reimbursement of expenses incurred on behalf of the Company.

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Notes)	12 Months Ended
	Dec. 31, 2014
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 have appealed the decision to the U.S. Court of Appeals for the Second Circuit. The Company intends to continue vigorously defending the Securities Cases. It is possible that additional investor lawsuits could be filed over these events.
	On May 10, 2013, Steven Handshu filed a stockholder derivative suit in the 151st Judicial District Court of Harris County, Texas on behalf of the Company against the Company's directors and senior officers. On June 6, 2013, Zachariah Hanft filed another stockholder derivative suit in the Southern District of New York on behalf of the Company against the Company's directors and senior officers. On June 18, 2013, Mark Respler filed another stockholder derivative suit in the District of Delaware on behalf of the Company against the Company's directors and senior officers. On June 27, 2013, Timothy Bassett filed another stockholder derivative suit in the Southern District of Texas on behalf of the Company against the Company's directors and senior officers. On September 16, 2013, the Southern District of Texas allowed Joseph Vitellone to substitute for Mr. Bassett as plaintiff in that action. On March 19, 2014 Richard Harveth filed another stockholder derivative suit in the 125th District Court of Harris County, Texas.  These suits are collectively referred to as the Derivative Cases. The Derivative Cases assert that the individual defendants unjustly enriched themselves and breached their fiduciary duties to the Company by publishing allegedly false and misleading statements to the Company's investors regarding the Company's business and financial position and results, and allegedly failing to maintain adequate internal controls. The complaints demand that the defendants pay unspecified damages to the Company, including damages allegedly sustained by the Company as a result of the alleged breaches of fiduciary duties by the defendants, as well as disgorgement of profits and benefits obtained by the defendants, and reasonable attorneys', accountants' and experts' fees and costs to the plaintiff. On December 20, 2013, the United States District Court for the Southern District of Texas granted the Company’s motion to dismiss the stockholder derivative case maintained by Joseph Vitellone and entered a final judgment of dismissal. The court held that Mr. Vitellone failed to plead particularized facts demonstrating that pre-suit demand on the Company’s board was excused. In addition, on December 13, 2013, the 151st Judicial District Court of Harris County, Texas dismissed the lawsuit filed by Steven Handshu for want of prosecution after the plaintiff failed to serve any defendant in that matter. On January 21, 2014, the Hanft complaint was dismissed with prejudice after the plaintiff in that action filed a voluntary motion for dismissal. On February 18, 2014, the United States District Judge for the District of Delaware granted the Company’s supplemental motion to dismiss the Derivative Case filed by Mark Respler. All of the Derivative Cases have now been dismissed, except the Derivative Case filed by Richard Harveth, for which the Company is presently seeking dismissal. It is possible that additional stockholder derivative suits could be filed over these events.
	In addition, the Company has received several demand letters from stockholders seeking books and records relating to the allegations in the Securities Cases and the Derivative Cases under Section 220 of the Delaware General Corporation Law. On September 17, 2013, Anthony Scavo, who is one of the stockholders that made a demand, filed a books and records action in the Delaware Court of Chancery pursuant to Section 220 of the Delaware General Corporation Law (“Scavo Action”). The Scavo Action seeks various books and records relating to the claims in the Securities Cases and the Derivative Cases, as well as costs and attorneys’ fees. The Company has filed an answer in the Scavo Action, which has now been dismissed. It is possible that additional similar actions may be filed and that similar stockholder demands could be made.
	In April 2013, the Company also received a letter from the SEC stating that the SEC's Division of Enforcement was conducting an inquiry regarding the Company's internal controls, change in outside auditors and public statements to investors and asking the Company to preserve documents relating to these matters. The Company is complying with this request. On December 30, 2013, the Company received a document subpoena relating to the issues identified in the April 2013 letter. In 2014, the SEC issued additional subpoenas for documents and testimony and has taken testimony from certain individuals. The Company intends to cooperate with the subpoenas.
	Any potential liability, if any, from these claims cannot currently be estimated.
	Twin Hickory Matter
	On April 11, 2013, a flash fire occurred at Eureka Hunter Pipeline’s Twin Hickory site located in Tyler County, West Virginia. The incident occurred during a pigging operation at a natural gas receiving station. Two employees of third-party contractors received fatal injuries. Another employee of a third-party contractor was also injured.
	In mid-February 2014, the estate of one of the deceased third-party contractor employees sued Eureka Hunter Pipeline and certain other parties in a case styled Karen S. Phipps v. Eureka Hunter Pipeline, LLC et al., Civil Action No. 14-C-41, in the Circuit Court of Ohio County, West Virginia. In October 2014, in a case styled Exterran Energy Solutions, LP v. Eureka Hunter Pipeline, LLC and Magnum Hunter Resources Corporation, Civil Action No. 2014-63353, in the District Court of Harris County, Texas, Exterran Energy Solutions, LP, one of the co-defendants in the Phipps lawsuit, filed suit against the Company and Eureka Hunter Pipeline seeking a declaratory judgment that Eureka Hunter Pipeline is obligated to indemnify Exterran with respect to the Phipps lawsuit. In April 2014, the estate of the other deceased third-party contractor employee sued the Company, Eureka Hunter Pipeline and certain other parties in a case styled Antoinette M. Miller v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-111, in the Circuit Court of Ohio County, West Virginia. The plaintiffs allege that Eureka Hunter Pipeline and the other defendants engaged in certain negligent and reckless conduct which resulted in the wrongful death of the third-party contractor employees. The plaintiffs have demanded judgment for an unspecified amount of compensatory, general and punitive damages. Various cross-claims have also been asserted. In May 2014, the injured third-party contractor employee sued Magnum Hunter Resources Corporation and certain other parties in a case styled Jonathan Whisenhunt v. Magnum Hunter Resources Corporation et al, Civil Action No. 14-C-135, in the Circuit Court of Ohio County, West Virginia. The claim filed by the injured third-party contractor employee, Jonathan Whisenhunt, has been resolved and dismissal of this case is anticipated in the near term. A portion of the settlement was paid by an insurer of Eureka Hunter Pipeline, and the remainder paid by the co-defendants or their insurers. The cross-claims among the defendants in the Whisenhunt litigation have not been resolved. Investigation regarding the incident is ongoing. It is not possible to predict at this juncture the extent to which, if at all, Eureka Hunter Pipeline or any related entities will incur liability or damages because of this incident. However, the Company believes that its insurance coverage will be sufficient to cover any losses or liabilities it may incur as a result of this incident.
	PRC Williston Matter
	On December 16, 2013, Drawbridge Special Opportunities Fund LP and Fortress Value Recovery Fund I LLC f/k/a D.B. Zwirn Special Opportunities Fund, L.P. (together, the “Plaintiffs”) filed suit against PRC Williston in the Court of Chancery of the State of Delaware. PRC Williston and the Plaintiffs entered into Participation Agreements in February 2007 in connection with the Plaintiffs extending credit to PRC Williston pursuant to a credit agreement entitling the Plaintiffs 12.5% collective interest in any distributions in respect of the equity interests of the members of PRC Williston. Plaintiffs claimed that they were entitled to compensation for 12.5% of alleged past distributions on equity from PRC Williston to Magnum Hunter and 12.5% of any transfers of funds to Magnum Hunter from the proceeds of the December 30, 2013 sale of PRC Williston’s assets. On December 23, 2013, the Chancery Court entered a temporary restraining order prohibiting PRC Williston from transferring, assigning, removing, distributing or otherwise displacing to Magnum Hunter, Magnum Hunter’s creditors, or any other person or entity, $5.0 million of the proceeds received by PRC Williston in connection with the sale of its assets. On March 18, 2014, the Court granted Plaintiff’s motion for a preliminary injunction, extending the relief granted by the temporary restraining order until after a full trial on the merits.
	On July 24, 2014, the Company, PRC Williston, and the Plaintiffs executed a Settlement and Release Agreement (“the Settlement Agreement”). Per the terms of the Settlement Agreement, PRC Williston paid approximately $2.9 million in cash to Drawbridge Special Opportunities Fund LP. As a result of the Settlement Agreement, the Company, PRC Williston, and the Plaintiffs agreed to release each other from all claims, past, present or future, related to the dispute. In addition, with the execution of the Settlement Agreement, the parties agreed to terminate, in all respects, the Participation Agreements and that none of the parties would have any further rights or obligations thereunder. With the cash settlement payment and the termination of the Participation Agreements, the Company now has rights and claims to 100% of the equity interests in PRC Williston and its remaining assets and liabilities. Consequently, there is no longer any non-controlling interest in PRC Williston’s equity reflected in our consolidated financial statements.
	General
	We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.
	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, 2014 and 2013 was $640,695.
	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 $19.4 million as of December 31, 2014. 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 $3.1 million as of December 31, 2014.
	Eureka Hunter Pipeline Gas Gathering Agreement
	On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement with Eureka Hunter Pipeline. 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 Hunter Pipeline and Triad Hunter were both wholly-owned subsidiaries of the Company. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Pipeline became a related party (see “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 17 - Related Party Transactions”). As of December 31, 2014, Triad Hunter and Eureka Hunter Pipeline were parties to six individual transaction confirmations with terms ranging from eight to fourteen years. Triad Hunter’s maximum daily quantity committed was 135,000 MMBtu per day at an aggregate reservation fee of $0.75 per MMBtu. Triad Hunter’s remaining obligation under the contract was $98.0 million as of December 31, 2014.
	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 $13.0 million;
	ii	during the period beginning on the date that is twenty-one months after the Precedent Agreement Date and ending on the day immediately prior to the date that is twenty-eight months after the Precedent Agreement Date, an amount equal to $36.0 million; and
	iii	during the period beginning on the date that is twenty-eight months after the Precedent Agreement Date and ending on the date the Credit Support Agreement terminates, an amount equal to $65.0 million.
	Provided however, that the Credit Support Amount shall be subject to reduction (on a cumulative basis) at specified dates depending on Triad Hunter's Interest Coverage Ratio or if Triad Hunter meets the creditworthiness standards established in the Texas Gas FERC Gas Tariff as in effect on such date that Triad Hunter meets the said standard. Due to recent changes in the transportation market in the southern Appalachian Basin and the additional announcements of new pipeline capacity under construction in this region, the Company is currently reviewing the possible cancellation of this agreement.
	REX Transportation Agreement
	On October 8, 2014, Triad Hunter executed a Precedent Agreement with Rockies Express Pipeline LLC (“REX”), (“REX Transportation Services Agreement”) for the delivery by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter. In executing the REX Transportation Services Agreement, Triad Hunter committed to purchase 100,000 MMBtu per day of firm transportation from REX. The term of the REX Transportation Services Agreement will commence with the date the pipeline project is available for service, currently anticipated to be between mid-2016 and mid-2017, and will end 15 years thereafter. The execution of a Firm Transportation Agreement is contingent upon REX receiving appropriate approvals from FERC for their pipeline project. Upon executing a Firm Transportation Agreement, the Company will have minimum annual contractual obligations for reservation charges of approximately $16.4 million over the 15 year term of the agreement.
	In addition, the Company was required to provide credit support to REX, in the form of a letter of credit, in the initial amount of twenty-seven months of Triad Hunter’s reservation charges, within 45 days of executing the REX Transportation Services Agreement. The Company posted a letter of credit for $36.9 million for the benefit of REX on November 25, 2014, using availability under the Company’s Senior Revolving Credit Facility. The borrowing capacity under the Senior Revolving Credit Facility was reduced by $36.9 million. No amounts have been drawn against the letter of credit as of December 31, 2014.
	Future minimum gathering, processing, and transportation commitments related to the REX Transportation Services Agreement and the TGT Transportation Services Agreement are not included in the table below, as they are not contractual obligations until the execution of Firm Transportation Agreements, subject to the related projects being approved by FERC. Future minimum gathering, processing, and transportation commitments at December 31, 2014, are as follows (in thousands):
	2015	$	11,567
	2016	$	11,591
	2017	$	11,567
	2018	$	11,567
	2019	$	11,567
	Thereafter	$	62,655
	Agreement to Purchase Utica Shale Acreage
	On August 12, 2013, Triad Hunter entered into an asset purchase agreement with MNW. Pursuant to the purchase agreement, Triad Hunter agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in such counties within the state of Ohio, over a period of time, in staggered closings, subject to certain conditions. During the year ended December 31, 2013, Triad Hunter purchased a total of 5,922 net leasehold acres from MNW for $24.6 million in multiple closings.
	On December 30, 2013, a lawsuit was filed against the Company, Triad Hunter, MNW and others by Dux Petroleum, LLC (“Dux”) asserting certain claims relating to the acreage covered by the asset purchase agreement with MNW. As a result of the litigation, no purchases were made during the first quarter of 2014. On May 28, 2014, the litigation was settled by all parties. As part of the settlement, the Company and Triad Hunter agreed to collectively pay Dux the aggregate amount of $500,000. Subsequent to the settlement of the lawsuit, Triad Hunter resumed closings of lease acquisitions from MNW.
	On October 28, 2014, Triad Hunter and MNW entered into the First Amendment to the Asset Purchase Agreement and Partial Release of Earn-Out Agreement (“Amendment”). In connection with the asset purchase agreement with MNW dated August 12, 2013, Triad Hunter and MNW also entered into an earn-out agreement dated August 12, 2013, which provided for MNW to perform certain consulting services for Triad Hunter and to be paid for such services through the release by Triad Hunter of escrow funds being withheld from the purchase price at each closing under the asset purchase agreement. The Amendment terminates MNW's obligation to perform further consulting services under the earn-out agreement, provides for the disbursement of funds to MNW that have been held in escrow from closings to date, and amends the asset purchase agreement to end further withholdings of escrow funds from the purchase price at future closings.
	During the year ended December 31, 2014, Triad Hunter purchased a total of 16,456 net leasehold acres from MNW for $67.3 million in multiple closings, and also released $0.4 million in escrowed funds, for a total disbursement to MNW of approximately $67.7 million. As of December 31, 2014, under the asset purchase agreement, Triad Hunter has now acquired a total of approximately 22,379 net leasehold acres from MNW, or approximately 70% of the approximately 32,000 total net leasehold acres originally anticipated under the asset purchase agreement.
	Settlement Agreement with Continuum Energy Services
	On January 10, 2014, the Company and certain of its subsidiaries entered into an Omnibus Settlement Agreement and Release (“Settlement Agreement”) dated January 9, 2014 with Continuum Energy Services, L.L.C. (formerly known as Seminole Energy Services, L.L.C.) and certain of its affiliates (collectively, “Continuum”). In connection with and pursuant to the terms of the Settlement Agreement, the Company and Continuum agreed to release and discharge each other from all claims and causes of action alleged in, arising from or related to certain legal proceedings and to terminate, amend and enter into certain new, related agreements effective immediately prior to year-end on December 31, 2013 (“New Agreements”).
	By entering into the New Agreements, the Company and Continuum restructured their existing agreements. The Company obtained a reduction in gas gathering rates it pays for natural gas owned or controlled by the Company that is gathered on the Stone Mountain Gathering System located in the state of Kentucky. The Company and Continuum collectively agreed to construct an enhancement of the Rogersville Plant designed to recover less ethane and more propane from the natural gas processed at the Rogersville Plant. The parties also agreed to reduce and extend the Company's contractual horizontal well drilling obligations owed to Continuum. The Company's future drilling obligation to Continuum, which required the Company to drill and complete four wells in southern Appalachia, expired on June 30, 2014, and, pursuant to the Settlement Agreement, the Company paid Continuum $450,000 as a result of the Company’s decision not to drill two of the required four wells.
	The Company and Continuum also agreed to modify the natural gas processing rates the Company pays for processing at the Rogersville Plant, the Company's allocation of NGLs recovered from gas processed and the costs of blend stock necessary to blend with the NGLs produced from the Rogersville Plant, and certain deductions to the NGLs purchase price the Company will pay Continuum for the Company's NGLs produced from the Rogersville Plant. Additionally, Continuum sold to the Company Continuum's 50% interest in a natural gas gathering trunk line and treatment facility located in southwestern Muhlenberg County, Kentucky, which had previously been owned equally by Continuum and the Company.
	Drilling Rig Purchase
	During June 2014, the Company, through its 100% owned subsidiary, Alpha Hunter Drilling, LLC, executed an agreement to purchase a new drilling rig for a total purchase price of approximately $6.5 million, including a $1.3 million deposit due on July 1, 2014 with the remainder due upon delivery, which was expected to be on or about January 15, 2015.
	In February 2015, the Company was notified that the rig was complete and available for delivery. However, the Company has not taken delivery of the rig and has notified the seller that until performance issues related to a separate rig of the same model purchased by the Company from the seller are resolved, that it does not intend to take delivery of the rig. See “Note 22 - Subsequent Events”.
	PVA Arbitration Decision
	On July 25, 2014, the Company received the final determination from the arbitrator in the disagreement related to the final working capital adjustments pertaining to the sale of Eagle Ford Hunter to Penn Virginia in 2013. As a result, the Company recorded a total liability of $33.7 million, plus accrued interest of $1.3 million, based upon the final determination made by the arbitrator. This amount was settled in cash on July 31, 2014. The arbitrator declined to rule, on the basis of lack of authority, on two claims made by Penn Virginia related to working capital adjustments governed by a transition services agreement in the amount of $7.8 million. Any potential liability from these claims cannot currently be estimated. Management has determined these additional claims are meritless.
	Operating Leases
	As of December 31, 2014, office space rentals with terms of 12 months or greater include office spaces in Houston, Texas, at a monthly cost of $33,800, and office spaces in Grapevine, Texas, with monthly payments of approximately $4,800.
	Future minimum lease commitments under non-cancelable operating leases at December 31, 2014, are as follows (in thousands):
	2015	$	502
	2016	$	239
	2017	$	121
	2018	$	124
	2019	$	53
	Thereafter	$	—
	Services Agreement
	On March 21, 2012, Triad Hunter entered into the Amended and Restated Gas Gathering Services Agreement with Eureka Hunter Pipeline. Further, on March 20, 2012, and amended on March 21, 2012, the Company and Eureka Hunter Holdings entered into a Services Agreement to provide administrative services. The terms of the Services Agreement provide that the Company will receive an Administrative Services 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. Upon the deconsolidation of Eureka Hunter Holdings on December 18, 2014, Eureka Hunter Pipeline became a related party. See “Note 17 - Related Party Transactions”.
Environmental Contingencies
The exploration, development and production of oil and gas assets, the operations of oil and natural gas gathering systems, and the performance of oil field services are subject to various federal, state, local and foreign laws and regulations designed to protect the environment. Compliance with these regulations is part of the Company's day-to-day operating procedures. Infrequently, accidental discharge of such materials as oil, natural gas or drilling fluids can occur and such accidents can require material expenditures to correct. The Company maintains various levels and types of insurance which it believes to be appropriate to limit its financial exposure. As of December 31, 2014, the Company is unaware of any material capital expenditures which may be required for environmental control.
On December 13, 2014, the Company lost control of the Stalder 3UH well located in Monroe County, Ohio. On December 23, 2014, the well was temporarily capped and the well head assembly had been successfully replaced. There is currently no evidence of environmental damage to the immediate area as a result of the blowout, and no personnel were injured in connection with the well control operations on the Stalder Pad. The Company believes that there has been no damage to the overall structure or integrity of the Stalder 3UH well and that the three other Utica Shale wells and the one Marcellus Shale well also located on the Company’s Stalder Pad have been unaffected and are currently producing. The Company further believes that its control of well insurance will be adequate to cover all losses incurred by it in connection with the blowout of the Stalder 3UH well (subject to the normal retention amount of the insurance policy).

SUPPLEMENTAL_CASH_FLOW_INFORMA

SUPPLEMENTAL CASH FLOW INFORMATION (Notes)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013			2012
		(in thousands)
	Cash paid for interest	$	73,192		$	67,736		$	35,669
	Cash paid for taxes	$	—		$	1,200		$	—
	Non-cash transactions
	Change in accrued capital expenditures - increase (decrease)	$	127,068		$	(65,634	)	$	34,621
	Eureka Hunter Holdings, LLC Series A convertible preferred unit dividends paid in kind	$	1,950		$	8,243		$	1,658
	Non-cash additions to asset retirement obligation	$	3,426		$	2,132		$	8,492
	Common stock issued for 401k matching contributions	$	1,593		$	1,192		$	874
	Preferred stock issued for acquisitions	$	—		$	—		$	64,968
	Eureka Hunter Holdings, LLC Class A common units issued for an acquisition	$	—		$	—		$	12,453
	Non-cash consideration received from sale of assets	$	9,447		$	42,300		$	7,120
	Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units	$	(51,692	)	$	—		$	—
	Common stock issued for acquisitions	$	—		$	—		$	1,902
	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_Notes

SEGMENT REPORTING (Notes)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment Reporting	NOTE 20 - SEGMENT REPORTING
	U.S. Upstream, Midstream and Oilfield Services represent the operating segments of the Company. As of December 31, 2013 the Canadian Upstream segment, comprised of the WHI Canada operations, were classified as assets held for sale and discontinued operations. The Upstream segments are organized and operate to explore for and produce crude oil and natural gas within the geographic boundaries of the U.S. and Canada. The Midstream segment 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. 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, 2014, 2013, and 2012.
		For the Year Ended December 31, 2014
		U.S. Upstream			Canadian Upstream			Midstream and Marketing (1)			Oil Field Services			Corporate Unallocated(2)			Intersegment Eliminations			Total
		(in thousands)
	Total revenue	$	270,615		$	—		$	109,658		$	31,392		$	—		$	(20,196	)	$	391,469
	Depreciation, depletion, and accretion	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	(7,155		)	10,636			—			—			(12,775		)	—			(9,294		)
	Net income (loss)	$	(416,817	)	$	10,636		$	(98,426	)	$	782		$	360,400		$	(3,702	)	$	(147,127	)
	Total assets	$	1,162,732		$	—		$	454		$	46,995		$	462,025		$	(2,377	)	$	1,669,829
	Total capital expenditures	$	470,538		$	305		$	221,455		$	8,079		$	231		$	—		$	700,608
		For the Year Ended December 31, 2013
		U.S. Upstream			Canadian Upstream			Midstream and Marketing (1)			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
		(in thousands)
	Total revenue	$	225,498		$	—		$	69,306		$	21,527		$	—		$	(11,793	)	$	304,538
	Depreciation, depletion, and accretion	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	159,225			(150,207		)	—			—			—			(69		)	8,949
	Net income (loss)	$	35,208		$	(150,207	)	$	(25,875	)	$	(590	)	$	(81,698	)	$	(2	)	$	(223,164	)
	Total assets	$	1,373,041		$	68,367		$	296,739		$	44,193		$	77,684		$	(3,373	)	$	1,856,651
	Total capital expenditures (3)	$	444,385		$	15,352		$	87,498		$	22,440		$	1,037		$	—		$	570,712
		For the Year Ended December 31, 2012
		U.S. Upstream			Canadian Upstream			Midstream and Marketing (1)			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
		(in thousands)
	Total revenue	$	134,339		$	—		$	15,692		$	13,552		$	—		$	(3,646	)	$	159,937
	Depreciation, depletion, and accretion	65,040			—			5,963			967			—			468			72,438
	Loss (gain) on sale of assets	246			—			(250		)	600			—			—			596
	Other operating expenses	167,423			—			11,706			10,838			27,137			(3,541		)	213,563
	Other income (expense)	(10,210		)	—			7,388			(482		)	(24,121		)	63			(27,362		)
	Income (loss) from continuing operations before income tax	(108,580		)	—			5,661			665			(51,258		)	(510		)	(154,022		)
	Income tax benefit	24,665			—			—			—			—			—			24,665
	Total income (loss) from discontinued operations, net of tax	18,856			(25,021		)	—			145			—			(1,344		)	(7,364		)
	Net income (loss)	$	(65,059	)	$	(25,021	)	$	5,661		$	810		$	(51,258	)	$	(1,854	)	$	(136,721	)
	Total assets	$	1,602,022		$	392,918		$	245,207		$	23,810		$	93,612		$	(158,937	)	$	2,198,632
	Total capital expenditures (3)	$	927,456		$	86,612		$	84,348		$	11,657		$	785		$	—		$	1,110,858
	______________
	(1)	Includes operations of Eureka Hunter Holdings, which represents approximately 38.6%, 40.7%, and 71.6% of Midstream and Marketing revenues for the years ended December 31, 2014, 2013, and 2012, respectively, and which was deconsolidated as of December 18, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	(2)	Includes the Company’s retained interest in Eureka Hunter Holdings which has a value of $347 million at December 31, 2014.
	(3)	Presentation of capital expenditures has been changed from prior year presentation in order to reflect capital expenditures incurred rather than cash paid for capital expenditures.

CONDENSED_CONSOLIDATED_GUARANT

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS (Notes)	12 Months Ended
	Dec. 31, 2014
Guarantees [Abstract]
CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS	NOTE 21 - CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS
	Guarantor Subsidiaries
	Certain of the Company’s subsidiaries, including Alpha Hunter Drilling, LLC, Bakken Hunter, Shale Hunter, Magnum Hunter Marketing, LLC, MHP, NGAS Hunter, LLC, Triad Hunter, and Virco (collectively, “Guarantor Subsidiaries”), jointly and severally guarantee on a senior unsecured basis, the obligations of the Company under all the Senior Notes issued under the indenture entered into by the Company on May 16, 2012, as supplemented. The Guarantor Subsidiaries may also guarantee any debt of the Company issued pursuant to the Form S-3 Registration Statement filed by the Company with the SEC on August 5, 2014.
	These condensed consolidating guarantor financial statements have been revised to reflect Eagle Ford Hunter and PRC Williston as a non-guarantors as the subsidiaries are no longer guarantors of the Company’s Senior Notes. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
	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, 2014 and 2013 and for the years ended December 31, 2014, 2013, and 2012 is as follows:
	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Balance Sheets
	(in thousands)
			As of December 31, 2014
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	ASSETS
	Current assets		$	85,647			$	36,338			$	589			$	(2,378	)		$	120,196
	Intercompany accounts receivable		1,113,417				—				—				(1,113,417		)		—
	Property and equipment (using successful efforts accounting)		5,506				1,170,122				30				—				1,175,658
	Investment in subsidiaries		(91,595		)		94,134				—				(2,539		)		—
	Investment in affiliate, equity-method		347,191				—				—				—				347,191
	Other assets		22,804				3,980				—				—				26,784
	Total Assets		$	1,482,970			$	1,304,574			$	619			$	(1,118,334	)		$	1,669,829
	LIABILITIES AND SHAREHOLDERS' EQUITY
	Current liabilities		$	25,347			$	142,914			$	2,567			$	(2,383	)		$	168,445
	Intercompany accounts payable		—				1,073,091				42,560				(1,115,651		)		—
	Long-term liabilities		925,767				43,762				—				—				969,529
	Redeemable preferred stock		100,000				—				—				—				100,000
	Shareholders' equity (deficit)		431,856				44,807				(44,508		)		(300		)		431,855
	Total Liabilities and Shareholders' Equity		$	1,482,970			$	1,304,574			$	619			$	(1,118,334	)		$	1,669,829
	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Balance Sheets
	(in thousands)
			As of December 31, 2013
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	ASSETS
	Current assets		$	53,161			$	43,841			$	27,096			$	(3,372	)		$	120,726
	Intercompany accounts receivable		965,138				—				—				(965,138		)		—
	Property and equipment (using successful efforts accounting)		7,214				1,272,027				234,838				—				1,514,079
	Investment in subsidiaries		372,236				102,314				—				(474,550		)		—
	Other assets		17,308				100,894				103,644				—				221,846
	Total Assets		$	1,415,057			$	1,519,076			$	365,578			$	(1,443,060	)		$	1,856,651
	LIABILITIES AND SHAREHOLDERS' EQUITY
	Current liabilities		$	54,826			$	97,520			$	34,929			$	(3,410	)		$	183,865
	Intercompany accounts payable		—				921,237				43,866				(965,103		)		—
	Long-term liabilities		818,651				39,067				127,663				—				985,381
	Redeemable preferred stock		100,000				—				136,675				—				236,675
	Shareholders' equity (deficit)		441,580				461,252				22,445				(474,547		)		450,730
	Total Liabilities and Shareholders' Equity		$	1,415,057			$	1,519,076			$	365,578			$	(1,443,060	)		$	1,856,651
	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Statements of Operations
	(in thousands)
			For the Year Ended December 31, 2014
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	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 loss 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 Hunter Holdings		(51,692		)		—				—				—				(51,692		)
Net income (loss) attributable to common shareholders		$	(249,875	)		$	(411,902	)		$	(109,810	)		$	521,714			$	(249,873	)
		For the Year Ended December 31, 2013
		Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
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		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
Condensed Consolidating Statements of Operations
(in thousands)
		For the Year Ended December 31, 2012
		Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
Revenues		$	729			$	141,772			$	21,080			$	(3,644	)		$	159,937
Expenses		54,047				212,071				32,487				15,354				313,959
Loss from continuing operations before equity in net income of subsidiaries		(53,318		)		(70,299		)		(11,407		)		(18,998		)		(154,022		)
Equity in net income of subsidiaries		(102,545		)		458				(23,362		)		125,449				—
Income (loss) from continuing operations before income tax		(155,863		)		(69,841		)		(34,769		)		106,451				(154,022		)
Income tax benefit		11,290				13,375				—				—				24,665
Income (loss) from continuing operations		(144,573		)		(56,466		)		(34,769		)		106,451				(129,357		)
Loss from discontinued operations, net of tax		—				(209		)		(9,564		)		—				(9,773		)
Gain on disposal of discontinued operations, net of tax		—				2,409				—				—				2,409
Net income (loss)		(144,573		)		(54,266		)		(44,333		)		106,451				(136,721		)
Net income attributable to non-controlling interest		—				—				—				4,013				4,013
Net income (loss) attributable to Magnum Hunter Resources Corporation		(144,573		)		(54,266		)		(44,333		)		110,464				(132,708		)
Dividends on preferred stock		(22,842		)		—				(11,864		)		—				(34,706		)
Net income (loss) attributable to common shareholders		$	(167,415	)		$	(54,266	)		$	(56,197	)		$	110,464			$	(167,414	)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
(in thousands)
	For the Year Ended December 31, 2014
	Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
	Resources				Subsidiaries				Subsidiaries								Resources
	Corporation																Corporation
																	Consolidated
Net income (loss)	$	(162,819	)		$	(411,902	)		$	(90,467	)		$	518,061			$	(147,127	)
Foreign currency translation loss	—				—				(1,204		)		—				(1,204		)
Unrealized gain (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
	Resources				Subsidiaries				Subsidiaries								Resources
	Corporation																Corporation
																	Consolidated
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	)
	For the Year Ended December 31, 2012
	Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
	Resources				Subsidiaries				Subsidiaries								Resources
	Corporation																Corporation
																	Consolidated
Net income (loss)	$	(144,573	)		$	(54,266	)		$	(44,333	)		$	106,451			$	(136,721	)
Foreign currency translation loss	—				—				3,883				—				3,883
Unrealized gain (loss) on available for sale securities	—				(309		)		—				—				(309		)
Comprehensive income (loss)	(144,573		)		(54,575		)		(40,450		)		106,451				(133,147		)
Comprehensive (income) loss attributable to non-controlling interest	—				—				—				4,013				4,013
Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(144,573	)		$	(54,575	)		$	(40,450	)		$	110,464			$	(129,134	)
Magnum Hunter Resources Corporation and Subsidiaries
Condensed Consolidating Statements of Cash Flows
(in thousands)
		For the Year Ended December 31, 2014
		Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
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				Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
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
		For the Year Ended December 31, 2012
		Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
Cash flow from operating activities		$	(458,921	)		$	281,782			$	236,360			$	(1,210	)		$	58,011
Cash flow from investing activities		(364,045		)		(287,204		)		(357,961		)		3				(1,009,207		)
Cash flow from financing activities		831,080				1,781				162,374				1,207				996,442
Effect of exchange rate changes on cash		—				—				(2,474		)		—				(2,474		)
Net increase (decrease) in cash		8,114				(3,641		)		38,299				—				42,772
Cash at beginning of period		18,758				(546		)		(3,361		)		—				14,851
Cash at end of period		$	26,872			$	(4,187	)		$	34,938			$	—			$	57,623

SUBSEQUENT_EVENTS_Notes

SUBSEQUENT EVENTS (Notes)	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 22 - SUBSEQUENT EVENTS
	Closing of additional MNW Interests
	On January 14, 2015, Triad Hunter purchased approximately 2,665 net acres of undeveloped leasehold in the Utica Shale in Ohio for $12.0 million under its asset purchase agreement with MNW. Following this purchase, approximately 6,956 net acres remain to be purchased by the Company under the asset purchase agreement with MNW, contingent upon the remaining leasehold acreage being cured of title defects acceptable to Triad Hunter.
	Departure of Officer and Closing of Certain Offices
	Effective January 31, 2015, R. Glenn Dawson resigned from his position as Executive Vice President of the Company and President of the Company’s Williston Basin Division, and as an employee of the Company. In connection with Mr. Dawson’s resignation, the Company and Mr. Dawson entered into a letter agreement regarding severance (the “Severance Agreement”) and a Release and Confidentiality Agreement, each dated as of January 29, 2015. Pursuant to the Severance Agreement, the Company agreed to pay Mr. Dawson a total of CAD $550,000 ($435,000 USD) in severance pay, less applicable statutory withholding deductions (the “Severance Amount”). The Severance Amount, the determination of which took into account certain rights of Canadian employees to severance under Canadian law, will be paid by the Company to Mr. Dawson in approximately equal bi-weekly installments during the period from February 1, 2015 to June 15, 2015. Pursuant to the Release and Confidentiality Agreement, Mr. Dawson provided a customary general release of claims against the Company and its affiliates, including claims relating to severance under Canadian law, and agreed to customary confidentiality provisions.
	Due to a combination of the sale last year of all of the Company’s Canadian assets and a substantial portion of its Bakken assets located in North Dakota, the increasing focus on the Company’s natural gas and NGLs exploration and production activities located in West Virginia and Ohio, and in an effort to reduce general and administrative costs, the Company has closed its Denver, Colorado and Calgary, Alberta offices effective January 31, 2015 and terminated all employees at those locations. The Company has also moved the responsibilities of the former personnel at those now-closed offices to existing personnel at the Company’s Houston and Grapevine, Texas offices.
	New Corporate Office in Irving, Texas
	In connection with the Company’s announced plans to relocate its corporate headquarters from Houston, Texas to the Dallas, Texas area, the Company’s finance, treasury and reserve engineering departments will be moving to the Dallas. Additionally, the Company plans to consolidate its accounting, financial reporting, information systems, legal and human resources departments, which are currently located in Grapevine, Texas, to its new corporate headquarters. In connection with the corporate headquarters relocation, the Company entered into a sublease agreement to lease commercial office space in Irving (Las Colinas), Texas, in order to relocate its corporate headquarters. The commencement date of the sublease was January 16, 2015, and the sublease expires on January 31, 2018. The sublease rent is $366,000 per year.
	ND Pipeline Agreements
	On January 16, 2015, Bakken Hunter executed an Agreement for the Construction, Ownership and Operation of the ND Pipeline Facilities (the “ND Pipeline Facilities Agreement) and a Gas Purchase Agreement with Steppe Petroleum Inc (“Steppe”). Under the terms of the ND Pipeline Facilities Agreement, Bakken Hunter agreed to construct a gas gathering pipeline (the “ND Pipeline”), approximately one mile in length, spanning from the Canadian border to the Oneok Rockies Divide County gas gathering system, which is owned and operated by ONEOK Rockies Midstream, LLC (“Oneok”). Bakken Hunter currently acts as operator of the ND Pipeline and Steppe has borne all the costs associated with the operation, construction, and modifications to the ND Pipeline until such time as either (i) Bakken Hunter exercises its right to cause Steppe to takeover operatorship, or (ii) Steppe exercises their right to step in as or replace Bakken Hunter as operator. Upon execution of the agreement, Steppe became obligated to reimburse Bakken Hunter approximately $689,000 for costs incurred for the construction of the ND Pipeline.
	Bakken Hunter also agreed to purchase all natural gas that is gathered from Steppe’s wells through the ND Pipeline and delivered into the Oneok Rockies Divide County gas gathering system. Bakken Hunter sells all natural gas purchased from Steppe to Oneok in a back-to-back transaction. Bakken Hunter must remit to Steppe all proceeds from natural gas sold to Oneok under this agreement less an administrative fee of $0.05 per Mcf gathered.
	Rig Purchase by Alpha Hunter Drilling, LLC.
	In February 2015, the Company was notified that the drilling rig, for which Alpha Hunter Drilling had executed a purchase contract and made a deposit of $1.3 million in June 2014, was complete and available for delivery. However, the Company has not taken delivery of the rig and has notified the seller that until performance issues related to a separate drilling rig of the same model previously purchased by the Company from the seller are resolved, that it does not intend to take delivery of the new rig.

OTHER_INFORMATION_Notes

OTHER INFORMATION (Notes)	12 Months Ended
	Dec. 31, 2014
Other Information
OTHER INFORMATION	NOTE 23 - OTHER INFORMATION
	Quarterly Data (Unaudited)
	Certain prior-year balances have been reclassified to correspond with current-year presentation. As a result of the Company’s decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
	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
		2014
		(in thousands)
	Total revenue (1)	$	113,482		$	138,463		$	79,670		$	59,854		$	391,469
	Operating income (loss) (2)	$	(32,762	)	$	1,555		$	(57,576	)	$	(401,575	)	$	(490,358	)
	Income (loss) from continuing operations (3)	$	(56,557	)	$	(61,407	)	$	(123,189	)	$	103,320		$	(137,833	)
	Income (loss) 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	)
		2013
	Total revenue	$	59,382		$	76,686		$	78,291		$	90,179		$	304,538
	Operating loss (4)	$	(41,437	)	$	(34,412	)	$	(119,874	)	$	(39,070	)	$	(234,793	)
	Loss from continuing operations	$	(61,584	)	$	(3,634	)	$	(152,513	)	$	(14,382	)	$	(232,113	)
	Income (loss) from discontinued operations, net of tax (5)	$	16,884		$	(3,764	)	$	(75,573	)	$	(108	)	$	(62,561	)
	Gain (loss) on disposal of discontinued operations, net of tax (6)	—			172,452			(69,521		)	(31,421		)	71,510
	Net income (loss) attributable to Magnum Hunter Resources Corporation	$	(44,197	)	$	165,440		$	(296,882	)	$	(46,537	)	$	(222,176	)
	Net income (loss) attributable to common shareholders	$	(57,685	)	$	151,311		$	(311,299	)	$	(61,208	)	$	(278,881	)
	Basic and diluted loss from continuing operations per common share	$	(0.44	)	$	(0.10	)	$	(0.98	)	$	(0.17	)	$	(1.69	)
	Basic and diluted income (loss) per common share	$	(0.34	)	$	0.89		$	(1.83	)	$	(0.36	)	$	(1.64	)
	______________
	(1)	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.
	(2)	The quarter-ended June 30, 2014 income from operations 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 Hunter Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipeline’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects.
	(3)	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 Hunter 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 $510 million from the deconsolidation of Eureka Hunter Holdings. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	(4)	The quarter-ended September 30, 2013 loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.
	(5)	The quarter-ended September 30, 2013 loss from discontinued operations was primarily driven by impairment expense of $72.5 million, as management determined a significant portion of the non-core acreage would not be utilized.
	(6)	The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
	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,
		2014				2013				2012
	Purchase of non-producing leases	$	124,411			$	149,592			$	414,037
	Purchase of producing properties	12,246				1,358				159,290
	Exploration costs	9,907				11,531				165,789
	Development costs	321,053				273,944				262,486
	Asset retirement obligation	6,085				2,186				407
		$	473,702			$	438,611			$	1,002,009
	Oil and Gas Reserve Information
	Proved oil and gas reserve quantities are based on estimates prepared by Magnum Hunter’s third party reservoir engineering firms Cawley, Gillespie, & Associates, Inc. in 2014 and 2013, and Cawley, Gillespie, & Associates, Inc. and AJM Deloitte in 2012. 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, 2011		17,124			4,585			139,237
	Revisions of previous estimates		7,936			4,632			25,644
	Purchase of reserves in place		10,613			—			12,082
	Extensions, discoveries, and other additions		3,305			110			544
	Sale of reserves in place		-10			—			-63
	Production		-2,141			-202			-14,824
	Balance December 31, 2012		36,827			9,125			162,620
	Revisions of previous estimates		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
	Extensions, discoveries and other additions		1,705			3,226			132,345
	Revisions of previous estimates		-6,540			2,149			-511
	Sales 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
Developed reserves, included above
December 31, 2012		16,355			6,262			125,526
December 31, 2013		12,085			6,990			176,585
December 31, 2014		6,938			10,587			251,628
Proved undeveloped reserves, included above:
31-Dec-12		20,472			2,863			37,094
31-Dec-13		12,250			3,432			70,197
31-Dec-14		3,583			3,816			101,373
The purchases of reserves in place during the year ended December 31, 2012, includes approximately 2,217 MBoe of proved reserves acquired in the Eagle Operating Assets Acquisition, approximately 8,595 MBoe of proved reserves acquired in the Baytex Energy USA Assets Acquisition, approximately 1,429 MBoe acquired in the Virco acquisition and various smaller acquisitions. 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 3 - 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 our Marcellus Shale and Utica Shale development program which included the wells completed on the Stewart Winland, Stalder, WVDNR 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, 2014, 2013, and 2012 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, 2014, 2013, and 2012 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,
		2014				2013				2012
		(in thousands)
Future cash inflows		$	3,282,768			$	3,711,260			$	4,248,384
Future production costs		(1,443,121		)		(1,423,306		)		(1,520,260		)
Future development costs		(219,509		)		(421,797		)		(603,809		)
Future income tax expense		—				(149,367		)		(230,500		)
Future net cash flows		1,620,138				1,716,790				1,893,815
10% annual discount for estimated timing of cash flows		(710,875		)		(872,280		)		(1,046,162		)
Standardized measure of discounted future net cash flows		$	909,263			$	844,510			$	847,653
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, 2014, as a result of the Company’s net operating loss carryforwards of $710 million 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,
		2014				2013				2012
		(in thousands)
Balance, beginning of period		$	844,510			$	847,653			$	474,396
Net changes in prices and production costs		(281,352		)		(7,355		)		13,647
Changes in estimated future development costs		(57,348		)		(261,591		)		(391,318		)
Sales and transfers of oil and gas produced during the period		(166,611		)		(190,151		)		(179,384		)
Net changes due to extensions, discoveries, and improved recovery		332,684				12,829				60,468
Net changes due to revisions of previous quantity estimates (1)		(55,176		)		341,003				290,500
Previously estimated development costs incurred during the period		269,017				283,736				245,168
Accretion of discount		95,547				90,153				85,377
Purchase of minerals in place		—				218				217,791
Sale of minerals in place		(141,847		)		(236,885		)		(354		)
Changes in timing and other (2)		(7,720		)		(91,088		)		22,436
Net change in income taxes		77,559				55,988				8,926
Standardized measure of discounted future net cash flows		$	909,263			$	844,510			$	847,653
______________
(1)	The Company's net changes due to revisions of previous quantity estimates primarily reflect upward revisions to recoverable quantities of oil and gas minerals assuming existing prices and technology. For the year ended December 31, 2014, the Company made downward revisions of 6,540 MBbl 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. For the year ended December 31, 2012, the Company made upward revisions of 7,936 MBbls of oil, 4,632 MBbl of natural gas liquids and 25,644 MMcf of natural gas.
(2)	The Company's changes in timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. The reserves as of December 31, 2012, reflect accelerated recovery of minerals due to purchases of minerals in place and capital expenditures incurred to develop properties.
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:
		2014				2013				2012
Oil (per Bbl)		$	85.21			$	93.13			$	88.37
Natural gas liquids (per Bbl)		$	50.64			$	43.79			$	53.94
Gas (per Mcf)		$	4.69			$	4.14			$	3.08
In accordance with SEC requirements, the pricing used in our 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 2014 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.

ORGANIZATION_NATURE_OF_OPERATI1

ORGANIZATION, NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014
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. Our 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 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 our wholly-owned subsidiary, Magnum Hunter Production, Inc. (“MHP”), and in various managed drilling partnerships. The Company accounts for the interests in these 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.
	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.
	Non-recurring items subject to significant estimates include the fair value of the Company’s retained financial interest in equity method investees.
	Actual results could differ from the estimates and assumptions utilized.
Non-Controlling Interest in Consolidated Subsidiaries	Non-Controlling Interest in Consolidated Subsidiaries
	For the years ended December 31, 2013 and 2012, the Company consolidated Eureka Hunter Holdings, LLC (“Eureka Hunter Holdings”) in which it owned a 56.4% and 61.0% interest at December 31, 2013 and 2012, respectively. Eureka Hunter Holdings owns, directly or indirectly, 100% of the equity interests of Eureka Hunter Pipeline, LLC (“Eureka Hunter Pipeline”), TransTex Hunter, LLC (“TransTex Hunter”), and Eureka Hunter Land, LLC. Eureka Hunter Pipeline 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 Hunter sells and leases gas treating and processing equipment, much of which is leased to third party operators for treating natural gas at the wellhead.
	Following a series of transactions and capital contributions that occurred up to and including December 18, 2014, the Company no longer holds a controlling financial interest in Eureka Hunter Holdings. Accordingly, the results of operations of Eureka Hunter Holdings have been consolidated in the accompanying consolidated financial statements up to December 18, 2014. The Company held a 48.6% equity interest in Eureka Hunter Holdings at December 18, 2014 and at year-end 2014 and accounts for this retained interest under the equity method of accounting with the Company’s share of Eureka Hunter Holdings’ earnings recorded in “loss from equity method investment” in the accompanying consolidated statements of operations. See “Note 2 - Deconsolidation of Eureka Hunter Holdings” and “Note 10 - Investments and Derivatives”.
	Changes in the non-controlling interests attributable to entities in which the Company holds a controlling financial interest are accounted for as equity transactions, as they are considered investments by owners and distributions to owners acting in their capacity as owners. No gains or losses are recognized as the carrying value of the non-controlling interest is 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 year balances have been reclassified to correspond with the current year presentation. As a result of the Company’s decision in September 2014 to withdraw its plan to divest MHP and to cease all marketing efforts, the results of operations of MHP, which had previously been reported as a component of discontinued operations, have been reclassified to continuing operations for all periods presented, and all assets and liabilities that were previously reported as assets and liabilities held for sale in our consolidated balance sheet have been reclassified to assets and liabilities held for use as of December 31, 2014. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
	The Company has separately classified transportation and processing expenses incurred to deliver gas to processing plants and/or to selling points, which were previously included as components of lease operating expenses and severance taxes and marketing, in the accompanying consolidated statements of operations for all periods presented. The Company has also renamed lease operating expenses as “Production costs” and presented transportation and processing expenses as “Transportation, processing, and other related costs” in order to provide more meaningful information on costs associated with production and development.
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.
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, 2014 and 2013.
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. A sale of an entire field is generally assessed for treatment as a discontinued operation.
	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.
Estimates of Proved Oil and Natural Gas Reserves	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 prices, which may make it uneconomic to drill for and produce from higher-cost fields.
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 our 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.
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, 2014 and 2013, 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.
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.
Lease Operating Expenses	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.
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.
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 our production and are based on volumes.
Gas Gathering and Processing 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.
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.
	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.
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 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.
Commodity and Financial Derivative Instruments	Commodity and Financial Derivative Instruments
	The Company uses 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 has purchased certain investments that contain an embedded derivative. If the 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 the bifurcated derivative in “Gain (loss) on derivative contracts, net”.
Inventory	Inventory
	The Company’s materials and supplies inventory is acquired for use in future well completion and repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and to oilfield services expense in the accompanying consolidated statements of operations. As of December 31, 2014, the Company’s materials and supplies inventory is anticipated to be entirely used within the coming year, and all inventories are classified as current. See “Note 7 - Inventory”.
	The Company’s commodities inventories consist of crude oil held in storage and is carried at the lower of average lifting cost or market, on a first in, first out basis. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to production costs expense in the consolidated statements of operations.
Investments	Investments
	Available for sale investments are comprised of common and preferred stock of companies publicly traded with quoted prices in active markets. Available-for-sale assets are securities and other financial investments that are neither held for trading, nor held to maturity, nor held for strategic reasons, and that have a readily available market price. As such, the gains and losses resulting from marking available-for-sale investments to market are not included in net income but are reflected in other comprehensive income until they are realized. The Company has no investments classified as trading securities or held to maturity securities.
	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 investees 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 Hunter Holdings and determined that impairment was not indicated as of December 31, 2014.
Goodwill and Intangible Assets	Goodwill and Other Intangible Assets
	In accordance with GAAP, goodwill is not amortized to earnings, but is assessed annually for impairment, or whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely. The Company has established April 1 as its annual assessment date, and all goodwill had been allocated to the Company’s midstream segment. If the carrying value of goodwill is determined to be impaired, it is reduced to its implied fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. ASC Topic 350, Intangibles - Goodwill and Other, permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Company used this approach, and performed a qualitative analysis as of April 1, 2014 and determined that no impairment existed.
	As a result of the Company’s loss of its controlling financial interest in Eureka Hunter Holdings, the Company determined an event had occurred which required a reassessment of its goodwill as of December 18, 2014. The Company performed a qualitative assessment of goodwill as of December 18, 2014 and determined that no impairment existed prior to deconsolidation. The Company also performed an analysis to determine the amount of goodwill allocated to the Eureka Hunter Holdings business. As a result, all goodwill and intangible assets were derecognized as part of the gain on deconsolidation. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	Intangible assets consisted primarily of acquired gas treating agreements and customer relationships of Eureka Hunter Holdings.  Such assets were being amortized over the estimated useful lives, which ranged from 2 to 13 years, up to December 18, 2014, when they were 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.
Asset Retirement Obligation	Asset Retirement Obligation
	The asset retirement obligation (“ARO”) primarily represents 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.
	The 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.
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 our stock price, and the assessment of whether the achievement of performance criteria is probable.
Income Taxes	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, 2014 or 2013.
	We apply 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 we meet 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. 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	Other Comprehensive Income (Loss)
	The functional currency of the Company's operations in Canada is the Canadian dollar. 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.
Regulated Activities	Regulated Activities
	Energy Hunter Securities, Inc. (“Energy Hunter Securities”) is a 100%-owned subsidiary and was a registered broker-dealer and member of the Financial Industry Regulatory Authority (“FINRA”) at December 31, 2013. Among other regulatory requirements, it was subject to the net capital provisions of Rule 15c3-1 under the Securities Exchange Act of 1934, as amended. Because it did not hold customer funds or securities or owe money or securities to customers, Energy Hunter Securities was required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness.
	On September 26, 2014, Energy Hunter Securities filed a Uniform Request for Withdrawal From Broker-Dealer Registration with the Securities and Exchange Commission (“SEC”). As of December 31, 2014, Energy Hunter Securities’ had fulfilled all requests from FINRA and its broker-dealer registration has been terminated.
	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 April 2014, the FASB issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 updates the requirements for reporting discontinued operations in ASC Subtopic 205-20, Presentation of Financial Statements - Discontinued Operations, by requiring classification as discontinued operations of a component of an entity or a group of components of an entity if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when either 1) the component or group of components of an entity meet the criteria to be classified as held for sale, 2) are disposed of by sale, or 3) are disposed of other than by sale (e.g. abandonment or a distribution to owners in a spinoff). The amendments in this update expand the disclosure requirements related to discontinued operations and disposals of individually significant components that do not qualify for discontinued operations presentation in the financial statements. This ASU is effective prospectively for all disposals (or classification as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the ASC. The core principle of the revised standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve that core principle, an entity should apply the following steps: identify the contract(s) with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 requires entities to disclose both quantitative and qualitative information that enables users of financial statements to understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. This amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within those reporting periods. The guidance allows for either a “full retrospective” adoption or a “modified retrospective” adoption, however early application is not permitted. The Company is currently evaluating the adoption methods and the impact of this ASU on its consolidated financial statements and financial statement disclosures.
	In June 2014, the FASB issued ASU 2014-12, Compensation - Stock Compensation: Accounting for Share Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 clarifies that a performance target that affects vesting and that could be achieved after the requisite service period should be treated as a performance condition. An entity should apply existing guidance in ASC Topic 718 as it relates to awards with performance conditions that affect vesting to account for such awards. As such, the performance target should not be reflected in estimating the grant-date fair value of the award. This amendment is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
	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 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. 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 is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
	In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging: Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity. This update requires that, for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering the economic characteristics and risks of the entire hybrid financial instrument, including the embedded derivative feature that is being evaluated for separate accounting from the host contract. The effects of initially adopting the amendment should be applied on a modified retrospective basis to existing hybrid financial instruments issued in the form of a share as of the beginning of the fiscal year for which the amendments are effective. This amendment is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements and financial statement disclosures.
	In November 2014, the FASB issued ASU 2014-17, Business Combinations: Pushdown Accounting. ASU 2014-17 provides an acquired entity with the option to apply pushdown accounting in its separate financial statements upon the occurrence of an event in which an acquirer obtains control of the acquired entity. The election to apply pushdown accounting may be made each time there is a change-in-control event. If the acquired entity does not elect to apply pushdown accounting upon a change-in-control event, it can elect to apply pushdown accounting to its most recent change-in-control event in a subsequent reporting period as a change in accounting principle. This amendment is effective as of November 18, 2014. The adoption of this updated standard did not have any impact on the Company’s consolidated financial statements and financial statement disclosures.
Fair Value Measurement, Policy	Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standards also establish a framework for measuring fair value and a valuation hierarchy based upon the transparency of inputs used in the valuation of an asset or liability.  Classification within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The valuation hierarchy contains three levels:
	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.

DECONSOLIDATION_OF_EUREKA_HUNT1

DECONSOLIDATION OF EUREKA HUNTER HOLDINGS (Tables)	12 Months Ended
	Dec. 31, 2014
Noncontrolling Interest [Abstract]
Deconsolidation Of Subsidiary Results Of Operations	Summarized income information for Eureka Hunter Holdings from December 18, 2014 through December 31, 2014 is as follows:
		Fourteen days ended December 31, 2014
		(in thousands)
	Operating revenues	$	2,124
	Operating income	$	74
	Net loss	$	(207	)
	Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014	$	(101	)
Deconsolidation Of Subsidiary Assets And Liabilities	Summarized balance sheet information for Eureka Hunter Holdings as of December 31, 2014 is as follows:
		31-Dec-14
		(in thousands)
	Current assets	$	17,113
	Non-current assets	$	445,450
	Current liabilities	$	63,313
	Non-current liabilities	$	100,037
Deconsolidation Of Subsidiary Stockholders Equity	The following table reconciles the carrying value of the Company’s equity method investment in Eureka Hunter Holdings to the net assets of Eureka Hunter Holdings.
		31-Dec-14
		(in thousands)
	Net Assets of Eureka Hunter Holdings attributable to Magnum Hunter, at December 18, 2014	$	145,418
	Basis difference	201,874
	Loss from equity method investment Eureka Hunter Holdings for the period from December 18, 2014 to December 31, 2014	(101		)
	Magnum Hunter’s investment in Eureka Hunter Holdings	$	347,191

ACQUISITIONS_DIVESTITURES_AND_1

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Summary of revenue and operating income (loss) from the acquisitions	The following summarizes the revenue and operating income (loss) from the acquisitions included in the Company's consolidated statements of operations for the years ended December 31, 2014, 2013, and 2012 (TransTex revenues and operating loss were included through December 18, 2014, the date of deconsolidation of Eureka Hunter Holdings):
		For the year ended December 31,
		2014							2013						2012
		Revenues				Operating Income (loss)			Revenues			Operating Income (loss)			Revenues		Operating Income (loss)
		(in thousands)
	Eagle Operating assets	$	2			$	938		$	7,331		$	(26,867	)	$	5,500	$	(3,019	)
	TransTex assets	$	9,729			$	(2,995	)	$	12,765		$	(812	)	$	7,014	$	(393	)
	Baytex Energy USA assets	$	102,146			$	(352,151	)	$	100,572		$	(101,627	)	$	18,430	$	(6,649	)
	VIRCO acquisition	$	3,194			$	(7,936	)	$	4,453		$	(177	)	$	1,094	$	450
Schedule of pro forma information	The following unaudited summary, prepared on a pro forma basis, presents the results of operations for the year ended December 31, 2012, as if the above acquisitions along with transactions necessary to finance the acquisitions, had occurred as of the beginning of 2011. The pro forma information includes the effects of adjustments for interest expense, depreciation and depletion expense, and dividend expense. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of 2011, nor are they necessarily indicative of future consolidated results.
		Pro Forma
		For the Year Ended December 31,
			2012
		(in thousands except for per share amount, unaudited)
	Oil and natural gas sales		$	159,085
	Operating loss		$	(108,177	)
	Net loss		$	(150,777	)
	Net loss attributable to Magnum Hunter Resources Corporation		$	(146,764	)
	Net loss attributable to common shareholders		$	(188,736	)
	Loss per common share, basic and diluted		$	(1.21	)
Schedule of Assets and Liabilities Held for Sale [Table Text Block]	The following shows the Company’s assets and liabilities held for sale at December 31, 2013:
		31-Dec-13
		(in thousands)
	Accounts receivable	$	4,362
	Other current assets	1,004
	Oil and natural gas properties, net	150,770
	Gas transportation, gathering, and processing equipment and other, net	11,721
	Other long-term assets	196
	Total assets held for sale	$	168,053
	Accounts payable	$	7,292
	Accrued liabilities and other liabilities	5,573
	Asset retirement obligations	8,678
	Other long-term liabilities	5,845
	Total liabilities held for sale	$	27,388
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]	The Company included the results of operations of WHI Canada, which has historically been the only member of our Canadian Upstream segment, through May 12, 2014, Eagle Ford Hunter, which has historically been included as part of the U.S. Upstream segment, through April 24, 2013, and Hunter Disposal, which has historically been included as part of the Oilfield Services segment, through February 17, 2012 in discontinued operations as follows:
		Year Ended December 31,
		2014				2013			2012
		(in thousands)
	Revenues	$	8,533			$	67,490		$	114,068
	Expenses (1)	(3,975		)		(130,331		)	(122,099		)
	Other income (expense)	3				186			(94		)
	Income (loss) from discontinued operations before tax	4,561				(62,655		)	(8,125		)
	Income tax benefit (expense) (2)	—				94			(1,648		)
	Income (loss) from discontinued operations, net of tax	4,561				(62,561		)	(9,773		)
	Gain (loss) on disposal of discontinued operations, net of taxes (3)(4)	(13,855		)		71,510			2,409
	Income (loss) from discontinued operations, net of tax	$	(9,294	)		$	8,949		$	(7,364	)
	_____________________
	-1	Includes impairment expense of $65.4 million, and $0.3 million for the years ended December 31, 2013 and 2012, respectively, and exploration expense of $0.1 million, $19.9 million, and $36.8 million for the years ended December 31, 2014, 2013, and 2012, 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, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, 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, 2014
Oil and Natural Gas Sales [Abstract]
Schedule of Oil Natural Gas and NGL Revenue	During the years ended December 31, 2014, 2013, and 2012, the Company recognized sales from oil, natural gas, and natural gas liquids (“NGLs”) as follows:
		Year Ended December 31,
		2014		2013		2012
				(in thousands)
	Oil	$	131,109	$	147,798	$	82,225
	Natural gas	91,277		53,821		45,825
	NGLs	46,115		19,080		5,678
	Total oil and natural gas sales	$	268,501	$	220,699	$	133,728

PROPERTY_PLANT_EQUIPMENT_Table

PROPERTY, PLANT, & EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Schedule of Proved Property Impairments	During the years ended December 31, 2014, 2013 and 2012, the Company recorded proved property impairments as follows:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Williston Basin	$	261,270		$	8,498		$	3,631
	Appalachian Basin	6,001			1,151			76
	Western Kentucky	33,811			40,043			67
	South Texas	194			319			65
		$	301,276		$	50,011		$	3,839
Geological Geophysical Costs and Leasehold Abandonments Expense	The following table provides the Company's exploration expense for 2014, 2013 and 2012:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Geological and geophysical	$	1,564		$	1,402		$	2,570
	Leasehold impairments:
	Williston Basin	103,147			89,167			59,214
	Appalachian Basin	9,978			6,773			15,033
	Western Kentucky	3,820			3,047			2,154
	South Texas	—			—			1,404
		$	118,509		$	100,389		$	80,375
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,
		2014			2013
		(in thousands)
	Mineral interests in properties:
	Unproved leasehold costs	$	481,643		$	469,337
	Proved leasehold costs	257,185			336,357
	Wells and related equipment and facilities	560,060			438,275
	Uncompleted wells, equipment and facilities	46,346			97,748
	Advances to operators for wells in progress	1,411			13,571
	Total costs	1,346,645			1,355,288
	Less accumulated depreciation, depletion, and amortization	(248,410		)	(130,629		)
	Net capitalized costs	$	1,098,235		$	1,224,659
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, 2014 and 2013, is summarized as follows:
		December 31,
		2014			2013
		(in thousands)
	Gas transportation, gathering and processing equipment and other	$	100,436		$	315,642
	Less accumulated depreciation and depletion	(23,013		)	(26,222		)
	Net capitalized costs	$	77,423		$	289,420

INTANGIBLE_ASSETS_Tables

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Changes in Intangible Assets	The following table summarizes the Company's net intangible assets during the year ended December 31, 2013:
		December 31,
		2013
		(in thousands)
	Customer relationships	$	5,434
	Trademark	859
	Existing contracts	4,199
	Total intangible assets	10,492
	Accumulated amortization:
	Customer relationships	(1,248		)
	Trademark	(137		)
	Existing contracts	(2,577		)
	Intangible assets, net of accumulated amortization	$	6,530

INVENTORY_Tables

INVENTORY (Tables)	12 Months Ended
	Dec. 31, 2014
Inventory Disclosure [Abstract]
Schedule of Inventory, Current and Noncurrent	The following table sets forth the composition of the Company's inventory as of December 31, 2014 and December 31, 2013.
		December 31,
		2014		2013
		(in thousands)
	Materials and supplies	$	1,436	$	6,790
	Oil in tanks	832		368
	Inventory	$	2,268	$	7,158

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:
		December 31,
		2014			2013
		(in thousands)
	Asset retirement obligation at beginning of period	$	16,216		$	30,680
	Assumed in acquisition	—			17
	Liabilities incurred	218			253
	Liabilities settled	(107		)	(98		)
	Liabilities sold	(2,598		)	(7,614		)
	Accretion expense	1,478			2,264
	Revisions in estimated liabilities	3,208			1,935
	Reclassified as liabilities associated with assets held for sale	—			(11,148		)
	Reclassified from liabilities associated with assets held for sale	8,109			—
	Correction of prior year error	—			(73		)
	Asset retirement obligation at end of period	26,524			16,216
	Less: current portion	(295		)	(53		)
	Asset retirement obligation at end of period	$	26,229		$	16,163

FAIR_VALUE_OF_FINANCIAL_INSTRU1

FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Table Text Block]	The key inputs used in the Black-Scholes option pricing model were as follows:
		31-Dec-14
	Life	2.1			years
	Risk-free interest rate	0.95			%
	Estimated volatility	91			%
	Dividend	—
	GreenHunter Resources Stock price at end of period	$	0.71
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, 2014, 2013 and 2012:
		Embedded Derivatives
		Series A Preferred Units				Convertible Security
		(in thousands)
	Fair value at December 31, 2011	$	—			$	—
	Issuance of embedded derivative (liability) asset	(52,240		)		405
	Decrease in fair value recognized in gain on derivative contracts, net	8,692				(141		)
	Fair value at December 31, 2012	$	(43,548	)		$	264
	Issuance of embedded liability	(14,645		)		—
	Increase 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		)		—
	Increase in fair value recognized in loss on derivative contracts, net	(91,792		)		(4		)
	Conversion of Eureka Hunter Holdings Series A Preferred Units to Series A-2 Units	173,205				—
	Fair value as of December 31, 2014	$	—			$	75
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, 2014 and 2013:
		Fair Value Measurements on a Recurring Basis
		31-Dec-14
		(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
		Fair Value Measurements on a Recurring Basis
		31-Dec-13
		(in thousands)
		Level 1				Level 2				Level 3
	Available for sale securities	$	1,819			$	—			$	—
	Commodity derivative assets	—				554				—
	Convertible security derivative assets	—				—				79
	Total assets at fair value	$	1,819			$	554			$	79
	Commodity derivative liabilities	$	—			$	2,279			$	—
	Convertible preferred stock derivative liabilities	—				—				75,934
	Total liabilities at fair value	$	—			$	2,279			$	75,934
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		31-Dec-14								31-Dec-13
			Hierarchy Level		Carrying Amount				Estimated Fair Value				Carrying Amount		Estimated Fair Value
					(in thousands)
	Senior Notes		Level 2		$	597,355			$	498,000			$	597,230	$	651,300
	MHR Senior Revolving Credit Facility		Level 3		—				—				218,000		218,000
	MHR Second Lien Term Loan		Level 3		329,140				329,140				—		—
	Eureka Hunter Pipeline term loan		Level 3		—				—				50,000		58,291
	Equipment notes payable		Level 3		22,238				22,150				18,615		17,676
Fair value measurements on a non-recurring basis	Other fair value measurements made on a non-recurring basis during the years ended December 31, 2014, 2013, and 2012 consist of the following:
	Fair Value Measurements on a Non-recurring Basis
			(Level 1)				(Level 2)				(Level 3)
	Year ended December 31, 2014		(in thousands)
	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 Hunter Holdings		—				—				347,291
	Year ended December 31, 2013
	Fair value of proved properties impaired		$	—			$	—			$	329,409
	Fair value of long-lived assets of MHP		—				—				87,149
	Year ended December 31, 2012
	Fair value of proved properties impaired		$	—			$	—			$	372,450
	Fair value of acquisitions		—				—				532,150

INVESTMENTS_AND_DERIVATIVES_Ta

INVESTMENTS AND DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Investment	Below is a summary of changes in investments for the years ended December 31, 2014 and 2013:
		Available for Sale Securities (1)				Equity Method Investments
		(in thousands)
	Carrying value at December 31, 2011	$	497			$	—
	Additional cost basis from acquisition	—				4,043
	Transfers from cost method investments	1,770				—
	Loss from equity method investment, including impairment of carrying value	—				(1,971		)
	Change in fair value recognized in other comprehensive loss	(309		)		—
	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				—
	Equity in net loss recognized in other income (expense)	—				—
	Fair value of retained interest in Eureka Hunter 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 as of December 31, 2014	$	3,864			$	347,191
	(1) Available for sale securities above includes $147,000 that has been classified as held for sale associated with MHP
	as of December 31, 2013.
Schedule of Investments by Balance Sheet Grouping	The Company's investments have been presented in the consolidated balance sheet as of December 31, 2014 and December 31, 2013 as follows:
		31-Dec-14
		(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
		31-Dec-13
		(in thousands)
		Available for Sale Securities				Equity Method Investments			Total
	Investments - Current	$	1,672			$	590		$	2,262
	Investments - Non-current	—				350			350
	Investments - Held for Sale	147				—			147
	Carrying value as of December 31, 2013	$	1,819			$	940		$	2,759
Schedule of commondity derivatives	The table below is a summary of the Company's commodity derivatives as of December 31, 2014:
					Weighted Avg
	Natural Gas	Period	MMBtu/d		Price per MMBtu
	Swaps	Jan 2015 - Dec 2015	40,000		$4.09
					Weighted Avg
	Crude Oil	Period	Bbl/d		Price per Bbl
	Collars (1)	Jan 2015 - Dec 2015	259		$85.00 - $91.25
	Ceilings sold (call)	Jan 2015 - Dec 2015	1,570		$120.00
	Floors sold (put)	Jan 2015 - Dec 2015	259		$70.00
	________________________________
	(1) A collar is a sold call and a purchased put. Some collars are “costless” collars with the premiums netting to approximately zero.
Schedule of fair value of derivative contracts	The following table summarizes the fair value of the Company's derivative contracts as of the dates indicated:
		Derivatives not designated as hedging instruments
		Derivative Assets							Derivative Liabilities
		December 31,							December 31,
		2014				2013			2014		2013
	Commodity	(in thousands)
	Derivative assets	$	16,511			$	529		$	—	$	—
	Derivatives assets, long term	—				25			—		—
	Derivative liabilities	—				—			—		(1,903		)
	Derivative liabilities, long term	—				—			—		(376		)
	Total commodity	$	16,511			$	554		$	—	$	(2,279	)
	Financial
	Derivative assets	$	75			$	79		$	—	$	—
	Derivative liabilities, long term	—				—			—		(75,934		)
	Total financial	$	75			$	79		$	—	$	(75,934	)
	Total derivatives	$	16,586			$	633		$	—	$	(78,213	)
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, 2014, 2013 and 2012:
		For the Year Ended December 31,
		2014				2013			2012
		(in thousands)
	Gain (loss) on settled transactions	$	1,306			$	(8,216	)	$	11,294
	Gain (loss) on open contracts	18,232				(17,058		)	10,945
	Loss on extinguished embedded derivative	(91,792		)		—			—
	Total gain (loss), net	$	(72,254	)		$	(25,274	)	$	22,239

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Details of notes payable	Notes payable at December 31, 2014 and 2013 consisted of the following:
		As of December 31,
		2014			2013
		(in thousands)
	Senior Notes Payable due May 15, 2020, interest rate of 9.75%, net of unamortized discount of $2.6 million and $2.8 million at December 31, 2014 and 2013, respectively	$	597,355		$	597,230
	Various equipment and real estate notes payable with maturity dates February 2015 - November 2017, interest rates of 4.25% - 7.94% (1)	22,238			18,615
	Eureka Hunter Pipeline Credit Agreement due March 28, 2018, interest rate of 3.66% (2)	—			—
	Eureka Hunter Pipeline second lien term loan due August 16, 2018, interest rate of 12.5%	—			50,000
	MHR Senior Revolving Credit Facility due April 13, 2018, interest rate of 2.92% at December 31, 2014	—			218,000
	MHR 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	329,140			—
		$	948,733		$	883,845
	Less: current portion	(10,770		)	(3,967		)
	Total long-term debt obligations, net of current portion	$	937,963		$	879,878
	_________________
	(1) Balance as of December 31, 2013 includes notes classified as liabilities associated with assets held for sale of which $0.2 million is current and $3.8 million is long term.
	(2)	As a result of the deconsolidation of Eureka Hunter Holdings, this loan or revolver was derecognized with Eureka Hunter Holdings’ other liabilities. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”
Summary of approximate annual maturities of debt	The following table presents the approximate annual maturities of debt, gross of unamortized discount:
		(in thousands)
	2015	$	10,770
	2016	12,129
	2017	5,948
	2018	3,959
	2019	325,757
	Thereafter	602,825
		$	961,388
Schedule of Interest Expense Incurred on Debt [Table Text Block]	The following table sets forth interest expense for the years ended December 31, 2014, 2013 and 2012:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Interest expense incurred on debt, net of amounts capitalized	$	76,784		$	67,803		$	44,447
	Amortization and write-off of deferred financing costs	9,679			4,818			7,399
	Total interest expense	$	86,463		$	72,621		$	51,846

SHAREBASED_COMPENSATION_Tables

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013, and 2012 is presented below:
		2014					2013				2012
				Weighted-Average Exercise Price					Weighted-Average Exercise Price				Weighted-Average Exercise Price
		Shares					Shares				Shares
	Outstanding at beginning of the year	16,891,419		$	5.69		14,846,994		$	6.01	12,566,199		$	5.64
	Granted	—		$	—		4,937,575		$	4.11	4,978,750		$	6
	Exercised	(2,375,273	)	$	4.09		(1,466,025	)	$	3.66	(1,304,050	)	$	1.54
	Forfeited or expired	(1,321,190	)	$	6.27		(1,427,125	)	$	5.51	(1,393,905	)	$	7.14
	Outstanding at end of the year	13,194,956		$	5.91		16,891,419		$	5.69	14,846,994		$	6.01
	Exercisable at end of the year	9,140,323		$	6.22		9,983,743		$	5.96	8,683,622		$	5.97
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, 2014, 2013, and 2012 is presented below:
	Non-vested Options	2014		2013		2012
	Non-vested at beginning of the year	6,907,476		6,163,372		5,650,782
	Granted	—		4,937,575		4,978,750
	Vested	(1,915,526	)	(3,133,700	)	(3,405,434	)
	Forfeited	(1,018,767	)	(1,059,771	)	(1,060,726	)
	Non-vested at end of the year	3,973,183		6,907,476		6,163,372
Assumptions used in fair value method calculation	The assumptions used in the fair value method calculations for the years ended 2013 and 2012 are disclosed in the following table:
			Year Ended December 31,
			2013	2012
	Weighted average fair value per option granted during the period (1)		$2.52	$3.72
	Assumptions (2) :
	Weighted average stock price volatility (3)		80.61%	82.64%
	Weighted average risk free rate of return		0.78%	0.77%
	Weighted average estimated forfeiture rate (4)		2.45%	—%
	Weighted average expected term		4.65 years	4.51 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.
	(4)	For the year 2012, the Company estimated forfeitures to be zero based on the majority of options being granted to executive officers who are less likely to forfeit shares.
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, 2014, 2013, and 2012 is presented below:
		2014					2013				2012
				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	27,500		$	7.24		65,025		$	6.09	155,049		$	4.43
	Granted	3,239,796		$	5.66		210,494		$	4.66	69,791		$	4.29
	Forfeited	(170,000	)	$	7.26		—		$	—	—		$	—
	Vested	(780,283	)	$	4.48		(248,019	)	$	4.75	(159,815	)	$	4.46
	Non-vested at end of the year	2,317,013		$	5.97		27,500		$	7.24	65,025		$	6.09

SHAREHOLDERS_EQUITY_Tables

SHAREHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Summary of warrant activity	A summary of warrant activity for the years ended December 31, 2014, 2013, and 2012 is presented below:
		2014						2013				2012
				Weighted -						Weighted -				Weighted -
				Average						Average				Average
		Shares		Exercise Price				Shares		Exercise Price		Shares		Exercise Price
	Outstanding at beginning of year	17,169,010		$	8.56			13,376,277		$	10.56	13,525,832		$	10.48
	Granted	2,142,858		$	8.5			17,030,622		$	8.5	—		$	—
	Exercised, forfeited, or expired	(138,388	)	$	16.28			(13,237,889	)	$	10.5	(149,555	)	$	3.32
	Outstanding at end of year	19,173,480		$	8.5			17,169,010		$	8.56	13,376,277		$	10.56
	Exercisable at end of year	19,173,480		$	8.5			17,169,010		$	8.56	13,376,277		$	10.56
Summary of dividends paid	A summary of dividends incurred by the Company for the years ended December 31, 2014, 2013, and 2012 is presented below:
		Year Ended December 31,
		2014				2013				2012
		(in thousands)
	Dividend on Eureka Hunter Holdings Series A Preferred Units	$	12,760			$	14,323			$	8,090
	Accretion of the carrying value of the Eureka Hunter Holdings Series A Preferred Units	6,583				6,918				3,775
	Dividend on Series C Preferred Stock	10,248				10,248				10,248
	Dividend on Series D Preferred Stock	17,698				17,655				11,699
	Dividend on Series E Preferred Stock	7,418				7,561				894
	Total dividends on Preferred Stock	$	54,707			$	56,705			$	34,706
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, 2014, 2013 and 2012:
		December 31,
		2014			2013			2012
		(in thousands of shares)
	Series E Preferred Stock	10,946			10,946			10,897
	Warrants	19,173			17,169			13,376
	Restricted shares granted, not yet issued	2,369			28			—
	Common stock options	13,195			16,891			14,847
	Total	45,683			45,034			39,120

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013			2012
		(in thousands)
	Deferred income tax benefit
	Federal	$	—		$	(78,743	)	$	(24,584	)
	State	—			(6,664		)	(81		)
	Total deferred tax benefit	$	—		$	(85,407	)	$	(24,665	)
	Total income tax benefit	$	—		$	(85,407	)	$	(24,665	)
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, 2014, 2013, and 2012 to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Income tax benefit at statutory U.S. rate	$	(48,242	)	$	(111,132	)	$	(53,908	)
	State income taxes (net of federal benefit)	(3,616		)	(4,331		)	(53		)
	Tax effect of permanent differences	(498		)	750			(555		)
	Provision to return adjustment	(11,736		)	—			—
	Foreign statutory tax rate differences	297			—			—
	Tax effect of loss attributable to non-controlled interest	1,279			346			797
	Tax benefit recognized as tax expense in discontinued operations	—			(28,989		)	—
	Change in valuation allowance	63,341			58,341			29,047
	Other	(825		)	(392		)	7
	Total continuing operations	—			(85,407		)	(24,665		)
	Discontinued operations	—			11,773			3,071
	Total tax benefit	$	—		$	(73,634	)	$	(21,594	)
Schedule of Income before Income Tax, Domestic and Foreign [Table Text Block]	Income (loss) before income taxes was as follows:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Domestic	$	(134,853	)	$	(317,520	)	$	(154,022	)
	Foreign	(2,980		)	—			—
	Loss from continuing operations	(137,833		)	(317,520		)	(154,022		)
	Gain (loss) from discontinued operations	4,561			(62,655		)	(8,125		)
	Gain (loss) on disposal of discontinued operations	(13,855		)	83,378			3,830
	Loss before income tax	$	(147,127	)	$	(296,797	)	$	(158,317	)
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,
		2014			2013			2012
		(in thousands)
	Deferred tax assets:
	Net operating loss carry forwards	$	263,452		$	155,507		$	193,310
	Property and equipment	63,823			—			—
	Capital loss carry forward	38,401			—			—
	Share-based compensation	15,035			10,156			7,950
	Depletion carry forwards	1,047			1,047			997
	Tax credits	53			53			53
	US investment in Canada	—			74,148			—
	Other	1,562			561			532
	Deferred tax liabilities:
	Property and equipment	—			(90,950		)	(206,650		)
	Investment in Eureka Hunter Holdings	(176,606		)	—			—
	Valuation allowance
	Tax credits	(53		)	(53		)	(53		)
	Depletion carry forwards	(1,047		)	(1,047		)	(997		)
	Capital loss carry forward	(38,401		)	—			—
	Net operating losses	(167,266		)	(75,274		)	(69,400		)
	US investment in Canada	—			(74,148		)	—
	Net deferred tax asset (liability)	$	—		$	—		$	(74,258	)
Reconciliation of unrecognized tax benefits	Following is a reconciliation of the total amounts of unrecognized tax benefits during the years ended December 31, 2014, 2013 and 2012:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Unrecognized tax benefits at January 1	$	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)	—			—			3,879
	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, 2014
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,
		2014		2013		2012
	Samson Resources Company	24	%	31	%	17	%
	Teneska Marketing Ventures	17	%	10	%	14	%
	Markwest Liberty Midstream	15	%	6	%	—
	Baytex Energy USA LTD	7	%	11	%	15	%
	Continuum Midstream, LLC	5	%	6	%	13	%
	South Jersey	2	%	5	%	14	%
	Plains Marketing, LP	—		4	%	11	%

RELATED_PARTY_TRANSACTIONS_Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	The following table sets forth the related party balances as of December 31, 2014 and 2013:
		As of December 31,
		2014				2013
		(in thousands)
	GreenHunter (1)
	Accounts receivable (payable) - net	$	(228	)		$	23
	Derivative assets (2)	$	75			$	79
	Investments (2)	$	1,311			$	2,262
	Notes receivable (2)	$	1,224			$	1,768
	Prepaid expenses	$	1,000			$	9
	Eureka Hunter Holdings (3)
	Accounts receivable (payable) - net	$	122			$	—
	Equity method investment	$	347,191			$	—
	Pilatus Hunter
	Accounts receivable (payable) - net	$	12			$	—
	The following table sets forth the related party transaction activities for the years ended December 31, 2014, 2013 and 2012:
				Years Ended
				December 31,
				2014				2013		2012
				(in thousands)
	GreenHunter
		Salt water disposal (1)		$	4,682			$	3,033	$	2,400
		Equipment rental (1)		291				282		1,000
		Gas gathering-trucking (1)		652				—		—
		MAG tank panels (1)		800				—		—
		Office space rental		44				13		—
		Interest income from note receivable (2)		154				205		191
		Dividends earned from Series C shares (2)		220				220		—
		Unrealized loss on investments (2)		951				730		1,333
	Pilatus Hunter, LLC
		Airplane rental expenses (4)		281				166		174
	Executive of the Company
		Corporate apartment rental expense (5)		—				—		23
	Eureka Hunter (3)
		Transportation costs		353				—		—
	_________________________________
	(1)	GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and Virco., wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.
	(2)	On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water, 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 other long-term assets and an available for sale investment in GreenHunter included in investments.
	(3)	Following a sequence of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. The Company deconsolidated Eureka Hunter Holdings and accounts for its retained interest as of December 31, 2014 under the equity method of accounting. See “Note 2 - Deconsolidation of Eureka Hunter 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)	During the year ended December 31, 2012, the Company paid rent under a lease for a Houston, Texas corporate apartment from an executive of the Company, which apartment was used by other Company employees when in Houston for Company business.  The lease terminated in May 2012.

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, are as follows (in thousands):
	2015	$	502
	2016	$	239
	2017	$	121
	2018	$	124
	2019	$	53
	Thereafter	$	—
Schedule of future minimum gathering, processing, and transportation commitments	Future minimum gathering, processing, and transportation commitments at December 31, 2014, are as follows (in thousands):
	2015	$	11,567
	2016	$	11,591
	2017	$	11,567
	2018	$	11,567
	2019	$	11,567
	Thereafter	$	62,655

SUPPLEMENTAL_CASH_FLOW_INFORMA1

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	The following summarizes cash paid (received) for interest and income taxes, as well as non-cash investing transactions:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Cash paid for interest	$	73,192		$	67,736		$	35,669
	Cash paid for taxes	$	—		$	1,200		$	—
	Non-cash transactions
	Change in accrued capital expenditures - increase (decrease)	$	127,068		$	(65,634	)	$	34,621
	Eureka Hunter Holdings, LLC Series A convertible preferred unit dividends paid in kind	$	1,950		$	8,243		$	1,658
	Non-cash additions to asset retirement obligation	$	3,426		$	2,132		$	8,492
	Common stock issued for 401k matching contributions	$	1,593		$	1,192		$	874
	Preferred stock issued for acquisitions	$	—		$	—		$	64,968
	Eureka Hunter Holdings, LLC Class A common units issued for an acquisition	$	—		$	—		$	12,453
	Non-cash consideration received from sale of assets	$	9,447		$	42,300		$	7,120
	Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units	$	(51,692	)	$	—		$	—
	Common stock issued for acquisitions	$	—		$	—		$	1,902

SEGMENT_REPORTING_Tables

SEGMENT REPORTING (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013, and 2012.
		For the Year Ended December 31, 2014
		U.S. Upstream			Canadian Upstream			Midstream and Marketing (1)			Oil Field Services			Corporate Unallocated(2)			Intersegment Eliminations			Total
		(in thousands)
	Total revenue	$	270,615		$	—		$	109,658		$	31,392		$	—		$	(20,196	)	$	391,469
	Depreciation, depletion, and accretion	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	(7,155		)	10,636			—			—			(12,775		)	—			(9,294		)
	Net income (loss)	$	(416,817	)	$	10,636		$	(98,426	)	$	782		$	360,400		$	(3,702	)	$	(147,127	)
	Total assets	$	1,162,732		$	—		$	454		$	46,995		$	462,025		$	(2,377	)	$	1,669,829
	Total capital expenditures	$	470,538		$	305		$	221,455		$	8,079		$	231		$	—		$	700,608
		For the Year Ended December 31, 2013
		U.S. Upstream			Canadian Upstream			Midstream and Marketing (1)			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
		(in thousands)
	Total revenue	$	225,498		$	—		$	69,306		$	21,527		$	—		$	(11,793	)	$	304,538
	Depreciation, depletion, and accretion	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	159,225			(150,207		)	—			—			—			(69		)	8,949
	Net income (loss)	$	35,208		$	(150,207	)	$	(25,875	)	$	(590	)	$	(81,698	)	$	(2	)	$	(223,164	)
	Total assets	$	1,373,041		$	68,367		$	296,739		$	44,193		$	77,684		$	(3,373	)	$	1,856,651
	Total capital expenditures (3)	$	444,385		$	15,352		$	87,498		$	22,440		$	1,037		$	—		$	570,712
		For the Year Ended December 31, 2012
		U.S. Upstream			Canadian Upstream			Midstream and Marketing (1)			Oil Field Services			Corporate Unallocated			Intersegment Eliminations			Total
		(in thousands)
	Total revenue	$	134,339		$	—		$	15,692		$	13,552		$	—		$	(3,646	)	$	159,937
	Depreciation, depletion, and accretion	65,040			—			5,963			967			—			468			72,438
	Loss (gain) on sale of assets	246			—			(250		)	600			—			—			596
	Other operating expenses	167,423			—			11,706			10,838			27,137			(3,541		)	213,563
	Other income (expense)	(10,210		)	—			7,388			(482		)	(24,121		)	63			(27,362		)
	Income (loss) from continuing operations before income tax	(108,580		)	—			5,661			665			(51,258		)	(510		)	(154,022		)
	Income tax benefit	24,665			—			—			—			—			—			24,665
	Total income (loss) from discontinued operations, net of tax	18,856			(25,021		)	—			145			—			(1,344		)	(7,364		)
	Net income (loss)	$	(65,059	)	$	(25,021	)	$	5,661		$	810		$	(51,258	)	$	(1,854	)	$	(136,721	)
	Total assets	$	1,602,022		$	392,918		$	245,207		$	23,810		$	93,612		$	(158,937	)	$	2,198,632
	Total capital expenditures (3)	$	927,456		$	86,612		$	84,348		$	11,657		$	785		$	—		$	1,110,858
	______________
	(1)	Includes operations of Eureka Hunter Holdings, which represents approximately 38.6%, 40.7%, and 71.6% of Midstream and Marketing revenues for the years ended December 31, 2014, 2013, and 2012, respectively, and which was deconsolidated as of December 18, 2014. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	(2)	Includes the Company’s retained interest in Eureka Hunter Holdings which has a value of $347 million at December 31, 2014.
	(3)	Presentation of capital expenditures has been changed from prior year presentation in order to reflect capital expenditures incurred rather than cash paid for capital expenditures.

CONDENSED_CONSOLIDATED_GUARANT1

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS (Tables) (Debt Securities Under Universal Shelf Registration Statement Form S-4)	12 Months Ended
	Dec. 31, 2014
Debt Securities Under Universal Shelf Registration Statement Form S-4
CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS
Schedule of condensed consolidating balance sheets	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Balance Sheets
	(in thousands)
			As of December 31, 2014
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	ASSETS
	Current assets		$	85,647			$	36,338			$	589			$	(2,378	)		$	120,196
	Intercompany accounts receivable		1,113,417				—				—				(1,113,417		)		—
	Property and equipment (using successful efforts accounting)		5,506				1,170,122				30				—				1,175,658
	Investment in subsidiaries		(91,595		)		94,134				—				(2,539		)		—
	Investment in affiliate, equity-method		347,191				—				—				—				347,191
	Other assets		22,804				3,980				—				—				26,784
	Total Assets		$	1,482,970			$	1,304,574			$	619			$	(1,118,334	)		$	1,669,829
	LIABILITIES AND SHAREHOLDERS' EQUITY
	Current liabilities		$	25,347			$	142,914			$	2,567			$	(2,383	)		$	168,445
	Intercompany accounts payable		—				1,073,091				42,560				(1,115,651		)		—
	Long-term liabilities		925,767				43,762				—				—				969,529
	Redeemable preferred stock		100,000				—				—				—				100,000
	Shareholders' equity (deficit)		431,856				44,807				(44,508		)		(300		)		431,855
	Total Liabilities and Shareholders' Equity		$	1,482,970			$	1,304,574			$	619			$	(1,118,334	)		$	1,669,829
	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Balance Sheets
	(in thousands)
			As of December 31, 2013
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	ASSETS
	Current assets		$	53,161			$	43,841			$	27,096			$	(3,372	)		$	120,726
	Intercompany accounts receivable		965,138				—				—				(965,138		)		—
	Property and equipment (using successful efforts accounting)		7,214				1,272,027				234,838				—				1,514,079
	Investment in subsidiaries		372,236				102,314				—				(474,550		)		—
	Other assets		17,308				100,894				103,644				—				221,846
	Total Assets		$	1,415,057			$	1,519,076			$	365,578			$	(1,443,060	)		$	1,856,651
	LIABILITIES AND SHAREHOLDERS' EQUITY
	Current liabilities		$	54,826			$	97,520			$	34,929			$	(3,410	)		$	183,865
	Intercompany accounts payable		—				921,237				43,866				(965,103		)		—
	Long-term liabilities		818,651				39,067				127,663				—				985,381
	Redeemable preferred stock		100,000				—				136,675				—				236,675
	Shareholders' equity (deficit)		441,580				461,252				22,445				(474,547		)		450,730
	Total Liabilities and Shareholders' Equity		$	1,415,057			$	1,519,076			$	365,578			$	(1,443,060	)		$	1,856,651
Schedule of condensed consolidating statements of operations	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Statements of Operations
	(in thousands)
			For the Year Ended December 31, 2014
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	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 loss 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 Hunter Holdings		(51,692		)		—				—				—				(51,692		)
	Net income (loss) attributable to common shareholders		$	(249,875	)		$	(411,902	)		$	(109,810	)		$	521,714			$	(249,873	)
			For the Year Ended December 31, 2013
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	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		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
	Condensed Consolidating Statements of Operations
	(in thousands)
			For the Year Ended December 31, 2012
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	Revenues		$	729			$	141,772			$	21,080			$	(3,644	)		$	159,937
	Expenses		54,047				212,071				32,487				15,354				313,959
	Loss from continuing operations before equity in net income of subsidiaries		(53,318		)		(70,299		)		(11,407		)		(18,998		)		(154,022		)
	Equity in net income of subsidiaries		(102,545		)		458				(23,362		)		125,449				—
	Income (loss) from continuing operations before income tax		(155,863		)		(69,841		)		(34,769		)		106,451				(154,022		)
	Income tax benefit		11,290				13,375				—				—				24,665
	Income (loss) from continuing operations		(144,573		)		(56,466		)		(34,769		)		106,451				(129,357		)
	Loss from discontinued operations, net of tax		—				(209		)		(9,564		)		—				(9,773		)
	Gain on disposal of discontinued operations, net of tax		—				2,409				—				—				2,409
	Net income (loss)		(144,573		)		(54,266		)		(44,333		)		106,451				(136,721		)
	Net income attributable to non-controlling interest		—				—				—				4,013				4,013
	Net income (loss) attributable to Magnum Hunter Resources Corporation		(144,573		)		(54,266		)		(44,333		)		110,464				(132,708		)
	Dividends on preferred stock		(22,842		)		—				(11,864		)		—				(34,706		)
	Net income (loss) attributable to common shareholders		$	(167,415	)		$	(54,266	)		$	(56,197	)		$	110,464			$	(167,414	)
Schedule of condensed consolidating statements of comprehensive income (loss)	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Statements of Comprehensive Income (Loss)
	(in thousands)
		For the Year Ended December 31, 2014
		Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
	Net income (loss)	$	(162,819	)		$	(411,902	)		$	(90,467	)		$	518,061			$	(147,127	)
	Foreign currency translation loss	—				—				(1,204		)		—				(1,204		)
	Unrealized gain (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
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
	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	)
		For the Year Ended December 31, 2012
		Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
		Resources				Subsidiaries				Subsidiaries								Resources
		Corporation																Corporation
																		Consolidated
	Net income (loss)	$	(144,573	)		$	(54,266	)		$	(44,333	)		$	106,451			$	(136,721	)
	Foreign currency translation loss	—				—				3,883				—				3,883
	Unrealized gain (loss) on available for sale securities	—				(309		)		—				—				(309		)
	Comprehensive income (loss)	(144,573		)		(54,575		)		(40,450		)		106,451				(133,147		)
	Comprehensive (income) loss attributable to non-controlling interest	—				—				—				4,013				4,013
	Comprehensive income (loss) attributable to Magnum Hunter Resources Corporation	$	(144,573	)		$	(54,575	)		$	(40,450	)		$	110,464			$	(129,134	)
Schedule of condensed consolidating statements of cash flows	Magnum Hunter Resources Corporation and Subsidiaries
	Condensed Consolidating Statements of Cash Flows
	(in thousands)
			For the Year Ended December 31, 2014
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	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				Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	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
			For the Year Ended December 31, 2012
			Magnum Hunter				100% Owned Guarantor				Non-Guarantor				Consolidating / Eliminating Adjustments				Magnum Hunter
			Resources				Subsidiaries				Subsidiaries								Resources
			Corporation																Corporation
																			Consolidated
	Cash flow from operating activities		$	(458,921	)		$	281,782			$	236,360			$	(1,210	)		$	58,011
	Cash flow from investing activities		(364,045		)		(287,204		)		(357,961		)		3				(1,009,207		)
	Cash flow from financing activities		831,080				1,781				162,374				1,207				996,442
	Effect of exchange rate changes on cash		—				—				(2,474		)		—				(2,474		)
	Net increase (decrease) in cash		8,114				(3,641		)		38,299				—				42,772
	Cash at beginning of period		18,758				(546		)		(3,361		)		—				14,851
	Cash at end of period		$	26,872			$	(4,187	)		$	34,938			$	—			$	57,623

OTHER_INFORMATION_Tables

OTHER INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2014
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
		2014
		(in thousands)
	Total revenue (1)	$	113,482		$	138,463		$	79,670		$	59,854		$	391,469
	Operating income (loss) (2)	$	(32,762	)	$	1,555		$	(57,576	)	$	(401,575	)	$	(490,358	)
	Income (loss) from continuing operations (3)	$	(56,557	)	$	(61,407	)	$	(123,189	)	$	103,320		$	(137,833	)
	Income (loss) 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	)
		2013
	Total revenue	$	59,382		$	76,686		$	78,291		$	90,179		$	304,538
	Operating loss (4)	$	(41,437	)	$	(34,412	)	$	(119,874	)	$	(39,070	)	$	(234,793	)
	Loss from continuing operations	$	(61,584	)	$	(3,634	)	$	(152,513	)	$	(14,382	)	$	(232,113	)
	Income (loss) from discontinued operations, net of tax (5)	$	16,884		$	(3,764	)	$	(75,573	)	$	(108	)	$	(62,561	)
	Gain (loss) on disposal of discontinued operations, net of tax (6)	—			172,452			(69,521		)	(31,421		)	71,510
	Net income (loss) attributable to Magnum Hunter Resources Corporation	$	(44,197	)	$	165,440		$	(296,882	)	$	(46,537	)	$	(222,176	)
	Net income (loss) attributable to common shareholders	$	(57,685	)	$	151,311		$	(311,299	)	$	(61,208	)	$	(278,881	)
	Basic and diluted loss from continuing operations per common share	$	(0.44	)	$	(0.10	)	$	(0.98	)	$	(0.17	)	$	(1.69	)
	Basic and diluted income (loss) per common share	$	(0.34	)	$	0.89		$	(1.83	)	$	(0.36	)	$	(1.64	)
	______________
	(1)	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.
	(2)	The quarter-ended June 30, 2014 income from operations 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 Hunter Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipeline’s fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects.
	(3)	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 Hunter 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 $510 million from the deconsolidation of Eureka Hunter Holdings. See “Note 2 - Deconsolidation of Eureka Hunter Holdings”.
	(4)	The quarter-ended September 30, 2013 loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.
	(5)	The quarter-ended September 30, 2013 loss from discontinued operations was primarily driven by impairment expense of $72.5 million, as management determined a significant portion of the non-core acreage would not be utilized.
	(6)	The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See “Note 3 - Acquisitions, Divestitures, and Discontinued Operations”.
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,
		2014				2013				2012
	Purchase of non-producing leases	$	124,411			$	149,592			$	414,037
	Purchase of producing properties	12,246				1,358				159,290
	Exploration costs	9,907				11,531				165,789
	Development costs	321,053				273,944				262,486
	Asset retirement obligation	6,085				2,186				407
		$	473,702			$	438,611			$	1,002,009
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, 2011		17,124			4,585			139,237
	Revisions of previous estimates		7,936			4,632			25,644
	Purchase of reserves in place		10,613			—			12,082
	Extensions, discoveries, and other additions		3,305			110			544
	Sale of reserves in place		-10			—			-63
	Production		-2,141			-202			-14,824
	Balance December 31, 2012		36,827			9,125			162,620
	Revisions of previous estimates		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
	Extensions, discoveries and other additions		1,705			3,226			132,345
	Revisions of previous estimates		-6,540			2,149			-511
	Sales 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
	Developed reserves, included above
	December 31, 2012		16,355			6,262			125,526
	December 31, 2013		12,085			6,990			176,585
	December 31, 2014		6,938			10,587			251,628
	Proved undeveloped reserves, included above:
	31-Dec-12		20,472			2,863			37,094
	31-Dec-13		12,250			3,432			70,197
	31-Dec-14		3,583			3,816			101,373
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,
			2014				2013				2012
			(in thousands)
	Future cash inflows		$	3,282,768			$	3,711,260			$	4,248,384
	Future production costs		(1,443,121		)		(1,423,306		)		(1,520,260		)
	Future development costs		(219,509		)		(421,797		)		(603,809		)
	Future income tax expense		—				(149,367		)		(230,500		)
	Future net cash flows		1,620,138				1,716,790				1,893,815
	10% annual discount for estimated timing of cash flows		(710,875		)		(872,280		)		(1,046,162		)
	Standardized measure of discounted future net cash flows		$	909,263			$	844,510			$	847,653
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,
			2014				2013				2012
			(in thousands)
	Balance, beginning of period		$	844,510			$	847,653			$	474,396
	Net changes in prices and production costs		(281,352		)		(7,355		)		13,647
	Changes in estimated future development costs		(57,348		)		(261,591		)		(391,318		)
	Sales and transfers of oil and gas produced during the period		(166,611		)		(190,151		)		(179,384		)
	Net changes due to extensions, discoveries, and improved recovery		332,684				12,829				60,468
	Net changes due to revisions of previous quantity estimates (1)		(55,176		)		341,003				290,500
	Previously estimated development costs incurred during the period		269,017				283,736				245,168
	Accretion of discount		95,547				90,153				85,377
	Purchase of minerals in place		—				218				217,791
	Sale of minerals in place		(141,847		)		(236,885		)		(354		)
	Changes in timing and other (2)		(7,720		)		(91,088		)		22,436
	Net change in income taxes		77,559				55,988				8,926
	Standardized measure of discounted future net cash flows		$	909,263			$	844,510			$	847,653
	______________
	(1)	The Company's net changes due to revisions of previous quantity estimates primarily reflect upward revisions to recoverable quantities of oil and gas minerals assuming existing prices and technology. For the year ended December 31, 2014, the Company made downward revisions of 6,540 MBbl 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. For the year ended December 31, 2012, the Company made upward revisions of 7,936 MBbls of oil, 4,632 MBbl of natural gas liquids and 25,644 MMcf of natural gas.
	(2)	The Company's changes in timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. The reserves as of December 31, 2012, reflect accelerated recovery of minerals due to purchases of minerals in place and capital expenditures incurred to develop properties.
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:
			2014				2013				2012
	Oil (per Bbl)		$	85.21			$	93.13			$	88.37
	Natural gas liquids (per Bbl)		$	50.64			$	43.79			$	53.94
	Gas (per Mcf)		$	4.69			$	4.14			$	3.08

ORGANIZATION_NATURE_OF_OPERATI2

ORGANIZATION, NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 18, 2014

Summary of Significant Accounting Policies [Line Items]

Due Period of Joint Interest Owner Obligations

30 days

Allowance for Doubtful Accounts Receivable

$300,000

$200,000

$300,000

$200,000

Deferred Finance Costs, Noncurrent, Net

22,856,000

20,008,000

22,856,000

20,008,000

Amortization and write-off of deferred financing costs

9,679,000

4,818,000

7,399,000

Required period to remit liabilities under revenue payable

30 days

Liability for Uncertain Tax Positions, Current

0

0

0

0

Foreign currency translation gain (loss)

-1,204,000

-10,928,000

3,883,000

Amounts reclassified from accumulated other comprehensive income upon sale of Williston Hunter Canada, Inc.

20,741,000

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

128,000

-258,000

-5,212,000

-8,513,000

-31,421,000

[1]

-69,521,000

[1]

172,452,000

[1]

0

-13,855,000

[2],[3]

71,510,000

[2],[3]

2,409,000

[2],[3]

Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent

-7,401,000

-84,000

-309,000

Eureka Hunter Holdings, LLC

Summary of Significant Accounting Policies [Line Items]

Ownership percentage by parent

48.60%

56.40%

48.60%

56.40%

61.00%

Eureka Hunter Pipelines, LLC

Summary of Significant Accounting Policies [Line Items]

Consolidated Entities Ownership Percentage in Entity

100.00%

100.00%

Energy Hunter Securities Inc.

Summary of Significant Accounting Policies [Line Items]

Minimum Net Capital Required for Broker-Dealer Subsidiary

5,000

5,000

Ratio of Indebtedness to Net Capital

0.0667

0.0667

Sentra Corporation

Summary of Significant Accounting Policies [Line Items]

Regulated Operating Revenue, Gas

718,000

216,000

511,000

Eureka Hunter Land, LLC [Member]

Summary of Significant Accounting Policies [Line Items]

Consolidated Entities Ownership Percentage in Entity

100.00%

100.00%

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 Hunter Holdings, LLC

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 upon sale of Williston Hunter Canada, Inc.

20,741,000

Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent

-7,401,000

-84,000

-309,000

Penn Virginia

Summary of Significant Accounting Policies [Line Items]

Proceeds from Sale of Available-for-sale Securities

-50,562,000

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

$8,262,000

[1]

(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.

[2]

(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.

[3]

(4)The Companybs 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.

DECONSOLIDATION_OF_EUREKA_HUNT2

DECONSOLIDATION OF EUREKA HUNTER HOLDINGS - Deconsolidation Narrative (Details) (USD $)	12 Months Ended			0 Months Ended		1 Months Ended	0 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 18, 2014	Nov. 20, 2014	Jan. 31, 2015	Nov. 18, 2014	Mar. 31, 2015	Dec. 17, 2014
									member
Noncontrolling Interest [Line Items]
Non-cash loss, downward adjustment of equity interests	$32,600,000
Gain on deconsolidation	509,563,000	0	0
Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Percent ownership of subsidiaries	48.60%
Number of representatives on the board of managers of LLC	3
Gain on deconsolidation				509,600,000
Revaluation of retained investment, gain				187,200,000
Series A-1 Units | Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Payments for limited liability company units					20,000,000
Morgan Stanley Infrastructure (MSI) | Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Percent ownership of subsidiaries	49.84%
Carried interest limitt if capital contributions are made	60,000,000
Deferred capital contributions	30,000,000
Number of managers on the board of limited liability company				6					5
Number of representatives on the board of managers of LLC	3
Retained interest upon deconsolidation	347,292,000			347,300,000
Morgan Stanley Infrastructure (MSI) | Scenario, Forecast | Eureka Hunter Holdings, LLC
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%
Morgan Stanley Infrastructure (MSI) | Series A-1 Units | Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Reduction in capital account, shares							1,227,182
Reduction in capital account							32,600,000
Payments for limited liability company units				55,000,000
Limited liability company units sold				5.50%
Morgan Stanley Infrastructure (MSI) | Series A-1 Units | Scenario, Forecast | Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Payments for limited liability company units								13,000,000
Morgan Stanley Infrastructure (MSI) | Series A-2 Units | Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Payments for limited liability company units				$10,000,000	$30,000,000

DECONSOLIDATION_OF_EUREKA_HUNT3

DECONSOLIDATION OF EUREKA HUNTER HOLDINGS - Income Information (Details) (USD $)	3 Months Ended												12 Months Ended			0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Revenue, Net	$59,854	[1]	$79,670	[1]	$138,463	[1]	$113,482	$90,179	$78,291		$76,686	$59,382	$391,469	$304,538	$159,937
Operating Income (Loss)	-401,575	[2]	-57,576	[2]	1,555	[2]	-32,762	-39,070	-119,874	[3]	-34,412	-41,437	-490,358	-234,793	-126,660
Net loss													-3,653	-988	-4,013
Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014													-1,038	-994	-1,971
Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Revenue, Net																2,124
Operating Income (Loss)																74
Net loss																-207
Magnum Hunter's 48.6% interest in Eureka Hunter Holdings net loss for the period from December 18, 2014 to December 31, 2014																($101)
Ownership percentage by parent	48.60%							56.40%					48.60%	56.40%	61.00%	48.60%
[1]	(1) 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.
[2]	(2) The quarter-ended June 30, 2014 income from operations 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 Companybs capital account with Eureka Hunter Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipelinebs fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects.
[3]	(4) The quarter-ended September 30, 2013 loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.

DECONSOLIDATION_OF_EUREKA_HUNT4

DECONSOLIDATION OF EUREKA HUNTER HOLDINGS - Balance Sheet Information (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Noncontrolling Interest [Line Items]
Current assets	$120,196	$120,726
Current liabilities	168,445	183,865
Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Current assets	17,113
Non-current assets	445,450
Current liabilities	63,313
Non-current liabilities	$100,037

DECONSOLIDATION_OF_EUREKA_HUNT5

DECONSOLIDATION OF EUREKA HUNTER HOLDINGS - Net Assets (Details) (USD $)	12 Months Ended			0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Loss from equity method investment	($1,038)	($994)	($1,971)
Investment in affiliates, equity method	347,191	940		347,191
Eureka Hunter Holdings, LLC
Noncontrolling Interest [Line Items]
Net Assets of Eureka Hunter Holdings attributable to Magnum Hunter, at December 18, 2014	145,418			145,418
Basis difference	201,874			201,874
Loss from equity method investment				-101
Investment in affiliates, equity method	$347,191			$347,191

ACQUISITIONS_DIVESTITURES_AND_2

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS Revenue and Operating Income (Loss) Summary (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Eagle Operating, Inc.
Business Acquisition [Line Items]
Revenues	$2	$7,331	$5,500
Operating Income (Loss)	938	-26,867	-3,019
Trans Tex Gas Services
Business Acquisition [Line Items]
Revenues	9,729	12,765	7,014
Operating Income (Loss)	-2,995	-812	-393
Baytex Energy USA Assets
Business Acquisition [Line Items]
Revenues	102,146	100,572	18,430
Operating Income (Loss)	-352,151	-101,627	-6,649
Virco
Business Acquisition [Line Items]
Revenues	3,194	4,453	1,094
Operating Income (Loss)	($7,936)	($177)	$450

ACQUISITIONS_DIVESTITURES_AND_3

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS Pro Forma Results (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisitions, Pro Forma Results Of Operations [Line Items]
Total revenue	$59,854	[1]	$79,670	[1]	$138,463	[1]	$113,482	$90,179	$78,291		$76,686	$59,382	$391,469	$304,538	$159,937
OPERATING LOSS	-401,575	[2]	-57,576	[2]	1,555	[2]	-32,762	-39,070	-119,874	[3]	-34,412	-41,437	-490,358	-234,793	-126,660
NET LOSS													-147,127	-223,164	-136,721
Net loss attributable to Magnum Hunter Resources Corporation	103,448		-120,683		-64,647		-61,592	-46,537	-296,882		165,440	-44,197	-143,474	-222,176	-132,708
Net loss attributable to common shareholders	42,767		-136,175		-79,997		-76,468	-61,208	-311,299		151,311	-57,685	-249,873	-278,881	-167,414
Loss per common share, basic and diluted	$0.23		($0.68)		($0.43)		($0.44)	($0.36)	($1.83)		$0.89	($0.34)	($1.32)	($1.64)	($1.07)
Pro forma
Business Acquisitions, Pro Forma Results Of Operations [Line Items]
Total revenue															159,085
OPERATING LOSS															-108,177
NET LOSS															-150,777
Net loss attributable to Magnum Hunter Resources Corporation															-146,764
Net loss attributable to common shareholders															($188,736)
Loss per common share, basic and diluted															($1.21)
[1]	(1) 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.
[2]	(2) The quarter-ended June 30, 2014 income from operations 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 Companybs capital account with Eureka Hunter Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipelinebs fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects.
[3]	(4) The quarter-ended September 30, 2013 loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.

ACQUISITIONS_DIVESTITURES_AND_4

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS Assets and Liabilities Held for Sale (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Discontinued operations
Liabilities associated with assets held for sale	$0	$12,865
MHP and WHI Canada
Discontinued operations
Accounts Receivable Held-for-sale		4,362
Other Assets Held-for-sale, Current		1,004
Oil and Gas Properties Held-for-sale		150,770
Gas Equipment Held-for-sale		11,721
Assets Held-for-sale, Other, Noncurrent		196
Assets Held-for-sale		168,053
Accounts Payable Held-for-sale		7,292
Accrued Expenses and Other Liabilities Held-for-sale		5,573
Asset Retirement Obligations Held-for-sale		8,678
Other Liabilities Held-for-sale, Noncurrent		5,845
Liabilities associated with assets held for sale		$27,388

ACQUISITIONS_DIVESTITURES_AND_5

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS Results of Operations of WHI Canada (Details) (USD $)	3 Months Ended											12 Months Ended						9 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Sep. 30, 2014	Sep. 30, 2014
Discontinued operations
Disposal Group, Including Discontinued Operation, Revenue												$8,533,000		$67,490,000		$114,068,000
Disposal Group, Including Discontinued Operation, Operating Expense												-3,975,000	[1]	-130,331,000	[1]	-122,099,000	[1]
Disposal Group, Including Discontinued Operation Nonoperating Income (Expense)												3,000		186,000		-94,000
Gain (loss) from discontinued operations												4,561,000		-62,655,000		-8,125,000
Discontinued Operation, Tax Effect of Income (Loss) from Discontinued Operation During Phase-out Period												0	[2]	94,000	[2]	-1,648,000	[2]
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax												4,561,000		-62,561,000		-9,773,000
Gain (loss) on disposal of discontinued operations, net of tax	128,000	-258,000	-5,212,000	-8,513,000	-31,421,000	[3]	-69,521,000	[3]	172,452,000	[3]	0	-13,855,000	[4],[5]	71,510,000	[4],[5]	2,409,000	[4],[5]
Income (loss) from discontinued operations, net of tax												-9,294,000		8,949,000		-7,364,000
Impairment expense related to discontinued operations							72,500,000
Magnum Hunter Production and Williston Hunter Canada
Discontinued operations
Gain (loss) on disposal of discontinued operations, net of tax																		-12,900,000
Impairment expense related to discontinued operations				18,600,000	18,200,000		55,600,000					18,500,000		65,400,000		256,000			67,600,000
Disposal Group Including Discontinued Operations Exploration Expense												100,000		19,900,000		36,800,000
Wilson Hunter Canada, Inc.
Discontinued operations
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent												0.20%
Tax Effect of Income (Loss) from Disposal of Discontinued Operation												0		-11,900,000		1,400,000
Hunter Disposal LLC
Discontinued operations
Gain (loss) on disposal of discontinued operations, net of tax														2,409,000
Tax Effect of Income (Loss) from Disposal of Discontinued Operation														$1,300,000
WHI Canada Capital Loss Utilization Against Capital Gains
Discontinued operations
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent												14.23%
[1]	(1)Includes impairment expense of $65.4 million, and $0.3 million for the years ended December 31, 2013 and 2012, respectively, and exploration expense of $0.1 million, $19.9 million, and $36.8 million for the years ended December 31, 2014, 2013, and 2012, respectively relating to the discontinued operations of WHI Canada, which is recorded in income (loss) from discontinued operations.
[2]	(2)The Companybs 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]	(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.
[4]	(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[5]	(4)The Companybs 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.

ACQUISITIONS_DIVESTITURES_AND_6

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS Acqusition Narratives (Details) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Mar. 30, 2012

22-May-12

Nov. 02, 2012

Dec. 20, 2012

Apr. 02, 2012

Mar. 31, 2014

Nov. 30, 2012

Oct. 30, 2014

Jan. 14, 2015

Jun. 17, 2014

Aug. 12, 2013

Jun. 18, 2014

common_unit

acre

acre

Business Acquisition [Line Items]

Business Combination, Acquisition Related Costs

$0

$2,800,000

$4,700,000

Goodwill

0

30,602,000

Business Acquisition, Number of Townships and Ranges Covered through Acquired Property

4

Eagle Operating, Inc.

Business Acquisition [Line Items]

Consideration Transferred

52,876,000

Cash payment for acquisition

50,974,000

Common stock issued in connection with acquisition (in shares)

296,859

Common stock issued in connection with acquisition

1,902,000

Business Acquisition, Share Price

$6.41

Baytex Energy Corporation USA, Ltd.

Business Acquisition [Line Items]

Consideration Transferred

312,018,000

Cash payment for acquisition

312,018,000

Viking International Resources Co, Inc.

Business Acquisition [Line Items]

Consideration Transferred

100,808,000

Cash payment for acquisition

37,349,000

Common stock issued in connection with acquisition

65,209,000

Temporary Equity, Liquidation Preference

69,400,000

Samson Resources Company

Business Acquisition [Line Items]

Cash payment for acquisition

30,000,000

Business Acquisition Percentage of Working Interests Owned in Acquired Properties

100.00%

Utica Shale

Business Acquisition [Line Items]

Net mineral acres acquired

32,000

Business Combination, Maximum Purchase Price

142,100,000

Payments to Acquire Land

24,600,000

Ormet Asset Purchase Agreement

Business Acquisition [Line Items]

Business Combination, Acreage In Which Mineral Interests Are Acquired

2,000

Eureka Hunter Holdings, LLC | Trans Tex Gas Services

Business Acquisition [Line Items]

Consideration Transferred

58,500,000

Cash payment for acquisition

46,047,000

Common Units Issued During Period Shares Acquisitions

622,641

Common stock issued in connection with acquisition

12,453,000

Business Acquisition, Cost of Acquired Entity, Total Enterprise Value

400,000,000

Goodwill

30,602,000

Intangible assets recognized

10,492,000

Depositary shares

Business Acquisition [Line Items]

Common stock issued in connection with acquisition (in shares)

27,906

4,300,000

Cumulative dividend rate for cumulative preferred stock (as a percent)

8.00%

Depositary shares | Viking International Resources Co, Inc.

Business Acquisition [Line Items]

Common stock issued in connection with acquisition (in shares)

2,774,850

2,774,850

Series E Preferred Stock

Business Acquisition [Line Items]

Cumulative dividend rate for cumulative preferred stock (as a percent)

8.00%

8.00%

Series E Preferred Stock | Viking International Resources Co, Inc.

Business Acquisition [Line Items]

Common stock issued in connection with acquisition (in shares)

2,774.85

Cumulative dividend rate for cumulative preferred stock (as a percent)

8.00%

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

Business Acquisition [Line Items]

Consideration Transferred

67,700,000

Business Combination, Acreage Of Undeveloped Leasehold Acquired

16,456

5,922

Payments to Acquire Land

67,300,000

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

Business Acquisition [Line Items]

Business Combination, Acreage Of Undeveloped Leasehold Acquired

2,665

Payments to Acquire Land

12,000,000

Monroe County, Ohio | Ormet Asset Purchase Agreement

Business Acquisition [Line Items]

Business Combination, Acreage In Which Mineral Interests Are Acquired

1,375

Wetzerl County, West Virginia | Ormet Asset Purchase Agreement

Business Acquisition [Line Items]

Business Combination, Acreage In Which Mineral Interests Are Acquired

325

Marcellus Zone | Ormet Asset Purchase Agreement

Business Acquisition [Line Items]

Cash payment for acquisition

$22,700,000

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%

ACQUISITIONS_DIVESTITURES_AND_7

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS Discontinued Operations Narratives (Details)

3 Months Ended

9 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

0 Months Ended

9 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Sep. 30, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Feb. 17, 2012

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2014

Jun. 30, 2014

Apr. 24, 2013

12-May-14

12-May-14

Sep. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2014

Sep. 30, 2014

Dec. 31, 2013

Dec. 31, 2012

12-May-14

Mar. 01, 2014

Apr. 10, 2014

Apr. 10, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2014

Feb. 17, 2012

Apr. 24, 2013

Sep. 30, 2013

Sep. 30, 2013

Nov. 03, 2014

Oct. 15, 2014

Sep. 30, 2014

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Hunter Disposal LLC

Hunter Disposal LLC

Hunter Disposal LLC

Eagle Ford Hunter

Eagle Ford Hunter

Eagle Ford Hunter

Eagle Ford Hunter

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Williston Hunter Canada Assets

Williston Hunter Canada Assets

Unproved Oil And Natural Gas Properties

Proved Oil and Natural Gas Properties

Series C Preferred Stock

Series C Preferred Stock

Penn Virginia

Penn Virginia

Penn Virginia

Roane Counties, West Virginia

Divide County, North Dakota

Divide County, North Dakota

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

CAD

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

CAD

USD ($)

CAD

Magnum Hunter Production and Williston Hunter Canada

Magnum Hunter Production and Williston Hunter Canada

Hunter Disposal LLC

Hunter Disposal LLC

Hunter Disposal LLC

Hunter Disposal LLC

Non-Core Working Interests In Oil And Gas Properties

Non-Operated Working Interests In Oil And Gas Properties

Non-Operated Working Interests In Oil And Gas Properties

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Discontinued operations

Ownership Percentage Sold

100.00%

100.00%

Total consideration received

$9,300,000

$422,100,000

Impairment expense related to discontinued operations

72,500,000

18,600,000

18,200,000

55,600,000

18,500,000

67,600,000

65,400,000

256,000

1,900,000

17,000,000

5,700,000

15,200,000

Depreciation

22,100,000

15,600,000

8,100,000

1,700,000

Proceeds from Sale of Property, Plant, and Equipment

8,700,000

9,500,000

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

128,000

-258,000

-5,212,000

-8,513,000

-31,421,000

[1]

-69,521,000

[1]

172,452,000

[1]

0

-13,855,000

[2],[3]

71,510,000

[2],[3]

2,409,000

[2],[3]

2,409,000

-12,900,000

6,100,000

172,500,000

-2,700,000

7,200,000

Tax Effect of Income (Loss) from Disposal of Discontinued Operation

1,300,000

Proceeds from Divestiture of Businesses

2,200,000

68,800,000

75,000,000

379,800,000

50,600,000

1,200,000

84,800,000

23,500,000

Discontinued Operations, Cash In Escrow

18,400,000

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

20,700,000

20,741,000

0

0

8,300,000

Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Shares

1,846,722

10,000,000

10,000,000

Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Value

2,600,000

42,300,000

42,300,000

Share Price

$1.79

$4.23

Sales Proceeds Used to Pay Down Outstanding Borrowings

325,000,000

Consideration received, number of shares of preferred stock received

88,000

Cumulative dividend rate for cumulative preferred stock (as a percent)

10.25%

10.00%

Consideration received, value of preferred stock received

2,200,000

1,900,000

Consideration received, value of promissory notes convertible into GreenHunter Energy, Inc common stock (in shares)

880,000

Debt Instrument, Convertible, Conversion Price

$2.50

Embedded Derivative, Fair Value of Embedded Derivative Asset

405,000

Adjusted cash proceeds for changes in working capital to reflect the effective date of the sale

783,000

Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax

-13,855,000

83,378,000

3,830,000

3,700,000

Liabilities of Disposal Group, Including Discontinued Operation

33,700,000

Disposal Group, Including Discontinued Operation, Accrued Liabilities

1,300,000

Discontinued Operation, Amount of Adjustment to Prior Period Gain (Loss) on Disposal, Net of Tax

28,100,000

7,100,000

Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal

($1,100,000)

[1]

(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.

[2]

(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.

[3]

(4)The Companybs 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.

ACQUISITIONS_DIVESTITURES_AND_8

ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS Other Divestitures Narratives (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Sep. 26, 2013

Dec. 30, 2013

Jan. 28, 2014

Nov. 03, 2014

Oct. 15, 2014

Sep. 30, 2014

Dec. 31, 2011

Well

Discontinued operations

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

$128,000

($258,000)

($5,212,000)

($8,513,000)

($31,421,000)

[1]

($69,521,000)

[1]

$172,452,000

[1]

$0

($13,855,000)

[2],[3]

$71,510,000

[2],[3]

$2,409,000

[2],[3]

Available-for-sale Securities

3,864,000

1,819,000

3,864,000

1,819,000

1,958,000

497,000

Williston Hunter Inc

Discontinued operations

Proceeds from Divestiture of Businesses

32,500,000

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

-38,100,000

Enduro Operating LLC

Discontinued operations

Disposal Group, Not Discontinued Operation, Operated Working Interests, Wells

180

Proceeds from Divestiture of Interest in Consolidated Subsidiaries

44,100,000

Discontinued Operation, Preliminary Gain (Loss) on Disposal of Discontinued Operation

-7,100,000

Eagle Ford Shale Assets

Discontinued operations

Proceeds from Divestiture of Businesses

15,500,000

Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal

-4,500,000

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

Discontinued operations

Number of Horizontal Oil and Gas Wells

5

Number of Horizontal Oil and Gas Wells Operated by Magnum Hunter Resources

4

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

Discontinued operations

Proceeds from Divestiture of Businesses

1,200,000

Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal

-1,100,000

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

Discontinued operations

Proceeds from Divestiture of Businesses

84,800,000

23,500,000

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

-2,700,000

7,200,000

New Standard Energy Texas LLC | Eagle Ford Shale Assets

Discontinued operations

Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Shares

65,650,000

Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Value

9,400,000

Disposal Group Including Discontinued Operation Price Of Stock On Sale Date

$0.14

Investment holding of total dhares outstanding, percent

17.00%

Investments | New Standard Energy Texas LLC | Eagle Ford Shale Assets

Discontinued operations

Available-for-sale Securities

$2,500,000

$2,500,000

[1]

(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.

[2]

(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.

[3]

(4)The Companybs 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_Details

OIL & NATURAL GAS SALES (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	$268,501	$220,699	$133,728
Oil
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	131,109	147,798	82,225
Natural Gas
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	91,277	53,821	45,825
NGL
Schedule of Oil Natural Gas and NGL Revenue [Line Items]
Oil and natural gas sales	$46,115	$19,080	$5,678

PROPERTY_PLANT_EQUIPMENT_Detai

PROPERTY, PLANT, & EQUIPMENT (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 18, 2014
Property, Plant and Equipment [Line Items]
Exploration costs	$9,907,000	$11,531,000	$165,789,000
Depreciation	22,100,000	15,600,000	8,100,000
Depreciation, depletion, amortization and accretion	146,868,000	107,385,000	72,438,000
Geological and geophysical	1,564,000	1,402,000	2,570,000
Unproved leasehold costs	481,643,000	469,337,000
Capitalized Costs, Mineral Interests in Proved Properties	257,185,000	336,357,000
Wells and related equipment and facilities	560,060,000	438,275,000
Uncompleted wells, equipment and facilities	46,346,000	97,748,000
Advances to operators for wells in progress	1,411,000	13,571,000
Results of Operations, Impairment of Oil and Gas Properties	301,276,000	50,011,000	3,839,000
Capitalized Costs, Oil and Gas Producing Activities, Gross	1,346,645,000	1,355,288,000
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance Relating to Oil and Gas Producing Activities	-248,410,000	-130,629,000
Capitalized Costs, Oil and Gas Producing Activities, Net	1,098,235,000	1,224,659,000
Exploration Abandonment and Impairment Expense	118,509,000	100,389,000	80,375,000
Williston Basin
Property, Plant and Equipment [Line Items]
Results of Operations, Impairment of Oil and Gas Properties	261,270,000	8,498,000	3,631,000
Impairment of Leasehold	103,147,000	89,167,000	59,214,000
Appalachian
Property, Plant and Equipment [Line Items]
Impairment of Leasehold	9,978,000	6,773,000	15,033,000
Appalachian Region
Property, Plant and Equipment [Line Items]
Results of Operations, Impairment of Oil and Gas Properties	6,001,000	1,151,000	76,000
Western Kentucky
Property, Plant and Equipment [Line Items]
Results of Operations, Impairment of Oil and Gas Properties	33,811,000	40,043,000	67,000
Impairment of Leasehold	3,820,000	3,047,000	2,154,000
South Texas
Property, Plant and Equipment [Line Items]
Results of Operations, Impairment of Oil and Gas Properties	194,000	319,000	65,000
Impairment of Leasehold	0	0	1,404,000
Gas Transportation Gathering Processing and Other Equipment
Property, Plant and Equipment [Line Items]
Capitalized Costs, Oil and Gas Producing Activities, Gross	100,436,000	315,642,000
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance Relating to Oil and Gas Producing Activities	-23,013,000	-26,222,000
Capitalized Costs, Oil and Gas Producing Activities, Net	77,423,000	289,420,000
Oil and natural gas properties
Property, Plant and Equipment [Line Items]
Depreciation, depletion, amortization and accretion	121,900,000	69,000,000	49,200,000
Magnum Hunter Production, Inc.
Property, Plant and Equipment [Line Items]
Impairment of Leasehold	33,800,000	26,900,000
Farley Pad
Property, Plant and Equipment [Line Items]
Exploration costs	1,100,000
Farley 1305 H
Property, Plant and Equipment [Line Items]
Exploration costs	13,800,000
Eureka Hunter Holdings, LLC | Gas Transportation Gathering Processing and Other Equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment derecognized				439,000,000
Accumulated depreciation and depletion				($30,300,000)

INTANGIBLE_ASSETS_Details

INTANGIBLE ASSETS (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Intangible assets
Amortization expense for intangible assets	$2,000,000	$2,500,000	$1,500,000
Intangible assets [Roll Forward]
Intangible assets, at beginning of the period	10,492,000
Total intangible assets		10,492,000
Intangible assets, net of accumulated amortization		6,530,000
Customer relationships
Intangible assets [Roll Forward]
Additions acquired through acquisition		5,434,000
Accumulated amortization		-1,248,000
Trademark
Intangible assets [Roll Forward]
Additions acquired through acquisition		859,000
Accumulated amortization		-137,000
Existing contracts
Intangible assets [Roll Forward]
Additions acquired through acquisition		4,199,000
Accumulated amortization		($2,577,000)

INVENTORY_Details

INVENTORY (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Inventory Disclosure [Abstract]
Materials and supplies	$1,436	$6,790
Oil in tanks	832	368
Inventory	$2,268	$7,158

ASSET_RETIREMENT_OBLIGATIONS_D

ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation at beginning of period	$16,216	$30,680
Assumed in acquisition	0	17
Liabilities incurred	218	253
Liabilities settled	-107	-98
Liabilities sold	-2,598	-7,614
Accretion expense	1,478	2,264
Revisions in estimated liabilities	3,208	1,935
Reclassified as liabilities associated with assets held for sale	0	-11,148
Reclassified from liabilities associated with assets held for sale	8,109	0
Correction of prior year error	0	73
Asset retirement obligation at end of period	26,524	16,216
Less: current portion	-295	-53
Asset retirement obligation at end of period	$26,229	$16,163

FAIR_VALUE_OF_FINANCIAL_INSTRU2

FAIR VALUE OF FINANCIAL INSTRUMENTS Black-Scholes Option Pricing Model (Details) (Convertible security derivative assets, Level 3, USD $)	12 Months Ended
	Dec. 31, 2014
Convertible security derivative assets | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Assumptions, Expected Term	2 years 1 month 6 days
Fair Value Assumptions, Risk Free Interest Rate	0.95%
Fair Value Assumptions, Expected Volatility Rate	91.00%
Fair Value Assumptions, Expected Dividend Rate	0.00%
Share Price	$0.71

FAIR_VALUE_OF_FINANCIAL_INSTRU3

FAIR VALUE OF FINANCIAL INSTRUMENTS Financial Assets and Liabilities Adjusted to FV on a Recurring Basis (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	$3,864		$1,819		$1,958	$497
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	3,864		1,819
Assets, Fair Value Disclosure	3,864		1,819
Financial and Nonfinancial Liabilities, Fair Value Disclosure			0
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
Assets, Fair Value Disclosure	16,511		554
Financial and Nonfinancial Liabilities, Fair Value Disclosure			2,279
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
Assets, Fair Value Disclosure	75		79
Financial and Nonfinancial Liabilities, Fair Value Disclosure			75,934
Commodity Contract [Member] | Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0		0
Derivative Liability			0
Commodity Contract [Member] | Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	16,511		554
Derivative Liability			2,279
Commodity Contract [Member] | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0		0
Derivative Liability			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		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		0
Preferred Stock Embedded Derivative | Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability			0
Preferred Stock Embedded Derivative | Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability			0
Preferred Stock Embedded Derivative | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability			75,934
GreenHunter Resources, Inc.
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	75	[1],[2]	79	[1],[2]
GreenHunter Resources, Inc. | 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		$79
[1]	GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and Virco., wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.
[2]	On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water, LLC (bGreenHunter Waterb), 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 bNote 9 - Fair Value of Financial Instrumentsb. The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long-term assets and an available for sale investment in GreenHunter included in investments.

FAIR_VALUE_OF_FINANCIAL_INSTRU4

FAIR VALUE OF FINANCIAL INSTRUMENTS Changes in FV of Derivative Assets and Liabilities (Details) (USD $)	12 Months Ended			0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 03, 2014	Dec. 31, 2011
Series A Preferred Stock
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Embedded Derivative, Fair Value of Embedded Derivative Liability					$0
Embedded Derivative, Fair Value of Embedded Derivative Liability	0		-43,548		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, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	79	264	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances	0	0	405
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings	-4	-185	-141
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	75	79	264
Embedded Derivatives, Liabilities | Convertible security derivative assets | Level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	0
Embedded Derivatives, Liabilities | Preferred Stock Embedded Derivative | Level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Issuances	-5,479	-14,645	-52,240
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	-91,792	-17,741	8,692
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements		($75,934)		$173,205

FAIR_VALUE_OF_FINANCIAL_INSTRU5

FAIR VALUE OF FINANCIAL INSTRUMENTS Carrying Amounts and Fair Values Categorized by FV Hierarchy (Details) (USD $)	Dec. 31, 2014	Oct. 22, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Level 2 | Senior Notes
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	$597,355		$597,230
Level 3 | Senior Revolving Credit Facility
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	0		218,000
Level 3 | 8.5% Second Lien Term Loan due October 22, 2019 [Member]
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	329,140		0
Discount on issuance of long-term debt		3.00%
Level 3 | Term Loan [Member]
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	0		50,000
Level 3 | Equipment note payable
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	22,238		18,615
Estimated Fair Value | Level 2 | Senior Notes
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	498,000		651,300
Estimated Fair Value | Level 3 | Senior Revolving Credit Facility
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	0		218,000
Estimated Fair Value | Level 3 | 8.5% Second Lien Term Loan due October 22, 2019 [Member]
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	329,140		0
Estimated Fair Value | Level 3 | Term Loan [Member]
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	0		58,291
Estimated Fair Value | Level 3 | Equipment note payable
Carrying amounts and fair values of long-term debt
Fair value of long-term debt	$22,150		$17,676

FAIR_VALUE_OF_FINANCIAL_INSTRU6

FAIR VALUE OF FINANCIAL INSTRUMENTS Fair Value Measurements on a Non-Recurring Basis (Details) (Nonrecurring, USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved properties impaired	$0	$0	$0
Long-Lived Assets	0	0
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	0
Acquisitions			0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved properties impaired	0	0	0
Long-Lived Assets	0	0
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	0
Acquisitions			0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved properties impaired	584,895	329,409	372,450
Long-Lived Assets	28,443	87,149
Investments in Affiliates, Subsidiaries, Associates, and Joint Ventures, Fair Value Disclosure	347,291
Acquisitions			$532,150

FAIR_VALUE_OF_FINANCIAL_INSTRU7

FAIR VALUE OF FINANCIAL INSTRUMENTS Narratives (Details) (USD $)	12 Months Ended			3 Months Ended	0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014	Dec. 18, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Impairment of proved oil and gas properties	$301,276	$50,011	$3,839
Nonrecurring | Level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Acquisitions			532,150
Eureka Hunter Holdings, LLC | Fair Value, Measurements, Recurring | Preferred Stock Embedded Derivative | Level 3 | Minimum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Assumptions, Expected Term	0 years			1 year
Eureka Hunter Holdings, LLC | Fair Value, Measurements, Recurring | Preferred Stock Embedded Derivative | Level 3 | Maximum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Assumptions, Expected Term	6 years			2 years
Embedded Derivatives, Liabilities | Preferred Stock Embedded Derivative | Level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	($91,792)	($17,741)	$8,692
Morgan Stanley Infrastructure (MSI) | Series A-1 Units | Eureka Hunter Holdings, LLC
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Limited liability company units sold					5.50%
Oil and natural gas properties
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Discount rate (as a percent)	10.00%

INVESTMENTS_AND_DERIVATIVES_Ch

INVESTMENTS AND DERIVATIVES Changes in Investments (Details) (USD $)	3 Months Ended											12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule of Available-for-sale Securities [Line Items]
Equity Method Investments, Return of Capital														($138)
Available-for-sale Securities	3,864				1,819							3,864		1,819		1,958		497
Equity Method Investments, Fair Value Disclosure	347,191				940							347,191		940		2,072		0
Available for Sale Securities, Acquired During Period														42,300
Equity Method Investments, Acquired During Period																4,043
Cost-method Investments, Transfers From																1,770
Loss from equity method investment												-1,038		-994		-1,971
Equity Method Investments, Other Adjustments												-3
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax												-7,401		-84		-309
Available-for-sale Securities, Received as Consideration												9,446
Gain (loss) on disposal of discontinued operations, net of tax	128	-258	-5,212	-8,513	-31,421	[1]	-69,521	[1]	172,452	[1]	0	-13,855	[2],[3]	71,510	[2],[3]	2,409	[2],[3]
Available-for-sale Securities, Other Adjustments														-55
Penn Virginia
Schedule of Available-for-sale Securities [Line Items]
Proceeds from Sale of Available-for-sale Securities														50,562
Gain (loss) on disposal of discontinued operations, net of tax														$8,262
[1]	(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.
[2]	(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[3]	(4)The Companybs 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.

INVESTMENTS_AND_DERIVATIVES_Co

INVESTMENTS AND DERIVATIVES Commodity Derivatives (Details)	12 Months Ended
	Dec. 31, 2014
	MMBTU
Natural Gas | Swaps | Jan 2014 - Dec 2014
Derivative [Line Items]
Natural gas commodity derivatives contract units per day (MMBTU)	40,000
Price per unit	4.09
Crude Oil | Collars | Jan 2014 - Dec 2014
Derivative [Line Items]
Crude oil commodity derivatives contract units per day (Bbl)	259	[1]
Crude Oil | Collars | Jan 2014 - Dec 2014 | Minimum
Derivative [Line Items]
Price per unit	85	[1]
Crude Oil | Collars | Jan 2014 - Dec 2014 | Maximum
Derivative [Line Items]
Price per unit	91.25	[1]
Crude Oil | Collars | Jan 2015 - Dec 2015 | Minimum
Derivative [Line Items]
Price per unit	85	[1]
Crude Oil | Collars | Jan 2015 - Dec 2015 | Maximum
Derivative [Line Items]
Price per unit	91.25	[1]
Crude Oil | Call Option | Jan 2015 - Dec 2015
Derivative [Line Items]
Crude oil commodity derivatives contract units per day (Bbl)	1,570
Price per unit	120
Crude Oil | Put Option | Jan 2014 - Dec 2014
Derivative [Line Items]
Crude oil commodity derivatives contract units per day (Bbl)	259
Price per unit	70
[1]	A collar is a sold call and a purchased put. Some collars are bcostlessb collars with the premiums netting to approximately zero.

INVESTMENTS_AND_DERIVATIVES_De

INVESTMENTS AND DERIVATIVES Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value
Gross Derivative Assets	$16,586	$633
Gross Derivative Liabilities	0	-78,213
Commodity
Derivatives, Fair Value
Gross Derivative Assets	16,511	554
Gross Derivative Liabilities	0	-2,279
Financial
Derivatives, Fair Value
Gross Derivative Assets	75	79
Gross Derivative Liabilities	0	-75,934
Derivative assets - current | Commodity
Derivatives, Fair Value
Gross Derivative Assets	16,511	529
Derivative assets - current | Financial
Derivatives, Fair Value
Gross Derivative Assets	75	79
Derivatives and other long term assets | Commodity
Derivatives, Fair Value
Gross Derivative Assets		25
Derivative and other current liabilities | Commodity
Derivatives, Fair Value
Gross Derivative Liabilities		-1,903
Derivative liabilities - long term | Commodity
Derivatives, Fair Value
Gross Derivative Liabilities		-376
Derivative liabilities - long term | Financial
Derivatives, Fair Value
Gross Derivative Liabilities		($75,934)

INVESTMENTS_AND_DERIVATIVES_Ne

INVESTMENTS AND DERIVATIVES Net Gain (Loss) on Derivative Contracts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	$18,232	($17,058)	$10,945
Embedded Derivative, Loss on Embedded Derivative	-91,792	0	0
Commodity Contract [Member] | Other Income (Expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on derivative contracts	-72,254	-25,274	22,239
Open Transaction [Member] | Commodity Contract [Member] | Other Income (Expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss)	18,232	-17,058	10,945
Settled Transaction [Member] | Commodity Contract [Member] | Other Income (Expense) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on derivative contracts	$1,306	($8,216)	$11,294

INVESTMENTS_AND_DERIVATIVES_In

INVESTMENTS AND DERIVATIVES Investments by Balance Sheet Location (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Securities, Current	$3,864	$1,672
Equity Method Investments, Current	0	590
Investments, Available-for-sale and Equity Method, Current	3,864	2,262
Available-for-sale Securities, Noncurrent	0
Investment in affiliates, equity method	347,191	350
Investments, Available-for-sale and Equity Method, Noncurrent	347,191	350
Available-for-sale securities, classified held-for-sale		147
Available-for-sale Securities	3,864	1,819	1,958	497
Investment in affiliates, equity method	347,191	940
Investments, Available-for-sale and Equity Method, Current and Noncurrent	$351,055	$2,759

INVESTMENTS_AND_DERIVATIVES_In1

INVESTMENTS AND DERIVATIVES Investments, Fair Value (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale Equity Securities, Amortized Cost Basis	$9,876	$428
Available-for-sale Equity Securities, Gross Unrealized Gain 1	0	0
Available-for-sale Equity Securities, Gross Unrealized Loss 1	-7,323	-281
Available-for-sale Securities, Equity Securities	2,553	147
Available-for-sale Equity Securities, Related Party, Amortized Cost	2,200	2,200
Available-for-sale Equity Securities, Related Party, Gross Unrealized Gain	0	0
Available-for-sale Equity Securities, Related Party, Gross Unrealized Loss	-889	-528
Available-for-sale Equity Securities, Related Party	1,311	1,672
Available-for-sale Securities, Equity Securities, Including Related Party, Amortized Cost Basis	12,076	2,628
Available-for-sale Equity Securities, Including Related Party, Gross Unrealized Gain	0	0
Available-for-sale Equity Securities, Including Related Party, Gross Unrealized Loss	8,212	809
Available-for-sale Equity Securities, Including Related Party	$3,864	$1,819

INVESTMENTS_AND_DERIVATIVES_Ef

INVESTMENTS AND DERIVATIVES Effect of Master Netting (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative [Line Items]
Gross Derivative Assets	$16,586	$633
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	16,511	-1,725
Derivative, Fair Value, Amount Offset Against Collateral, Net	0	0
Derivative, Fair Value, Net	16,511	-1,725
Current Assets [Member]
Derivative [Line Items]
Gross Derivative Assets	18,146	4,034
Derivative Asset, Fair Value, Amount Offset Against Collateral	-1,635	-3,505
Derivative assets	16,511	529
Long Term Assets [Member]
Derivative [Line Items]
Gross Derivative Assets	0	516
Derivative Asset, Fair Value, Amount Offset Against Collateral	0	-491
Derivative assets	0	25
Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	-1,635	-5,408
Derivative Liability, Fair Value, Amount Offset Against Collateral	1,635	3,505
Derivative Liability	0	-1,903
Long-term Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	-867
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	491
Derivative Liability	$0	($376)

INVESTMENTS_AND_DERIVATIVES_Na

INVESTMENTS AND DERIVATIVES Narrative (Details) (USD $)	3 Months Ended											12 Months Ended						0 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Feb. 17, 2012	Dec. 31, 2014	Dec. 31, 2011	Apr. 24, 2013	Jan. 28, 2014	Dec. 18, 2014
Derivative [Line Items]
Gain (loss) on disposal of discontinued operations, net of tax	$128,000	($258,000)	($5,212,000)	($8,513,000)	($31,421,000)	[1]	($69,521,000)	[1]	$172,452,000	[1]	$0	($13,855,000)	[2],[3]	$71,510,000	[2],[3]	$2,409,000	[2],[3]
Available-for-sale Securities	3,864,000				1,819,000							3,864,000		1,819,000		1,958,000			3,864,000	497,000
Loss from equity method investment												1,038,000		994,000		1,971,000
Equity Method Investments, Fair Value Disclosure	347,191,000				940,000							347,191,000		940,000		2,072,000			347,191,000	0
Available-for-sale securities, classified held-for-sale					147,000									147,000
Hunter Disposal LLC
Derivative [Line Items]
Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Shares																		1,846,722
Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Value																		2,600,000
Consideration received, value of preferred stock received																		2,200,000
Gain (loss) on disposal of discontinued operations, net of tax														2,409,000
Hunter Disposal LLC | Green Hunter Energy
Derivative [Line Items]
Consideration received, number of shares of preferred stock received																		88,000
Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Value	0				600,000							0		600,000					0
Eagle Ford Hunter
Derivative [Line Items]
Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Shares																					10,000,000
Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Value																					42,300,000
Penn Virginia
Derivative [Line Items]
Proceeds from Sale of Available-for-sale Securities														50,562,000
Gain (loss) on disposal of discontinued operations, net of tax														8,262,000
Series C Preferred Stock | Hunter Disposal LLC
Derivative [Line Items]
Consideration received, number of shares of preferred stock received																		88,000
Consideration received, value of preferred stock received																		1,900,000
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%
Consideration received, value of preferred stock received	1,300,000				1,700,000							1,300,000		1,700,000					1,300,000
Common Stock | Hunter Disposal LLC | Green Hunter Energy
Derivative [Line Items]
Consideration received, value of preferred stock received	1,300,000				2,100,000							1,300,000		2,100,000					1,300,000
New Standard Energy Texas LLC | Eagle Ford Shale Assets
Derivative [Line Items]
Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Shares																						65,650,000
Noncash or Part Noncash Divestiture Amount of Consideration Received Common Stock Value																						9,400,000
Disposal Group Including Discontinued Operation Price Of Stock On Sale Date																						$0.14
Investments | New Standard Energy Texas LLC | Eagle Ford Shale Assets
Derivative [Line Items]
Available-for-sale Securities		2,500,000
Eureka Hunter Holdings, LLC
Derivative [Line Items]
Percent ownership of subsidiaries	48.60%											48.60%							48.60%
Loss from equity method investment																			101,000
Eureka Hunter Holdings, LLC | Morgan Stanley Infrastructure (MSI)
Derivative [Line Items]
Percent ownership of subsidiaries	49.84%											49.84%							49.84%
Retained interest upon deconsolidation	$347,292,000											$347,292,000							$347,292,000				$347,300,000
[1]	(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.
[2]	(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[3]	(4)The Companybs 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.

LONGTERM_DEBT_Notes_Payable_De

LONG-TERM DEBT Notes Payable (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		16-May-12	Mar. 28, 2014
Debt Instrument [Line Items]
Total long-term debt, outstanding	$948,733,000		$883,845,000
Less: current portion	-10,770,000		-3,967,000
Total long-term debt	937,963,000		879,878,000
Assets held for sale, current portion	0		5,366,000
Assets held for sale, long term	0		162,687,000
Exchange Notes
Debt Instrument [Line Items]
Total long-term debt, outstanding	597,355,000
Senior Notes Payable due May 15, 2020
Debt Instrument [Line Items]
Total long-term debt, outstanding			597,230,000
Interest rate (as a percent)	9.75%				9.75%
Senior notes payable, unamortized discount (in dollars)	2,600,000		2,800,000,000		6,000,000
Various equipment and real estate notes payable with maturity January 2015 - April 2021
Debt Instrument [Line Items]
Total long-term debt, outstanding	22,238,000	[1]	18,615,000	[1]
Assets held for sale, current portion	163,000
Assets held for sale, long term	3,800,000
Interest rate, low end of the range (as a percent)	4.25%		4.25%
Interest rate, high end of the range (as a percent)	7.94%		7.94%
Credit Agreement due March 28, 2018, interest rate of 3.66 percent | Eureka Hunter Pipelines, LLC
Debt Instrument [Line Items]
Total long-term debt, outstanding	0	[2]	0	[2]
Term Loan [Member] | Eureka Hunter Pipelines, LLC
Debt Instrument [Line Items]
Total long-term debt, outstanding	0		50,000,000
Second lien term loan due October 22, 2019, interest rate of 8.5 percent
Debt Instrument [Line Items]
Total long-term debt, outstanding	329,140,000		0
Senior notes payable, unamortized discount (in dollars)	10,000,000
Senior Revolving Credit Facility
Debt Instrument [Line Items]
Total long-term debt, outstanding	0		218,000,000
Interest rate (as a percent)	2.92%		2.92%
Term Loan [Member] | Second lien term loan due October 22, 2019, interest rate of 8.5 percent
Debt Instrument [Line Items]
Interest rate (as a percent)	8.50%		8.50%
Term Loan [Member] | 12.5 Percent Term Loan due August 16, 2018 [Member]
Debt Instrument [Line Items]
Total long-term debt, outstanding						$50,000,000
Term Loan [Member] | 12.5 Percent Term Loan due August 16, 2018 [Member] | Eureka Hunter Pipelines, LLC
Debt Instrument [Line Items]
Interest rate (as a percent)	12.50%		12.50%
Line of Credit [Member] | Senior Revolving Credit Facility | 5.75 Percent Credit Agreement due March 28, 2018 [Member] | Eureka Hunter Pipeline LLC [Member]
Debt Instrument [Line Items]
Interest rate (as a percent)	3.66%		3.66%
[1]	Balance as of December 31, 2013 includes notes classified as liabilities associated with assets held for sale of which $0.2 million is current and $3.8 million is long term
[2]	As a result of the deconsolidation of Eureka Hunter Holdings, this loan or revolver was derecognized with Eureka Hunter Holdingsb other liabilities. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb

LONGTERM_DEBT_Expected_Annual_

LONG-TERM DEBT Expected Annual Maturities of Debt (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]
2015	$10,770
2016	12,129
2017	5,948
2018	3,959
2019	325,757
Thereafter	602,825
Total	$961,388

LONGTERM_DEBT_Senior_Notes_Det

LONG-TERM DEBT Senior Notes (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 13, 2012	16-May-12	22-May-12	Nov. 08, 2013
Debt Instrument [Line Items]
Proceeds from issuing Senior Notes	$0	$0	$596,907,000
Long-term Debt, Gross	961,388,000
Senior Notes
Debt Instrument [Line Items]
Proceeds from Issuance of Debt				150,000,000	450,000,000
Interest rate (as a percent)	9.75%				9.75%
Proceeds from issuing Senior Notes				149,900,000	431,200,000
Noninterest Expense Offering Cost				3,100,000	12,800,000
Senior notes payable, unamortized discount (in dollars)	2,600,000	2,800,000,000			6,000,000
Debt Instrument, Unamortized Premium				3,000,000
Long-term Debt, Gross							600,000,000
Debt Instrument, Penalty Interest Paid				1,100,000
Minimum Holding Percentage of Aggregate Principal Amount of Outstanding Debt Instruments	25.00%
Long Term Debt Redemption with Net Proceeds from Equity Offerings as Percentage of Principal Amount	35.00%
Long Term Debt Percentage of Principal Amount Outstanding Excluding Notes Held by Entity after Redemption with Net Proceeds from Equity Offerings Minimum	65.00%
Long Term Debt Redemption Periods after Closing Date of Equity Offering	180 days
Long Term Debt Redemption Price Due to Change of Control as Percentage of Principal Amount	101.00%
Senior Notes | On or After May15, 2016
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	104.88%
Senior Notes | After May 15, 2017
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	102.44%
Senior Notes | After May 15, 2018
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes | Prior to May 15, 2016
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Notes | Before May 15, 2015
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	109.75%
Baytex Energy Corporation USA, Ltd.
Debt Instrument [Line Items]
Business Acquisition, Cost of Acquired Entity, Purchase Price (Deprecated 2013-01-31)						$312,018,000
Option One | Senior Notes | Prior to May 15, 2016
Debt Instrument [Line Items]
Long-term Debt, Redemption Price Make-whole Premium, Percentage of Outstanding Principal	1.00%
Option Two [Member] | Senior Notes | Prior to May 15, 2016
Debt Instrument [Line Items]
Long-term Debt, Redemption Price Make-whole Premium, Percentage Added to Treasury Rate for Purposes of Calculating Make-whole Premium	5000.00%

LONGTERM_DEBT_Senior_Revolving

LONG-TERM DEBT Senior Revolving Credit Facility (Details) (USD $)	0 Months Ended		12 Months Ended	3 Months Ended
	6-May-14	Oct. 22, 2014	Dec. 31, 2014	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2013	16-May-12
Senior Notes
Debt Instrument [Line Items]
Senior notes payable, unamortized discount (in dollars)			$2,600,000			$2,800,000,000	$6,000,000
Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	325,000,000					232,500,000
Liens Percentage Used in Reserve Reports for Borrowing Base Determinations	90.00%					80.00%
Line of Credit Facility, Borrowing Capacity Increase Limit	750,000,000
Debt Instrument Required Minimum Ratio of Consolidated Current Assets to Consolidated Current Liabilities	1
Letter of credit facility | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	50,000,000					10,000,000
Period On or Before July 1, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility, Reduction of Borrowing Base	25,000,000
Line of Credit Facility, Reduction of Borrowing Base, Percent of Net Proceeds From Issuance of Common Equity	50.00%
Period July 1, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility, Reduction of Borrowing Base For Each Dollar Of Additional Senior Notes	0.25
Period May 6, 2014 Through July 1, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Period May 6, 2014 Through July 1, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Eurodollar
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.75%
Fiscal Quarter Ended March 31, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Debt Instrument, EBITDAX to Interest Expense	200.00%
Fiscal Quarters Ending June 30, 2014 and September 30, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Debt Instrument, EBITDAX to Interest Expense	225.00%
Debt Instrument Required Maximum Ratio of Total Debt to EBITDAX	4.75
Fiscal Quarter Ended December 31, 2014 And Each Fiscal Quarter Thereafter | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Debt Instrument, EBITDAX to Interest Expense	250.00%
Fiscal Quarter Ending December 31, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Debt Instrument Required Maximum Ratio of Total Debt to EBITDAX	4.5
Fiscal Quarter Ending March 31, 2015 and Each Quarter Thereafter | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement
Debt Instrument [Line Items]
Debt Instrument Required Maximum Ratio of Total Debt to EBITDAX	4.25
Minimum | Period From July 1, 2014 Through Date of Delivery of Compliance Certificate for Quarter Ending June 30, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Minimum | Period From July 1, 2014 Through Date of Delivery of Compliance Certificate for Quarter Ending June 30, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Eurodollar
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Minimum | Period From Delivery of Compliance Certificate and After | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Minimum | Period From Delivery of Compliance Certificate and After | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Eurodollar
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Maximum | Period From July 1, 2014 Through Date of Delivery of Compliance Certificate for Quarter Ending June 30, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.25%
Maximum | Period From July 1, 2014 Through Date of Delivery of Compliance Certificate for Quarter Ending June 30, 2014 | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Eurodollar
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.25%
Maximum | Period From Delivery of Compliance Certificate and After | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Maximum | Period From Delivery of Compliance Certificate and After | Line of Credit [Member] | Amendment to Third Amended and Restated Credit Agreement | Eurodollar
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Senior Revolving Credit Facility | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		50,000,000
Line of Credit Facility, Borrowing Capacity Increase Limit		250,000,000
Line Of Credit Facility, Interest Period Interval Period		3 months
Line of Credit Facility, Minimum Borrowing Capacity Availability as Percent of Borrowing Base		2.50%
Line Of Credit Facility, Covenant, Minimum Borrowing Capacity Availability		5,000,000
Line Of Credit Facility, Covenant, Minimum Borrowing Capacity Availability, Basket Per Year		45,000,000
Line Of Credit Facility, Present Value Of Proved Oil And Gas Reserves Lien, Percent		90.00%
Line Of Credit Facility, Present Value Of Proved Oil And Gas Reserves Lien, Discount Rate, Percent		10.00%
Senior Revolving Credit Facility | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018 | Federal Funds Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Senior Revolving Credit Facility | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018 | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Senior Revolving Credit Facility | Line of Credit [Member] | First Amendment [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant, Current Ratio			1
Debt Covenant, Maximum Allowable Investments in Oil and Gas Properties			2,000,000
Debt Instrument Covenant Allowed Maximum Investments In Subsidiary			2,000,000
Debt Instrument Covenant, Threshold for Liquidity Event, Arms Length Transaction			36,000,000
Debt Instrument Covenant, Threshold for Liquidity Event, Cash Proceeds Receivabed by Company or Restricted Subsidiary			73,000,000
Senior Revolving Credit Facility | Fiscal Quarter Ending December 31, 2014 | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Debt Instrument, Covenant, Current Ratio			1
Debt Instrument Covenant, Required Maximum Secured Net Debt To EBITDAX Ratio		2.5
Senior Revolving Credit Facility | Fiscal Quarter Ending March 31, 2016 | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Debt Instrument Covenant, Leverage Ratio Limitation On Netting Of Unencumbered Cash		100,000,000
Senior Revolving Credit Facility | Fiscal Quarter Ending March 31, 2015 | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Debt Instrument, Covenant, Current Ratio			0.75
Debt Instrument Covenant, Required Maximum Secured Net Debt To EBITDAX Ratio		2.5
Senior Revolving Credit Facility | Fiscal Quarter Ending June 30, 2015 And Each Fiscal Quarter Thereafter | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Debt Instrument, Covenant, Current Ratio			1
Debt Instrument Covenant, Required Maximum Secured Net Debt To EBITDAX Ratio		2
Senior Revolving Credit Facility | Minimum | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018 | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Senior Revolving Credit Facility | Minimum | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018 | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Senior Revolving Credit Facility | Maximum | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018 | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Senior Revolving Credit Facility | Maximum | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018 | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		3.00%
Term Loan | Line of Credit [Member] | Second Lien Term Loan Agreement
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		340,000,000
Senior notes payable, unamortized discount (in dollars)		10,200,000
Letter of credit facility | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		50,000,000
Line of Credit Facility, Commitment Fee Percentage		0.50%
Letter of credit facility | Line of Credit [Member] | Senior Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Line of Credit			($39,300,000)
Scenario, Forecast | Senior Revolving Credit Facility | Line of Credit [Member] | First Amendment [Member]
Debt Instrument [Line Items]
Debt Instrument Covenant, Liquidity Event not Met, Increase in Variable Rate					1.00%
Debt Instrument Covenant, Liquidity Event not Met, Increase in Commitment Fee					0.25%
Subsequent Event | Senior Revolving Credit Facility | Fiscal Quarter Ending December 31, 2014 | Line of Credit [Member] | Fourth Amended And Restated Credit Agreement, Maturing October 22, 2018
Debt Instrument [Line Items]
Debt Instrument, Covenant, Current Ratio				1	0.75
Prior to May 15, 2016 | Option Two [Member] | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Redemption Price Make-whole Premium, Percentage Added to Treasury Rate for Purposes of Calculating Make-whole Premium			5000.00%

LONGTERM_DEBT_Second_Lien_Term

LONG-TERM DEBT Second Lien Term Loan (Details) (Term Loan, Line of Credit [Member], Second Lien Term Loan Agreement, USD $)	0 Months Ended
	Oct. 22, 2014	Dec. 31, 2014	Oct. 22, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$340,000,000		$340,000,000
Line Of Credit Facility, Periodic Amortization, Principal, Percent	1.00%
Line Of Credit Facility, Covenant, Amount Outstanding In Addition To Loans Repaid Or Prepaid, Threshold	50,000,000		50,000,000
Line Of Credit Facility, Covenant, Indebtedness Threshold, Percent Of Adjusted Consolidated Net Tangible Assets	25.00%
Deferred Finance Costs, Gross		12,000,000
Fiscal Quarter Ending December 31, 2014
Debt Instrument [Line Items]
Debt Instrument, Covenant, Proved Reserves To Secured Debt Ratio, Minimum	1.5
Debt Instrument, Covenant, Proved Developed And Producing Reserves To Secured Debt Ratio, Minimum	1
Fiscal Quarter Ending March 31, 2016 And Any Fiscal Quarter Trailing Four-Quarter Period Then Ended
Debt Instrument [Line Items]
Debt Instrument Covenant, Leverage Ratio Limitation On Netting Of Unencumbered Cash	$100,000,000		$100,000,000
Debt Instrument Covenant, Required Maximum Secured Net Debt To EBITDAX Ratio	2.5
Option One | Federal Funds Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Option One | Adjusted One Month London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Option One | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	6.50%
Option Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Option Two [Member] | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	7.50%

LONGTERM_DEBT_Eureka_Hunter_Pi

LONG-TERM DEBT Eureka Hunter Pipeline Credit Agreement (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Mar. 28, 2014	Nov. 19, 2014
					lenders
Debt Instrument [Line Items]
Long-term Debt		$948,733,000	$883,845,000
Term Loan | 12.5 Percent Term Loan due August 16, 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt				50,000,000
Debt Instrument, Prepayment Penalty	2,200,000
Debt Instrument, Accrued Interest				1,500,000
Senior Revolving Credit Facility | Line of Credit [Member] | 5.75 Percent Credit Agreement due March 28, 2018 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				117,000,000	225,000,000
Line of Credit Facility, Borrowing Capacity Increase Limit				150,000,000
Deferred Finance Costs, Net				$1,200,000
Number of Financial Lenders				5	13

LONGTERM_DEBT_Equipment_and_Bu

LONG-TERM DEBT Equipment and Building Notes Payable (Details) (Notes Payable, Other Payables, USD $)	0 Months Ended
In Millions, unless otherwise specified	Jan. 21, 2014	Sep. 30, 2014
7.94 Percent Equipment Note Payable
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$5.60
Interest rate (as a percent)	7.94%
Term of debt instrument	48 months
4.875 Percent Building Note Payable
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$3.80
Interest rate (as a percent)		4.88%

LONGTERM_DEBT_Interest_Expense

LONG-TERM DEBT Interest Expense (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Interest expense incurred on debt, net of amounts capitalized		$76,784,000	$67,803,000	$44,447,000
Amortization and write-off of deferred financing costs		9,679,000	4,818,000	7,399,000
Interest Expense, Debt		86,463,000	72,621,000	51,846,000
Write off of Deferred Debt Issuance Cost	2,700,000
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 [Member]
Debt Instrument [Line Items]
Write off of Deferred Debt Issuance Cost	1,400,000
Term Loan | 12.5 Percent Term Loan due August 16, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, 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		$2,000,000	$2,600,000	$4,400,000

SHAREBASED_COMPENSATION_Stock_

SHARE-BASED COMPENSATION Stock Option and Stock Appreciation Rights Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options and Stock Appreciation Rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at beginning of the year	16,891,419	14,846,994	12,566,199
Weighted Average Exercise Price, beginning of the year	$5.69	$6.01	$5.64
Granted	0	4,937,575	4,978,750
Weighted Average Exercise Price, Granted	$0	$4.11	$6
Exercised	-2,375,273	-1,466,025	-1,304,050
Weighted Average Exercise Price, Exercised	$4.09	$3.66	$1.54
Forfeited or expired	-1,321,190	-1,427,125	-1,393,905
Weighted Average Exercise Price, Forfeited or Expired	$6.27	$5.51	$7.14
Outstanding at end of the year		16,891,419	14,846,994
Weighted Average Exercise Price, end of the year	$5.91	$5.69	$6.01
Exercisable at end of the year	9,140,323	9,983,743	8,683,622
Weighted Average Exercise Price, Exercisable at end of year	$6.22	$5.96	$5.97
Amended And Restated Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at end of the year	13,194,956

SHAREBASED_COMPENSATION_NonVes

SHARE-BASED COMPENSATION Non-Vested Common Stock (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options and Stock Appreciation Rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at beginning of the year	6,907,476	6,163,372	5,650,782
Granted	0	4,937,575	4,978,750
Vested	-1,915,526	-3,133,700	-3,405,434
Forfeited	-1,018,767	-1,059,771	-1,060,726
Non-vested at end of the year		6,907,476	6,163,372
Amended And Restated Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at end of the year	3,973,183

SHAREBASED_COMPENSATION_Fair_V

SHARE-BASED COMPENSATION Fair Value Assumptions (Details) (Common stock options, Weighted average, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Common stock options | Weighted average
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value per option granted during the period	$2.52	[1]	$3.72	[1]
Weighted average stock price volatility	80.61%	[2],[3]	82.64%	[2],[3]
Weighted average risk free rate of return	0.78%	[2]	0.77%	[2]
Weighted average estimated forfeiture rate	2.45%	[2],[4]	0.00%	[2],[4]
Weighted average expected term	4 years 7 months 24 days	[2]	4 years 6 months 4 days	[2]
[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.
[4]	For the year 2012, the Company estimated forfeitures to be zero based on the majority of options being granted to executive officers who are less likely to forfeit shares.

SHAREBASED_COMPENSATION_NonVes1

SHARE-BASED COMPENSATION Non-Vested Common Shares Granted Under the Stock Incentive Plan (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at beginning of the year	27,500	65,025	155,049
Weighted Average Share Price, beginning of the year	$7.24	$6.09	$4.43
Granted (in shares)	3,239,796	210,494	69,791
Weighted Average Share Price, Granted	$5.66	$4.66	$4.29
Forfeited	-170,000	0	0
Weighted Average Share Price, Forfeited	$7.26	$0	$0
Vested	-780,283	-248,019	-159,815
Weighted Average Share Price, Vested	$4.48	$4.75	$4.46
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 11 months 16 days
Non-vested at end of the year		27,500	65,025
Weighted Average Share Price, end of the year	$5.97	$7.24	$6.09
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$9.70	$0.20	$0.40
Amended And Restated Stock Incentive Plan | Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at end of the year	2,317,013

SHAREBASED_COMPENSATION_Narrat

SHARE-BASED COMPENSATION Narratives (Details) (USD $)	12 Months Ended			0 Months Ended			3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 06, 2014	Jan. 08, 2014	12-May-14	Dec. 31, 2014	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,500,000						27,500,000
Allocated Share-based Compensation Expense	$12.50	$13.60	$15.70
Restricted Stock [Member]
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
Stock Options and Stock Appreciation Rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	3.2	14.1	12.6				3.2
Share Based Compensation Arrangement by Share Based Payment Award Equity Instruments Including Options Outstanding Number		16,891,419	14,846,994					12,566,199
Share Based Compensation Arrangement by Share Based Payment Award Equity Instruments Including Options Nonvested Number		6,907,476	6,163,372					5,650,782
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	11 months 13 days
Share Based Compensation Arrangement by Share Based Payment Award Equity Instruments Including Options Nonvested Intrinsic Value	6.4						6.4
Share Based Compensation Arrangement by Share Based Payment Award Equity Instruments Including Options Outstanding Weighted Average Remaining Contractual Term	5 years 6 months 25 days
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	3,239,796	210,494	69,791
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	9.7	0.2	0.4				9.7
Non-vested number		27,500	65,025					155,049
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 11 months 16 days
Amended And Restated Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement by Share Based Payment Award Equity Instruments Including Options Outstanding Number	13,194,956						13,194,956
Share Based Compensation Arrangement by Share Based Payment Award Equity Instruments Including Options Nonvested Number	3,973,183						3,973,183
Amended And Restated Stock Incentive Plan | Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement by Share Based Payment Award Cumulative Number of Shares Issued	11,035,482						11,035,482
Non-vested number	2,317,013						2,317,013
Eureka Hunter Holdings, LLC Management Incentive Compensation Plan | Common Class B [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)						894,102	413,110
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized						2,336,905
Eureka Hunter Holdings, LLC Management Incentive Compensation Plan | Incentive Plan Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)						894,102	413,110
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized						2,336,905
Board of Directors | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross				216,348	123,798
Vesting Rights Percentage					100.00%
Stock Issued During Period, Value, Restricted Stock Award, Net of Forfeitures	18.5
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)	105,812	182,994
Officers Executives and Employees | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	3,275,033			1,451,500	1,312,575		65,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period				3 years	3 years
Vesting Rights Percentage				33.00%	33.00%
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Period for One Third of Shares				1 year	1 year
Share-based Compensation Arrangement by Share-based Payment Award, Plan Modification, Incremental Compensation Cost							2.6

SHAREHOLDERS_EQUITY_Warrant_Ac

SHAREHOLDERS' EQUITY Warrant Activity (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in warrant activity
Shares, Outstanding at beginning of year	17,169,010	13,376,277	13,525,832
Shares, Granted	2,142,858	17,030,622	0
Shares, Exercised, forfeited, or expired	-138,388	-13,237,889	-149,555
Shares, Outstanding at end of year	19,173,480	17,169,010	13,376,277
Shares, Exercisable at end of year	19,173,480	17,169,010	13,376,277
Changes in weighted-average exercise price
Weighted-Average Exercise Price, Outstanding at beginning of period (in dollars per share)	8.56	10.56	10.48
Weighted-Average Exercise Price, Granted	8.5	8.5	0
Weighted-Average Exercise Price, Exercised, forfeited, or expired (in dollars per share)	16.28	10.5	3.32
Weighted-Average Exercise Price, Outstanding at end of period (in dollars per share)	8.5	8.56	10.56
Weighted-Average Exercise Price, Exercisable at end of year (in dollars per share)	8.5	8.56	10.56

SHAREHOLDERS_EQUITY_Preferred_

SHAREHOLDERS' EQUITY Preferred Dividends Incurred (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Dividends on preferred stock	$54,707	$56,705	$34,706
Series C Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	10,248	10,248	10,248
Series D Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	17,698	17,655	11,699
Series E Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	7,418	7,561	894
Eureka Hunter Holdings, LLC | Series A Preferred Stock
Class of Stock [Line Items]
Dividends on preferred stock	12,760	14,323	8,090
Accretion of the difference between the carrying value and the redemption value of preferred stock included in dividends	$6,583	$6,918	$3,775

SHAREHOLDERS_EQUITY_Schedule_o

SHAREHOLDERS' EQUITY Schedule of Potentially Dilutive Securities (Details) (Dilutive [Member])	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	45,683	45,034	39,120
Series E Preferred Stock
Class of Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	10,946	10,946	10,897
Common stock options
Class of Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	13,195	16,891	14,847
Warrant [Member]
Class of Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	19,173	17,169	13,376
Restricted Stock [Member]
Class of Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,369	28	0

SHAREHOLDERS_EQUITY_Narratives

SHAREHOLDERS' EQUITY Narratives (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended				12 Months Ended	0 Months Ended			3 Months Ended	0 Months Ended		1 Months Ended
	16-May-12	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	9-May-14	Apr. 13, 2011	Mar. 30, 2012	Nov. 02, 2012	Dec. 31, 2008	Aug. 26, 2013	Aug. 13, 2011	3-May-11	Dec. 31, 2014	Sep. 07, 2012	Mar. 31, 2014	Dec. 31, 2012	Nov. 30, 2012	Jul. 24, 2014	Aug. 13, 2013	Apr. 02, 2012
Common Stock [Abstract]
Common stock issued in connection with share-based compensation (in shares)		657,317	182,994	108,397
Common stock issued upon warrant exercise (in shares)		2,375,273	1,466,025	1,438,275
Proceeds from exercise of common stock options		$9,700,000	$5,400,000	$2,300,000
Proceeds from stock issuance		0	10,072,000	144,635,000
Gross proceeds from stock issuance	148,200,000	178,410,000		148,241,000
Employee Stock Ownership Plan (ESOP), Compensation Expense		1,600,000	1,200,000	900,000
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share)			10.5	10.5												10.5
Class of Warrant or Right Number Of Days Notice Required For Redemption By Company		30 days
Common Stock Warrants Shares Exercisable		19,173,480	17,169,010	13,376,277									19,173,480			13,376,277
Proceeds from exercise of warrants				300,000
Warrants outstanding		0											0
Weighted average remaining contract life		1 year 3 months 15 days
Cumulative Perpetual Preferred Stock [Abstract]
Depositary shares returned and held in treasury				0
Common Stock Warrant [Member]
Common Stock Warrants [Abstract]
Number of warrants exercised					2,142,858
Exercise price of warrants (in dollars per share)					8.5
Redemption price of warrants (in dollars per share)					0.001
Class of Warrant or Right, Redemption Period Notice					30 days
$2.50 Common stock warrants
Common Stock Warrants [Abstract]
Number of warrants exercised				134,177
Exercise price of warrants (in dollars per share)				2.5												2.5
$10.50 Common stock warrants
Common Stock Warrants [Abstract]
Number of warrants exercised			13,237,889	48
Exercise price of warrants (in dollars per share)				10.5												10.5
Warrants expired (in shares)				15,330
$15.13 Common stock warrants
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share)		15.13											15.13
Common Stock Warrants Shares Exercisable		97,780											97,780
$19.04 Common stock warrants
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share)		19.04											19.04
Common Stock Warrants Shares Exercisable		40,608											40,608
Eureka Hunter Holdings, LLC
Non-controlling Interests [Abstract]
Percent ownership of subsidiaries		48.60%											48.60%
NGAS Resources, Inc.
Common Stock Warrants [Abstract]
Warrants outstanding						4,609,038
Exchange ratio of NGAS warrants into common stock warrants						8.46%
Period available to holder under cash out option						30 days
Cash paid on cash out option on warrants						1,000,000
Warrants opted cash out option (in shares)						251,536
Common Stock Warrants Shares Exercisable						389,924
Eagle Operating
Common Stock [Abstract]
Common stock issued in connection with acquisition (in shares)							296,859
Common stock issued in connection with acquisition							1,900,000
Common stock issued in connection with acquisition (in dollars per share)							$6.41
VIRCO
Common Stock [Abstract]
Common stock issued in connection with acquisition								65,209,000
Cumulative Perpetual Preferred Stock [Abstract]
Percentage of ownership interest acquired																	100.00%
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]
Stock issued (in shares)					21,428,580
Common stock issued (in dollars per share)					$7
Gross proceeds from stock issuance					149,700,000
Common Stock Warrants [Abstract]
Exercise price of warrants (in dollars per share)										8.5
Class of Warrant or Right, Warrants Fair Value										21,600,000
Redemption price of warrants (in dollars per share)		0.001
Class of Warrant or Right, Warrants Issued										17,030,622
Common Stock | Magnum Hunter Resources Corporation
Common Stock [Abstract]
Common stock issued as a matching contribution to the Employee Stock Ownership Plan (in shares)		249,531	221,170	199,055
Obligation to make future contributions to the plan		0											0
Employee Stock Ownership Plan (ESOP), Shares in ESOP		585,239											585,239
Unearned Common Stock in Employee Stock Ownership Plan [Abstract]
Shares returned to treasury											153,300
Treasury stock (in dollars per share)		$3.94											$3.94						$3.94
Common stock to be offered for sale or contributed to the Plan		153,300
Common Stock | Magnum Hunter Resources Corporation | Minimum
Unearned Common Stock in Employee Stock Ownership Plan [Abstract]
Number of discretionary matching contributions common stock may be contributed (one or more)																			1
Common Stock | Underwritten public offering
Common Stock [Abstract]
Stock issued (in shares)	35,000,000
Common stock issued (in dollars per share)	$4.50
Proceeds from stock issuance	157,500,000
Exchangeable common stock | NuLoch Resources
Common Stock [Abstract]
Common stock issued upon exchange of MHR Exchangeco Corporation's exchangeable shares (in shares)			505,835	3,188,036
Exchangeable Common Stock [Abstract]
Exchangeable shares issued for acquisition of NuLoch Resources (in shares)												4,275,998
Number of shares of common stock exchaged by each exchangeable share												1
Exchangeable shares issued for acquisition of NuLoch Resources												31,600,000
Exchangeable stock, time period from issuance the shares are redeemable		1 year
Series C Preferred Stock
Cumulative Perpetual Preferred Stock [Abstract]
Cumulative dividend rate for cumulative preferred stock (as a percent)		10.25%
Preferred stock par value (in dollars per share)		$0.01											$0.01
Non-controlling Interests [Abstract]
Common units issued		4,000,000	4,000,000										4,000,000
Series D Preferred Stock
Common Stock [Abstract]
Stock issued (in shares)			216,068	2,771,263
Proceeds from stock issuance			9,600,000	122,500,000
Cumulative Perpetual Preferred Stock [Abstract]
Cumulative dividend rate for cumulative preferred stock (as a percent)		8.00%	8.00%	8.00%									8.00%
Preferred stock par value (in dollars per share)		$0.01											$0.01
Preferred Stock, liquidation preference (in dollars per share)		$50	$50										$50
Offering expenses			1,200,000	3,100,000
Series D Preferred Stock | At the market sales agreement
Common Stock [Abstract]
Stock issued (in shares)				1,721,263
Proceeds from stock issuance				77,900,000
Cumulative Perpetual Preferred Stock [Abstract]
Offering expenses				1,500,000
Series D Preferred Stock | Underwritten public offering
Common Stock [Abstract]
Stock issued (in shares)														1,050,000
Common stock issued (in dollars per share)														$44
Proceeds from stock issuance														44,600,000
Cumulative Perpetual Preferred Stock [Abstract]
Offering expenses														1,600,000
Depositary shares
Class of Stock [Line Items]
Preferred Stock, Interest in Series E Preferred Stock per Share		0.001
Common Stock [Abstract]
Stock issued (in shares)																1,000,000
Common stock issued (in dollars per share)		$23.50	$24.24										$23.50		$7
Common stock issued in connection with acquisition (in shares)			27,906												4,300,000
Proceeds from stock issuance			590,000												28,900,000
Cumulative Perpetual Preferred Stock [Abstract]
Cumulative dividend rate for cumulative preferred stock (as a percent)		8.00%
Preferred Stock, liquidation preference (in dollars per share)		$25											$25
Conversion price (in dollars per share)		$8.50											$8.50
Proceeds from issuance of depositary shares (in dollars per share)																$22.44
Depositary shares | VIRCO
Common Stock [Abstract]
Common stock issued in connection with acquisition (in shares)								2,774,850									2,774,850
Cumulative Perpetual Preferred Stock [Abstract]
Depositary share issued into escrow account related to acquisition																	70,000
Depositary shares returned and held in treasury																	1,800,000
Series A Preferred Stock
Non-controlling Interests [Abstract]
Common units issued		9,885,048	9,885,048										9,885,048
Series A Preferred Stock | Eureka Hunter Holdings, LLC
Non-controlling Interests [Abstract]
Common units issued																				622,641
Value of common units issued related to acquisitions																				$12,500,000
Series E Preferred Stock
Cumulative Perpetual Preferred Stock [Abstract]
Cumulative dividend rate for cumulative preferred stock (as a percent)		8.00%	8.00%
Preferred stock par value (in dollars per share)		$0.01											$0.01
Preferred Stock, liquidation preference (in dollars per share)		$25,000	$25,000										$25,000
Conversion price (in dollars per share)		$8.50											$8.50
Series E Preferred Stock | VIRCO
Common Stock [Abstract]
Common stock issued in connection with acquisition (in shares)								2,774.85
Cumulative Perpetual Preferred Stock [Abstract]
Cumulative dividend rate for cumulative preferred stock (as a percent)								8.00%

REEDEMABLE_PREFERRED_STOCK_Det

REEDEMABLE PREFERRED STOCK (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 03, 2014	Dec. 14, 2011	Apr. 02, 2012	Mar. 21, 2012
Class of Stock [Line Items]
Proceeds from stock issuance	$0	$10,072,000	$144,635,000
Proceeds from sale of Series A preferred units in Eureka Hunter Holdings	11,956,000	35,280,000	149,655,000
Preferred stock, cash dividends paid	54,707,000	56,705,000	34,706,000
Preferred stock, dividends paid-in-kind	1,950,000	8,243,000	1,658,000
Fair Value Disclosure, Preferred Units Outstanding	389,000,000
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units	-51,692,000	0	0
Series C Preferred Stock
Class of Stock [Line Items]
Preferred Stock, shares issued	4,000,000	4,000,000
Temporary Equity Dividend Rate Percentage	10.25%	10.25%
Preferred stock par value per share	$0.01
Preferred Stock, liquidation preference (in dollars per share)	$25	$25
Preferred stock, redemption price per share at the Company's option					$25
Preferred stock, redemption price per share in the event of a change of control	$25
Series A Preferred Stock
Class of Stock [Line Items]
Preferred Stock, shares issued	9,885,048	9,885,048
Temporary Equity Dividend Rate Percentage	8.00%	8.00%
Preferred stock, cash dividends paid	10,200,000	5,200,000	3,400,000
Preferred stock, dividends accrued		3,900,000	3,000,000
Preferred stock, dividends paid-in-kind	1,900,000	8,200,000	1,700,000
Preferred stock issued as in-kind payment (in shares)	97,492	412,157	82,892
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 Hunter Holdings, LLC
Class of Stock [Line Items]
Preferred Stock, shares issued						622,641
Temporary Equity Dividend Rate Percentage	8.00%
Cumulative dividend rate for cumulative preferred stock increased (as a percent)	10.00%
Conversion ratio (as a percent)	1
Level 3 | Embedded Derivatives, Liabilities | Preferred Stock Embedded Derivative
Class of Stock [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements		-75,934,000		173,205,000
Ridgeline | Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock, maximum purchase commitment pursuant to Unit Purchase Agreement							200,000,000
Ridgeline | Series A Preferred Stock | Eureka Hunter Holdings, LLC
Class of Stock [Line Items]
Preferred Stock, shares issued	610,000	1,800,000	7,590,000
Proceeds from stock issuance	12,000,000	35,300,000	148,600,000
Proceeds from sale of Series A preferred units in Eureka Hunter Holdings	$200,000,000

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2009
Net operating loss carryforwards
Valuation Allowance, Deferred Tax Asset, Change in Amount	$56,200,000
Deferred income tax expense (benefit)
U.S. federal	0	-78,743,000	-24,584,000
Various states	0	-6,664,000	-81,000
Total deferred tax expense (benefit)	0	-85,407,000	-24,665,000
Total continuing operations	0	-85,407,000	-24,665,000
Reconciliation of income tax expense (benefit)
Income tax benefit at statutory U.S. rate	-48,242,000	-111,132,000	-53,908,000
State income taxes (net of federal benefit)	-3,616,000	-4,331,000	-53,000
Tax effect of permanent differences	-498,000	750,000	-555,000
Provision to return adjustment	-11,736,000	0	0
Foreign statutory tax rate differences	297,000	0	0
Tax effect of loss attributable to non-controlled interest	1,279,000	346,000	797,000
Tax benefit recognized as tax expense in discontinued operations	0	-28,989,000	0
Change in valuation allowance	63,341,000	58,341,000	29,047,000
Other	-825,000	-392,000	7,000
Total continuing operations	0	-85,407,000	-24,665,000
Discontinued operations	0	11,773,000	3,071,000
Total tax benefit	0	-73,634,000	-21,594,000
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest [Abstract]
Domestic	-134,853,000	-317,520,000	-154,022,000
Foreign	-2,980,000	0	0
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX	-137,833,000	-317,520,000	-154,022,000
Gain (loss) from discontinued operations	4,561,000	-62,655,000	-8,125,000
Gain (loss) on disposal of discontinued operations	-13,855,000	83,378,000	3,830,000
Loss before income tax	-147,127,000	-296,797,000	-158,317,000
Deferred tax assets:
Net operating loss carry forwards	263,452,000	155,507,000	193,310,000
Property and equipment	63,823,000	0	0
Capital loss carry forward	38,401,000	0	0
Share-based compensation	15,035,000	10,156,000	7,950,000
Depletion carry forwards	1,047,000	1,047,000	997,000
Tax credits	53,000	53,000	53,000
US investment in Canada	0	74,148,000	0
Other	1,562,000	561,000	532,000
Deferred tax liabilities:
Property and equipment	0	-90,950,000	-206,650,000
Valuation allowances
Tax credits	-53,000	-53,000	-53,000
Depletion carry forwards	-1,047,000	-1,047,000	-997,000
Capital loss carry forward	-38,401,000	0	0
Net operating losses	167,266,000	75,274,000	69,400,000
Net deferred tax asset (liability)	0	0	-74,258,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at January 1	3,879,000	3,879,000		0
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	3,879,000
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	3,879,000	3,879,000	3,879,000	0
Investments in Subsidiaries, Foreign, Valuation Allowance	0	-74,148,000	0
Deferred Tax Assets, Valuation Allowance	206,800,000
NOL from excess stock based compensation deductions
Deferred income tax expense (benefit)
Net operating loss carry forwards	38,100,000
Deferred tax assets:
Net operating loss carry forwards	14,800,000
U.S. federal income tax
Deferred income tax expense (benefit)
Net operating loss carry forwards	710,000,000
Depletion carryover	2,800,000
Depletion carryover, tax effected	1,100,000
Eureka Hunter Holdings, LLC
Deferred tax liabilities:
Investment in Eureka Hunter Holdings	-176,606,000	0	0
Discontinued Operations [Member]
Net operating loss carryforwards
Valuation Allowance, Deferred Tax Asset, Change in Amount	($7,100,000)

MAJOR_CUSTOMERS_Details

MAJOR CUSTOMERS (Details) (Revenues, Customer concentration)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Samson Resources Company
Major customers
Concentration percentage	24.00%	31.00%	17.00%
Teneska Marketing Ventures
Major customers
Concentration percentage	7.00%	11.00%	15.00%
Markwest Liberty Midstream [Member]
Major customers
Concentration percentage	15.00%	6.00%	0.00%
Baytex Energy USA LTD
Major customers
Concentration percentage	17.00%	10.00%	14.00%
Continuum Midstream, LLC [Member]
Major customers
Concentration percentage	5.00%	6.00%	13.00%
South Jersey [Member]
Major customers
Concentration percentage	2.00%	5.00%	14.00%
Plains Marketing, LP [Member]
Major customers
Concentration percentage	0.00%	4.00%	11.00%

RELATED_PARTY_TRANSACTIONS_Bal

RELATED PARTY TRANSACTIONS Balances and Activities (Details) (USD $)	0 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Feb. 17, 2012	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Related Party Transaction
Investment in affiliates, equity method		$347,191		$940
GreenHunter Resources, Inc.
Related Party Transaction
Accounts receivable (payable) - net		-228	[1]	23	[1]
Derivative assets		75	[1],[2]	79	[1],[2]
Investments		1,311	[1],[2]	2,262	[1],[2]
Notes receivable (2)		1,224	[1],[2]	1,768	[1],[2]
Prepaid expenses		1,000	[1]	9	[1]
Loss on investments		951	[2]	730	[2]	1,333	[2]
Related Party Transaction Rental Agreement Term	5 years
GreenHunter Resources, Inc. | Water disposal charges
Related Party Transaction
Related party expenses		4,682	[1]	3,033	[1]	2,400	[1]
GreenHunter Resources, Inc. | Rental expenses
Related Party Transaction
Related party expenses		291	[1]	282	[1]	1,000	[1]
GreenHunter Resources, Inc. | Gas gathering trucking
Related Party Transaction
Related party expenses		652	[1]	0	[1]	0	[1]
GreenHunter Resources, Inc. | MAG tank panels
Related Party Transaction
Related party expenses		800	[1]	0	[1]	0	[1]
GreenHunter Resources, Inc. | Office space rental
Related Party Transaction
Interest Income from Note Receivable		44		13		0
GreenHunter Resources, Inc. | Interest income from note receivable
Related Party Transaction
Interest Income from Note Receivable		154	[2]	205	[2]	191	[2]
Pilatus Hunter
Related Party Transaction
Accounts receivable (payable) - net		12		0
Percentage of ownership in related party by member of management		100.00%		100.00%		100.00%
Pilatus Hunter | Airplane rental expenses
Related Party Transaction
Related party expenses		281	[3]	166	[3]	174	[3]
Executive Officer | Corporate apartment rental
Related Party Transaction
Related party expenses		0	[4]	0	[4]	23	[4]
Eureka Hunter Holdings, LLC
Related Party Transaction
Accounts receivable (payable) - net		122	[5]	0	[5]
Investment in affiliates, equity method		347,191	[5]	0	[5]
Eureka Hunter Holdings, LLC | Transportation costs
Related Party Transaction
Related party expenses		353	[5]	0	[5]	0	[5]
Series C Preferred Stock | GreenHunter Resources, Inc.
Related Party Transaction
Proceeds from Dividends Received		$220	[2]	$220	[2]	$0	[2]
[1]	GreenHunter is an entity of which Gary C. Evans, the Company's Chairman and CEO, is the Chairman, a major shareholder and interim CEO. Eagle Ford Hunter received, and Triad Hunter and Virco., wholly-owned subsidiaries of the Company, receive services related to brine water and rental equipment from GreenHunter and its affiliated companies, White Top Oilfield Construction, LLC and Black Water Services, LLC. The Company believes that such services were and are provided at competitive market rates and were and are comparable to, or more attractive than, rates that could be obtained from unaffiliated third party suppliers of such services.
[2]	On February 17, 2012, the Company sold its wholly-owned subsidiary, Hunter Disposal, to GreenHunter Water, LLC (bGreenHunter Waterb), 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 bNote 9 - Fair Value of Financial Instrumentsb. The Company has recorded interest income as a result of the note receivable from GreenHunter. Also as a result of this transaction, the Company has an equity method investment in GreenHunter that is included in derivatives and other long-term assets and an available for sale investment in GreenHunter included in investments.
[3]	The Company rented an airplane for business use for certain members of Company management at various times from Pilatus Hunter, LLC, an entity 100% owned by Mr. Evans. Airplane rental expenses are recorded in general and administrative expense.
[4]	During the year ended December 31, 2012, the Company paid rent under a lease for a Houston, Texas corporate apartment from an executive of the Company, which apartment was used by other Company employees when in Houston for Company business. The lease terminated in May 2012.
[5]	Following a sequence of transactions up to and including, December 18, 2014, the Company no longer held a controlling financial interest in Eureka Hunter Holdings. The Company deconsolidated Eureka Hunter Holdings and accounts for its retained interest as of December 31, 2014 under the equity method of accounting. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb and bNote 10 - Investments and Derivativesb.

RELATED_PARTY_TRANSACTIONS_Nar

RELATED PARTY TRANSACTIONS Narratives (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 29, 2014	Feb. 17, 2012	Apr. 02, 2012
Related Party Transaction
Term of consulting agreement	12 months
GreenHunter Resources, Inc.
Related Party Transaction
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%
Kirk Trosclair [Member]
Related Party Transaction
Monthly compensation	10,000
Compensation (including reimbursement of expenses)	71,000
Common Class A [Member] | Eureka Hunter Holdings, LLC | Chief Executive Officer [Member]
Related Party Transaction
Common Units Issued During Period Shares Acquisitions				27,641
Eureka Hunter Pipeline Gas Gathering Agreement [Member]
Related Party Transaction
Oil and Gas Delivery Commitments and Contracts, Fixed Price	0.75
Amended and Restated Gas Gathering Services Agreement [Member]
Related Party Transaction
Administrative service fee	500,000
Margin on administrative services fee	1.50%

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES Future Minimum Gathering, Processing and Transportation Commitments (Details) (Gathering, processing, and transportation commitments, USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Gathering, processing, and transportation commitments
Other Commitments [Line Items]
2015	$11,567
2016	11,591
2017	11,567
2018	11,567
2019	11,567
Thereafter	$62,655

COMMITMENTS_AND_CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES Future Minimum Lease Commitments Under Non-Cancelable Operating Leases (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Future minimum base rentals of Transtex Hunter's non-cancelable leases
2015	$502
2016	239
2017	121
2018	124
2019	53
Thereafter	$0

COMMITMENTS_AND_CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES Narratives (Details) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

9 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Sep. 26, 2008

Dec. 31, 2014

Dec. 14, 2011

Jul. 24, 2014

Dec. 30, 2013

28-May-14

Sep. 30, 2014

Dec. 31, 2013

Aug. 18, 2014

Oct. 08, 2014

Oct. 30, 2014

Jun. 30, 2014

Apr. 24, 2013

Aug. 12, 2013

Jul. 01, 2014

Oct. 21, 2014

Jul. 25, 2014

Well

officer

acre

Alpha Hunter Drilling LLC

Commitments

Equity Method Investment, Ownership Percentage

100.00%

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

Remaining maximum liability

640,695

Lease Commitments | Houston, Texas

Commitments

Lease cost

33,800

Lease Commitments | Grapevine, Texas [Member]

Commitments

Lease cost

4,800

Lease Commitments | Triad Hunter | Maximum

Commitments

Term of commitment

12 months

Gathering, processing, and transportation commitments

Commitments

Term of commitment

120 months

Gathering, processing, and transportation commitments | Triad Hunter

Commitments

Remaining maximum liability

3,100,000

Term of commitment

120 months

Gathering, processing, and transportation commitments | Eureka Hunter Pipelines, LLC

Commitments

Remaining maximum liability

19,400,000

Class action complaint filed by Horace Carvalho

Commitments

Number of the Company's officers subject to class action complaint

2

PRC Williston vs. Drawbridge Special Opportunities Fund LP And Fortress Value Recovery Fund I LLC D.B. Zwirn Special Opportunities Fund, L.P. [Member]

Commitments

Credit Agreement, Collective Interest In Distributions

12.50%

Litigation Settlement, Amount

2,900,000

PRC Williston vs. Drawbridge Special Opportunities Fund LP And Fortress Value Recovery Fund I LLC D.B. Zwirn Special Opportunities Fund, L.P. [Member] | PRC Williston Inc

Commitments

Proceeds from Sale of Productive Assets

5,000,000

The Company, PRC Williston vs. Drawbridge Special Opportunities Fund LP [Member]

Commitments

Settlement agreement percentage

100.00%

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

Commitments

Litigation Settlement, Amount

500,000

Seminole Energy Services, Settlement Agreement [Member] | Southern Appalachia [Member]

Commitments

Litigation Settlement, Amount

450,000

Number Of Wells Not Drilled

2

Number Of Wells, Required Drilling, Total

4

Utica Shale Assets Acquisition

Commitments

Net mineral acres acquired

32,000

Payments to Acquire Land

24,600,000

Eureka Hunter Pipeline Gas Gathering Agreement [Member]

Commitments

Remaining maximum liability

98,000,000

Daily quantity committed production

135,000

Aggregate reservation fee

0.75

Eureka Hunter Pipeline Gas Gathering Agreement [Member] | Minimum

Commitments

Pipeline Project Term Of Agreement

8 years

Eureka Hunter Pipeline Gas Gathering Agreement [Member] | Maximum

Commitments

Pipeline Project Term Of Agreement

14 years

Texas Gas Transportation Services Agreement, MMBtu Per Day Of Transportation Capacity [Member]

Commitments

Remaining maximum liability

12,800,000

Business Combination, Acquired Notional Amount Energy Measure Per Day

100,000

Pipeline Project Term Of Agreement

15 years

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

Commitments

Remaining maximum liability

16,400,000

Business Combination, Acquired Notional Amount Energy Measure Per Day

100,000

Pipeline Project Term Of Agreement

15 years

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

Commitments

Business Combination, Acreage Of Undeveloped Leasehold Acquired

16,456

5,922

Payments to Acquire Land

67,300,000

Escrow Deposit Disbursements Related to Property Acquisition

400,000

Consideration Transferred

67,700,000

Leasehold Acreage From MNW Energy, LLC [Member]

Commitments

Business Combination, Percentage of Total Leasehold Acres Purchased

70.00%

Business Combination, Net Leasehold Acres Purchased, Acquired to Date

22,379

Gas Gathering and Processing Equipment [Member] | Seminole Energy Services, Settlement Agreement [Member] | Muhlenberg County, Kentucky [Member]

Commitments

Percentage of ownership interest acquired

50.00%

Drilling Rig Purchase [Member] | Alpha Hunter Drilling LLC

Commitments

Payments to Acquire Oil and Gas Equipment

6,500,000

Business Combination, Deposit

1,300,000

Amended and Restated Gas Gathering Services Agreement [Member]

Commitments

Administrative service fee

500,000

Margin on administrative services fee

1.50%

Credit Support Agreement With REX (Rockies Express Pipeline LLC) [Member] | Line of Credit [Member] | Letter of credit facility | Triad Hunter

Commitments

Line Of Credit Facility, Maximum Borrowing Capacity, Required Period

45 days

Line of Credit Facility, Maximum Borrowing Capacity

36,900,000

Period Between Fourteen Months After and Twenty One Months From August 18, 2014 [Member] | Credit Support Agreement With TGT [Member] | Line of Credit [Member] | Letter of credit facility | Triad Hunter

Commitments

Line of Credit Facility, Maximum Borrowing Capacity

13,000,000

Period Between Twenty One Months After and Twenty Eight Months From August 18, 2014 [Member] | Credit Support Agreement With TGT [Member] | Line of Credit [Member] | Letter of credit facility | Triad Hunter

Commitments

Line of Credit Facility, Maximum Borrowing Capacity

36,000,000

Period Beginning Twenty Eight Months After August 18, 2014 [Member] | Credit Support Agreement With TGT [Member] | Line of Credit [Member] | Letter of credit facility | Triad Hunter

Commitments

Line of Credit Facility, Maximum Borrowing Capacity

65,000,000

Eagle Ford Hunter

Commitments

Liabilities of Disposal Group, Including Discontinued Operation

33,700,000

Disposal Group, Including Discontinued Operation, Accrued Liabilities

1,300,000

Disposal Group, Working Capital Adjustments, Basis For Liability Claims

$7,800,000

SUPPLEMENTAL_CASH_FLOW_INFORMA2

SUPPLEMENTAL CASH FLOW INFORMATION (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Significant Noncash Transactions [Line Items]
Cash paid for interest	$73,192,000	$67,736,000	$35,669,000
Cash paid for taxes	0	1,000	0
Non-cash transactions
Change in accrued capital expenditures - increase (decrease)	127,068,000	-65,634,000	34,621,000
Eureka Hunter Holdings, LLC Series A convertible preferred unit dividends paid in kind	1,950,000	8,243,000	1,658,000
Non-cash additions to asset retirement obligation	3,426,000	2,132,000	8,492,000
Common stock issued for 401k matching contributions	1,593,000	1,192,000	874,000
Preferred stock issued for acquisitions			64,968,000
Eureka Hunter Holdings, LLC Class A common units issued for an acquisition	0	0	12,453,000
Non-cash consideration received from sale of assets	9,447,000	42,300,000	7,120,000
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units	-51,692,000	0	0
Common stock issued for acquisitions			1,902,000
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	$21,600,000

SEGMENT_REPORTING_Details

SEGMENT REPORTING (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenue, Net	$59,854	[1]	$79,670	[1]	$138,463	[1]	$113,482	$90,179		$78,291	$76,686	$59,382	$391,469		$304,538		$159,937
Depreciation, depletion, amortization and accretion													146,868		107,385		72,438
Gain (Loss) on Disposition of Assets for Financial Service Operations													2,456		-44,641		-596
Operating Expenses													737,415		387,305		213,563
Income tax benefit													0		85,407		24,665
Interest income													156		265		202
Nonoperating Income (Expense)													352,525		-82,727		-27,362
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest													-137,833		-317,520		-154,022
Income (loss) from discontinued operations, net of tax													-9,294		8,949		-7,364
NET LOSS													-147,127		-223,164		-136,721
Assets	1,669,829							1,856,651					1,669,829		1,856,651		2,198,632
Total capital expenditures													700,608		570,712	[2]	1,110,858	[2]
Investment in affiliates, equity method	347,191							940					347,191		940
Investment in affiliates, equity method	347,191							350					347,191		350
U.S. Upstream
Segment Reporting Information [Line Items]
Revenue, Net													270,615		225,498		134,339
Depreciation, depletion, amortization and accretion													127,607		92,713		65,040
Gain (Loss) on Disposition of Assets for Financial Service Operations													2,075		-44,629		-246
Operating Expenses													556,085		267,935		167,423
Income tax benefit															56,418		24,665
Nonoperating Income (Expense)													1,340		-656		-10,210
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest													-409,662		-180,435		-108,580
Income (loss) from discontinued operations, net of tax													-7,155		159,225		18,856
NET LOSS													-416,817		35,208		-65,059
Assets	1,162,732							1,373,041					1,162,732		1,373,041		1,602,022
Total capital expenditures													470,538		444,385	[2]	927,456	[2]
Canadian Upstream
Segment Reporting Information [Line Items]
Revenue, Net													0		0		0
Depreciation, depletion, amortization and accretion													0		0		0
Gain (Loss) on Disposition of Assets for Financial Service Operations													0		0		0
Operating Expenses													0		0		0
Income tax benefit															0		0
Nonoperating Income (Expense)													0		0		0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest													0		0		0
Income (loss) from discontinued operations, net of tax													10,636		-150,207		-25,021
NET LOSS													10,636		-150,207		-25,021
Assets	0							68,367					0		68,367		392,918
Total capital expenditures													305		15,352	[2]	86,612	[2]
Midstream
Segment Reporting Information [Line Items]
Revenue, Net													109,658	[3]	69,306	[3]	15,692	[3]
Depreciation, depletion, amortization and accretion													15,737	[3]	12,318	[3]	5,963	[3]
Gain (Loss) on Disposition of Assets for Financial Service Operations													12	[3]	-8	[3]	250	[3]
Operating Expenses													93,138	[3]	60,497	[3]	11,706	[3]
Income tax benefit															0	[3]	0	[3]
Nonoperating Income (Expense)													-99,221	[3]	-22,358	[3]	7,388	[3]
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest													-98,426	[3]	-25,875	[3]	5,661	[3]
Income (loss) from discontinued operations, net of tax													0	[3]	0	[3]	0	[3]
NET LOSS													-98,426	[3]	-25,875	[3]	5,661	[3]
Assets	454	[3]						296,739	[3]				454	[3]	296,739	[3]	245,207	[3]
Total capital expenditures													221,455	[3]	87,498	[2],[3]	84,348	[2],[3]
Percentage of revenues													38.60%		40.70%		71.60%
Oil Field Services
Segment Reporting Information [Line Items]
Revenue, Net													31,392		21,527		13,552
Depreciation, depletion, amortization and accretion													3,524		2,354		967
Gain (Loss) on Disposition of Assets for Financial Service Operations													369		-4		-600
Operating Expenses													26,642		19,252		10,838
Income tax benefit															0		0
Nonoperating Income (Expense)													-813		-507		-482
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest													782		-590		665
Income (loss) from discontinued operations, net of tax													0		0		145
NET LOSS													782		-590		810
Assets	46,995							44,193					46,995		44,193		23,810
Total capital expenditures													8,079		22,440	[2]	11,657	[2]
Corporate Unallocated
Segment Reporting Information [Line Items]
Revenue, Net													0	[4]	0		0
Depreciation, depletion, amortization and accretion													0	[4]	0		0
Gain (Loss) on Disposition of Assets for Financial Service Operations													0	[4]	0		0
Operating Expenses													81,746	[4]	49,241		27,137
Income tax benefit															28,989		0
Nonoperating Income (Expense)													454,921	[4]	-61,446		-24,121
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest													373,175	[4]	-110,687		-51,258
Income (loss) from discontinued operations, net of tax													-12,775	[4]	0		0
NET LOSS													360,400	[4]	-81,698		-51,258
Assets	462,025	[4]						77,684					462,025	[4]	77,684		93,612
Total capital expenditures													231	[4]	1,037	[2]	785	[2]
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue, Net													-20,196		-11,793		-3,646
Depreciation, depletion, amortization and accretion													0		0		468
Gain (Loss) on Disposition of Assets for Financial Service Operations													0		0		0
Operating Expenses													-20,196		-9,620		-3,541
Income tax benefit															0		0
Nonoperating Income (Expense)													-3,702		2,240		63
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest													-3,702		67		-510
Income (loss) from discontinued operations, net of tax													0		-69		-1,344
NET LOSS													-3,702		-2		-1,854
Assets	-2,377							-3,373					-2,377		-3,373		-158,937
Total capital expenditures													$0		$0	[2]	$0	[2]
[1]	(1) 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.
[2]	Presentation of capital expenditures has been changed from prior year presentation in order to reflect capital expenditures incurred rather than cash paid for capital expenditures.
[3]	Includes operations of Eureka Hunter Holdings, which represents approximately 38.6%, 40.7%, and 71.6% of Midstream and Marketing revenues for the years ended DecemberB 31, 2014, 2013, and 2012, respectively, and which was deconsolidated as of December 18, 2014. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb.
[4]	Includes the Companybs retained interest in Eureka Hunter Holdings which has a value of $347 million at December 31, 2014.

CONDENSED_CONSOLIDATED_GUARANT2

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
ASSETS
Current assets	$120,196	$120,726
Property and equipment (using successful efforts accounting)	1,175,658	1,514,079
Investment in affiliates, equity method	347,191	940
Total assets	1,669,829	1,856,651	2,198,632
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	168,445	183,865
Redeemable preferred stock	100,000	236,675
Shareholders' equity	431,855	450,730	711,652	490,652
Total liabilities and shareholdersb equity	1,669,829	1,856,651
Magnum Hunter Resources Corporation | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
ASSETS
Current assets	85,647	53,161
Intercompany accounts receivable	1,113,417	965,138
Property and equipment (using successful efforts accounting)	5,506	7,214
Investment in subsidiaries	-91,595	372,236
Investment in affiliates, equity method	347,191
Other assets	22,804	17,308
Total assets	1,482,970	1,415,057
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	25,347	54,826
Intercompany accounts payable	0	0
Long-term liabilities	925,767	818,651
Redeemable preferred stock	100,000	100,000
Shareholders' equity	431,856	441,580
Total liabilities and shareholdersb equity	1,482,970	1,415,057
Guarantor Subsidiaries | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
ASSETS
Current assets	36,338	43,841
Intercompany accounts receivable	0	0
Property and equipment (using successful efforts accounting)	1,170,122	1,272,027
Investment in subsidiaries	94,134	102,314
Investment in affiliates, equity method	0
Other assets	3,980	100,894
Total assets	1,304,574	1,519,076
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	142,914	97,520
Intercompany accounts payable	1,073,091	921,237
Long-term liabilities	43,762	39,067
Redeemable preferred stock	0	0
Shareholders' equity	44,807	461,252
Total liabilities and shareholdersb equity	1,304,574	1,519,076
Non Guarantor Subsidiaries | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
ASSETS
Current assets	589	27,096
Intercompany accounts receivable	0	0
Property and equipment (using successful efforts accounting)	30	234,838
Investment in subsidiaries	0	0
Investment in affiliates, equity method	0
Other assets	0	103,644
Total assets	619	365,578
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	2,567	34,929
Intercompany accounts payable	42,560	43,866
Long-term liabilities	0	127,663
Redeemable preferred stock	0	136,675
Shareholders' equity	-44,508	22,445
Total liabilities and shareholdersb equity	619	365,578
Eliminations | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
ASSETS
Current assets	-2,378	-3,372
Intercompany accounts receivable	-1,113,417	-965,138
Property and equipment (using successful efforts accounting)	0	0
Investment in subsidiaries	-2,539	-474,550
Investment in affiliates, equity method	0
Other assets	0	0
Total assets	-1,118,334	-1,443,060
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	-2,383	-3,410
Intercompany accounts payable	-1,115,651	-965,103
Long-term liabilities	0	0
Redeemable preferred stock	0	0
Shareholders' equity	-300	-474,547
Total liabilities and shareholdersb equity	-1,118,334	-1,443,060
Magnum Hunter Resources Corporation Consolidated | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
ASSETS
Current assets	120,196	120,726
Intercompany accounts receivable	0	0
Property and equipment (using successful efforts accounting)	1,175,658	1,514,079
Investment in subsidiaries	0	0
Investment in affiliates, equity method	347,191
Other assets	26,784	221,846
Total assets	1,669,829	1,856,651
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities	168,445	183,865
Intercompany accounts payable	0	0
Long-term liabilities	969,529	985,381
Redeemable preferred stock	100,000	236,675
Shareholders' equity	431,855	450,730
Total liabilities and shareholdersb equity	$1,669,829	$1,856,651

CONDENSED_CONSOLIDATED_GUARANT3

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Statements of Operations (Details) (USD $)	3 Months Ended														12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Condensed consolidating statements of operations
Total revenue	$59,854	[1]	$79,670	[1]	$138,463	[1]	$113,482	$90,179		$78,291		$76,686		$59,382	$391,469		$304,538		$159,937
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX															-137,833		-317,520		-154,022
Income tax benefit															0		85,407		24,665
LOSS FROM CONTINUING OPERATIONS, NET OF TAX	103,320	[2]	-123,189	[2]	-61,407	[2]	-56,557	-14,382		-152,513		-3,634		-61,584	-137,833		-232,113		-129,357
Income from discontinued operations, net of taxes															-9,294		8,949		-7,364
Gain (loss) on disposal of discontinued operations, net of tax	128		-258		-5,212		-8,513	-31,421	[3]	-69,521	[3]	172,452	[3]	0	-13,855	[4],[5]	71,510	[4],[5]	2,409	[4],[5]
Net income (loss)															-147,127		-223,164		-136,721
Net loss attributable to non-controlling interests															3,653		988		4,013
Net loss attributable to Magnum Hunter Resources Corporation	103,448		-120,683		-64,647		-61,592	-46,537		-296,882		165,440		-44,197	-143,474		-222,176		-132,708
Dividends on preferred stock															-54,707		-56,705		-34,706
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units															-51,692		0		0
Net loss attributable to common shareholders	42,767		-136,175		-79,997		-76,468	-61,208		-311,299		151,311		-57,685	-249,873		-278,881		-167,414
Magnum Hunter Resources Corporation | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Condensed consolidating statements of operations
Total revenue															142		2,629		729
Expenses															-370,646		112,754		54,047
Loss from continuing operations before equity in net income of subsidiaries															370,788		-110,125		-53,318
Equity in net income of subsidiaries															-513,580		-298,775		-102,545
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX															-142,792		-408,900		-155,863
Income tax benefit															0		28,989		11,290
LOSS FROM CONTINUING OPERATIONS, NET OF TAX															-142,792		-379,911		-144,573
Income from discontinued operations, net of taxes															0		-7,813		0
Gain (loss) on disposal of discontinued operations, net of tax															-20,027		144,378		0
Net income (loss)															-162,819		-243,346		-144,573
Net loss attributable to non-controlling interests															0		0		0
Net loss attributable to Magnum Hunter Resources Corporation															-162,819		-243,346		-144,573
Dividends on preferred stock															-35,364		-35,464		-22,842
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units															-51,692
Net loss attributable to common shareholders															-249,875		-278,810		-167,415
Guarantor Subsidiaries | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Condensed consolidating statements of operations
Total revenue															368,537		277,854		141,772
Expenses															772,355		461,173		212,071
Loss from continuing operations before equity in net income of subsidiaries															-403,818		-183,319		-70,299
Equity in net income of subsidiaries															-8,181		-424		458
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX															-411,999		-183,743		-69,841
Income tax benefit															0		56,422		13,375
LOSS FROM CONTINUING OPERATIONS, NET OF TAX															-411,999		-127,321		-56,466
Income from discontinued operations, net of taxes															0		22,661		-209
Gain (loss) on disposal of discontinued operations, net of tax															97		0		2,409
Net income (loss)															-411,902		-104,660		-54,266
Net loss attributable to non-controlling interests															0		0		0
Net loss attributable to Magnum Hunter Resources Corporation															-411,902		-104,660		-54,266
Dividends on preferred stock															0		0		0
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units															0
Net loss attributable to common shareholders															-411,902		-104,660		-54,266
Non Guarantor Subsidiaries | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Condensed consolidating statements of operations
Total revenue															43,611		35,848		21,080
Expenses															144,714		59,991		32,487
Loss from continuing operations before equity in net income of subsidiaries															-101,103		-24,143		-11,407
Equity in net income of subsidiaries															0		0		-23,362
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX															-101,103		-24,143		-34,769
Income tax benefit															0		-4		0
LOSS FROM CONTINUING OPERATIONS, NET OF TAX															-101,103		-24,147		-34,769
Income from discontinued operations, net of taxes															4,561		-77,340		-9,564
Gain (loss) on disposal of discontinued operations, net of tax															6,075		-72,868		0
Net income (loss)															-90,467		-174,355		-44,333
Net loss attributable to non-controlling interests															0		0		0
Net loss attributable to Magnum Hunter Resources Corporation															-90,467		-174,355		-44,333
Dividends on preferred stock															-19,343		-21,241		-11,864
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units															0
Net loss attributable to common shareholders															-109,810		-195,596		-56,197
Eliminations | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Condensed consolidating statements of operations
Total revenue															-20,821		-11,793		-3,644
Expenses															-17,121		-11,860		15,354
Loss from continuing operations before equity in net income of subsidiaries															-3,700		67		-18,998
Equity in net income of subsidiaries															521,761		299,199		125,449
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX															518,061		299,266		106,451
Income tax benefit															0		0		0
LOSS FROM CONTINUING OPERATIONS, NET OF TAX															518,061		299,266		106,451
Income from discontinued operations, net of taxes															0		-69		0
Gain (loss) on disposal of discontinued operations, net of tax															0		0		0
Net income (loss)															518,061		299,197		106,451
Net loss attributable to non-controlling interests															3,653		988		4,013
Net loss attributable to Magnum Hunter Resources Corporation															521,714		300,185		110,464
Dividends on preferred stock															0		0		0
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units															0
Net loss attributable to common shareholders															521,714		300,185		110,464
Magnum Hunter Resources Corporation Consolidated | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Condensed consolidating statements of operations
Total revenue															391,469		304,538		159,937
Expenses															529,302		622,058		313,959
Loss from continuing operations before equity in net income of subsidiaries															-137,833		-317,520		-154,022
Equity in net income of subsidiaries															0		0		0
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX															-137,833		-317,520		-154,022
Income tax benefit															0		85,407		24,665
LOSS FROM CONTINUING OPERATIONS, NET OF TAX															-137,833		-232,113		-129,357
Income from discontinued operations, net of taxes															4,561		-62,561		-9,773
Gain (loss) on disposal of discontinued operations, net of tax															-13,855		71,510		2,409
Net income (loss)															-147,127		-223,164		-136,721
Net loss attributable to non-controlling interests															3,653		988		4,013
Net loss attributable to Magnum Hunter Resources Corporation															-143,474		-222,176		-132,708
Dividends on preferred stock															-54,707		-56,705		-34,706
Loss on extinguishment of Eureka Hunter Holdings Series A Preferred Units															-51,692
Net loss attributable to common shareholders															($249,873)		($278,881)		($167,414)
[1]	(1) 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.
[2]	(3) 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 Hunter 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 $510 million from the deconsolidation of Eureka Hunter Holdings. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb.
[3]	(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.
[4]	(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[5]	(4)The Companybs 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.

CONDENSED_CONSOLIDATED_GUARANT4

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Statements of Comprehensive Income (Loss) (Details) (USD $)	9 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income (loss)		($147,127)	($223,164)	($136,721)
Foreign currency translation gain (loss)		-1,204	-10,928	3,883
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax		-7,401	-84	-309
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, Tax		0	8,262	0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities	20,700	20,741	0	0
Comprehensive loss		-134,991	-234,176	-133,147
Comprehensive loss attributable to non-controlling interests		3,653	988	4,013
Comprehensive loss attributable to Magnum Hunter Resources Corporation		-131,338	-233,188	-129,134
9.75 Percent Senior Notes Due May 15, 2020 [Member] | Magnum Hunter Resources Corporation
Net income (loss)		-162,819	-243,346	-144,573
Foreign currency translation gain (loss)		0	0	0
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax		0	8,262	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, Tax			-8,262
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		20,741
Comprehensive loss		-142,078	-243,346	-144,573
Comprehensive loss attributable to non-controlling interests		0	0	0
Comprehensive loss attributable to Magnum Hunter Resources Corporation		-142,078	-243,346	-144,573
9.75 Percent Senior Notes Due May 15, 2020 [Member] | Wholly-Owned Guarantor Subsidiaries
Net income (loss)		-411,902	-104,660	-54,266
Foreign currency translation gain (loss)		0	0	0
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax		-7,401	-84	-309
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, Tax			0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		0
Comprehensive loss		-419,303	-104,744	-54,575
Comprehensive loss attributable to non-controlling interests		0	0	0
Comprehensive loss attributable to Magnum Hunter Resources Corporation		-419,303	-104,744	-54,575
9.75 Percent Senior Notes Due May 15, 2020 [Member] | Non Guarantor Subsidiaries
Net income (loss)		-90,467	-174,355	-44,333
Foreign currency translation gain (loss)		-1,204	-10,928	3,883
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, Tax			0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		0
Comprehensive loss		-91,671	-185,283	-40,450
Comprehensive loss attributable to non-controlling interests		0	0	0
Comprehensive loss attributable to Magnum Hunter Resources Corporation		-91,671	-185,283	-40,450
9.75 Percent Senior Notes Due May 15, 2020 [Member] | Eliminations
Net income (loss)		518,061	299,197	106,451
Foreign currency translation gain (loss)		0	0	0
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, Tax			0
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		0
Comprehensive loss		518,061	299,197	106,451
Comprehensive loss attributable to non-controlling interests		3,653	988	4,013
Comprehensive loss attributable to Magnum Hunter Resources Corporation		521,714	300,185	110,464
9.75 Percent Senior Notes Due May 15, 2020 [Member] | Magnum Hunter Resources Corporation Consolidated
Net income (loss)		-147,127	-223,164	-136,721
Foreign currency translation gain (loss)		-1,204	-10,928	3,883
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax		-7,401	8,178	-309
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, Tax			-8,262
Amounts reclassified from accumulated other comprehensive income upon sale of available for sale securities		20,741
Comprehensive loss		-134,991	-234,176	-133,147
Comprehensive loss attributable to non-controlling interests		3,653	988	4,013
Comprehensive loss attributable to Magnum Hunter Resources Corporation		($131,338)	($233,188)	($129,134)

CONDENSED_CONSOLIDATED_GUARANT5

CONDENSED CONSOLIDATED GUARANTOR FINANCIAL STATEMENTS -Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	($18,665)	$111,711	$58,011
Cash flow from investing activities	-318,119	-127,860	-1,009,207
Cash flow from financing activities	348,195	656	996,442
Effect of foreign exchange rate changes on cash	56	-417	-2,474
Net change in cash and cash equivalents	11,467	-15,910	42,772
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	41,713	57,623	14,851
CASH AND CASH EQUIVALENTS, END OF YEAR	53,180	41,713	57,623
Magnum Hunter Resources Corporation | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	-347,898	-371,351	-458,921
Cash flow from investing activities	107,595	422,303	-364,045
Cash flow from financing activities	250,194	-29,929	831,080
Effect of foreign exchange rate changes on cash	0	0	0
Net change in cash and cash equivalents	9,891	21,023	8,114
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	47,895	26,872	18,758
CASH AND CASH EQUIVALENTS, END OF YEAR	57,786	47,895	26,872
Guarantor Subsidiaries | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	255,088	397,213	281,782
Cash flow from investing activities	-248,928	-411,473	-287,204
Cash flow from financing activities	301	796	1,781
Effect of foreign exchange rate changes on cash	0	0	0
Net change in cash and cash equivalents	6,461	-13,464	-3,641
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	-17,651	-4,187	-546
CASH AND CASH EQUIVALENTS, END OF YEAR	-11,190	-17,651	-4,187
Non Guarantor Subsidiaries | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	74,145	99,153	236,360
Cash flow from investing activities	-176,786	-138,690	-357,961
Cash flow from financing activities	97,700	16,485	162,374
Effect of foreign exchange rate changes on cash	56	-417	-2,474
Net change in cash and cash equivalents	-4,885	-23,469	38,299
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	11,469	34,938	-3,361
CASH AND CASH EQUIVALENTS, END OF YEAR	6,584	11,469	34,938
Eliminations | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	0	-13,304	-1,210
Cash flow from investing activities	0	0	3
Cash flow from financing activities	0	13,304	1,207
Effect of foreign exchange rate changes on cash	0	0	0
Net change in cash and cash equivalents	0	0	0
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	0	0	0
CASH AND CASH EQUIVALENTS, END OF YEAR	0	0	0
Magnum Hunter Resources Corporation Consolidated | 9.75 Percent Senior Notes Due May 15, 2020 [Member]
Schedule of condensed consolidating statements of cash flows
Cash flow from operating activities	-18,665	111,711	58,011
Cash flow from investing activities	-318,119	-127,860	-1,009,207
Cash flow from financing activities	348,195	656	996,442
Effect of foreign exchange rate changes on cash	56	-417	-2,474
Net change in cash and cash equivalents	11,467	-15,910	42,772
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	41,713	57,623	14,851
CASH AND CASH EQUIVALENTS, END OF YEAR	$53,180	$41,713	$57,623

SUBSEQUENT_EVENTS_Details

SUBSEQUENT EVENTS (Details)	4 Months Ended		12 Months Ended			0 Months Ended		0 Months Ended
	Jun. 15, 2015	Jun. 15, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jan. 14, 2015	Jan. 14, 2015	Jan. 16, 2015	Jan. 16, 2015
	Subsequent Event	Subsequent Event	Irving, Texas [Member]	Asset Purchase Agreement With MNW	Asset Purchase Agreement With MNW	Asset Purchase Agreement With MNW	Asset Purchase Agreement With MNW	Natural Gas, Per Thousand Cubic Feet	Steppe Petroleum Inc
	USD ($)	CAD	Subsequent Event	Triad Hunter	Triad Hunter	Triad Hunter	Triad Hunter	Bakken Hunter LLC [Member]	Bakken Hunter LLC [Member]
			USD ($)	Utica Shale, Ohio	Utica Shale, Ohio	Utica Shale, Ohio	Utica Shale, Ohio	Subsequent Event	Subsequent Event
				USD ($)	acre	Subsequent Event	Subsequent Event	USD ($)	USD ($)
				acre		USD ($)	acre
SUBSEQUENT EVENTS
Business Combination, Acreage Of Undeveloped Leasehold Acquired				16,456	5,922		2,665
Payments to Acquire Land				$67,300,000		$12,000,000
Business Combination, Acreage Of Undeveloped Leasehold Available For Purchase							6,956
Severance Costs	435,000	550,000
Operating Leases, Rent Expense			366,000
Reimbursement Revenue									689,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period								$0.05

SUBSEQUENT_EVENTS_Details_2

SUBSEQUENT EVENTS (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 02, 2012
In Millions, except Share data, unless otherwise specified
Series A Preferred Stock
SUBSEQUENT EVENTS
Preferred Stock, shares issued	9,885,048	9,885,048
Eureka Hunter Holdings, LLC
SUBSEQUENT EVENTS
Ownership percentage by parent	48.60%	56.40%	61.00%
Eureka Hunter Holdings, LLC | Series A Preferred Stock
SUBSEQUENT EVENTS
Preferred Stock, shares issued				622,641
Value of common units issued related to acquisitions				$12.50

SUBSEQUENT_EVENTS_Details_3

SUBSEQUENT EVENTS (Details 3) (Senior Revolving Credit Facility)	Dec. 31, 2014	Dec. 31, 2013
Senior Revolving Credit Facility
SUBSEQUENT EVENTS
Interest rate (as a percent)	2.92%	2.92%

SUBSEQUENT_EVENTS_Details_5

SUBSEQUENT EVENTS (Details 5) (Eagle Ford Shale Assets, USD $)	0 Months Ended
In Millions, unless otherwise specified	Jan. 28, 2014
Eagle Ford Shale Assets
SUBSEQUENT EVENTS
Cash consideration received	$15.50

OTHER_INFORMATION_Quarterly_Un

OTHER INFORMATION Quarterly Unaudited Summary Financial Results (Details) (USD $)	3 Months Ended														12 Months Ended						9 Months Ended	12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Sep. 30, 2014	Sep. 30, 2014
Details of unaudited summary financial results
Total revenue	$59,854,000	[1]	$79,670,000	[1]	$138,463,000	[1]	$113,482,000	$90,179,000		$78,291,000		$76,686,000		$59,382,000	$391,469,000		$304,538,000		$159,937,000
Operating Income (Loss)	-401,575,000	[2]	-57,576,000	[2]	1,555,000	[2]	-32,762,000	-39,070,000		-119,874,000	[3]	-34,412,000		-41,437,000	-490,358,000		-234,793,000		-126,660,000
Income (loss) from continuing operations	103,320,000	[4]	-123,189,000	[4]	-61,407,000	[4]	-56,557,000	-14,382,000		-152,513,000		-3,634,000		-61,584,000	-137,833,000		-232,113,000		-129,357,000
Income (loss) from discontinued operations, net of tax	0		0		1,192,000		3,369,000	-108,000		-75,573,000	[5]	-3,764,000		16,884,000	4,561,000		-62,561,000		-9,773,000
Gain (loss) on disposal of discontinued operations, net of tax	128,000		-258,000		-5,212,000		-8,513,000	-31,421,000	[6]	-69,521,000	[6]	172,452,000	[6]	0	-13,855,000	[7],[8]	71,510,000	[7],[8]	2,409,000	[7],[8]
Net Income (loss) attributable to Magnum Hunter Resources Corporation	103,448,000		-120,683,000		-64,647,000		-61,592,000	-46,537,000		-296,882,000		165,440,000		-44,197,000	-143,474,000		-222,176,000		-132,708,000
Net Income (loss) attributable to common shareholders	42,767,000		-136,175,000		-79,997,000		-76,468,000	-61,208,000		-311,299,000		151,311,000		-57,685,000	-249,873,000		-278,881,000		-167,414,000
Loss from continuing operations per share, basic and diluted	$0.23		($0.68)		($0.41)		($0.41)	($0.17)		($0.98)		($0.10)		($0.44)	($1.27)		($1.69)		($1.03)
Loss per common share, basic and diluted	$0.23		($0.68)		($0.43)		($0.44)	($0.36)		($1.83)		$0.89		($0.34)	($1.32)		($1.64)		($1.07)
Exploration expense	66,100,000
Impairment of proved oil and gas properties	261,500,000														301,276,000		89,041,000		4,096,000
General and administrative expense	32,600,000														108,687,000	[9]	82,461,000	[9]	62,347,000	[9]
Loss on derivative contracts			49,600,000		42,800,000
Gain on deconsolidation															509,563,000		0		0
Impairment expense related to discontinued operations										72,500,000
Properties in Burke County, North Dakota [Member]
Details of unaudited summary financial results
Loss on the sale of certain properties										38,100,000
Magnum Hunter Production and Williston Hunter Canada
Details of unaudited summary financial results
Gain (loss) on disposal of discontinued operations, net of tax																					-12,900,000
Impairment expense related to discontinued operations							$18,600,000	$18,200,000		$55,600,000					$18,500,000		$65,400,000		$256,000			$67,600,000
[1]	(1) 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.
[2]	(2) The quarter-ended June 30, 2014 income from operations 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 Companybs capital account with Eureka Hunter Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipelinebs fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects.
[3]	(4) The quarter-ended September 30, 2013 loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.
[4]	(3) 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 Hunter 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 $510 million from the deconsolidation of Eureka Hunter Holdings. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb.
[5]	(5)B The quarter-ended September 30, 2013 loss from discontinued operations was primarily driven by impairment expense of $72.5 million, as management determined a significant portion of the non-core acreage would not be utilized.
[6]	(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.
[7]	(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[8]	(4)The Companybs 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.
[9]	2014 includes the recognition of a $32.6 million non-cash loss related to the downward adjustment of the Companybs equity interest in Eureka Hunter Holdings related to excess capital expenditures in 2014. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb in the accompanying Notes to Consolidated Financial Statements.

OTHER_INFORMATION_Supplemental

OTHER INFORMATION Supplemental Oil and Gas Disclosures (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities
Purchase of non-producing leases	$124,411	$149,592	$414,037
Purchase of producing properties	12,246	1,358	159,290
Exploration costs	9,907	11,531	165,789
Development costs	321,053	273,944	262,486
Asset retirement obligation	6,085	2,186	407
Costs incurred, acquisition of oil and gas properties, Total	$473,702	$438,611	$1,002,009

OTHER_INFORMATION_Oil_and_Gas_

OTHER INFORMATION Oil and Gas Reserves (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBbls	MBbls	MBbls	MBbls	MBbls
	MBoe
Summary of estimating quantities of proved reserves data
Extensions, discoveries, and other additions	26,988	862
Increase (Decrease) in proved reserves	26,126
Crude Oil and Liquids
Summary of estimating quantities of proved reserves data
Beginning balance	24,335	36,827	24,335	36,827	17,124
Revisions of previous estimates			-6,540	3,766	7,936
Purchases of reserves in place				0	10,613
Extensions, discoveries, and other additions			1,705	577	3,305
Sales of reserves in place			-7,321	-14,506	-10
Production			-1,658	-2,329	-2,141
Ending balance			10,521	24,335	36,827
Developed reserves, included above (Volume)			6,938	12,085	16,355
Proved undeveloped reserves (Volume)			3,583,000	12,250,000	20,472,000
NGL
Summary of estimating quantities of proved reserves data
Beginning balance	10,422	9,125	10,422	9,125	4,585
Revisions of previous estimates			2,149	2,382	4,632
Purchases of reserves in place				0	0
Extensions, discoveries, and other additions			3,226	71	110
Sales of reserves in place			-434	-698	0
Production			-960	-458	-202
Ending balance			14,403	10,422	9,125
Developed reserves, included above (Volume)			10,587	6,990	6,262
Proved undeveloped reserves (Volume)			3,816,000	3,432,000	2,863,000
Natural Gas
Summary of estimating quantities of proved reserves data
Beginning balance	246,782	162,620	246,782	162,620	139,237
Revisions of previous estimates			-511	100,456	25,644
Purchases of reserves in place				88	12,082
Extensions, discoveries, and other additions			132,345	1,285	544
Sales of reserves in place			-3,768	-4,185	-63
Production			-21,847	-13,482	-14,824
Ending balance			353,001	246,782	162,620
Developed reserves, included above (Volume)			251,628	176,585	125,526
Proved undeveloped reserves (Volume)			101,373,000	70,197,000	37,094,000
Eagle Ford Hunter
Summary of estimating quantities of proved reserves data
Proved reserves included in sale (energy)				11,459
Certain North Dakota Oil and Gas Properties
Summary of estimating quantities of proved reserves data
Proved reserves included in sale (energy)				4,308
Eagle Operating
Summary of estimating quantities of proved reserves data
Purchases of reserves in place					2,217
Baytex Energy Corporation USA, Ltd.
Summary of estimating quantities of proved reserves data
Purchases of reserves in place					8,595
Virco
Summary of estimating quantities of proved reserves data
Purchases of reserves in place					1,428.90

OTHER_INFORMATION_Standardized

OTHER INFORMATION Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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	$3,282,768	$3,711,260	$4,248,384
Future production costs	1,443,121	1,423,306	1,520,260
Future development costs	219,509	421,797	603,809
Future income tax expense	0	149,367	230,500
Future net cash flows	1,620,138	1,716,790	1,893,815
10% annual discount for estimated timing of cash flows	-710,875	-872,280	-1,046,162
Standardized measure of discounted future net cash flows	$909,263	$844,510	$847,653

OTHER_INFORMATION_Changes_in_S

OTHER INFORMATION Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Balance, beginning of period	$844,510		$847,653		$474,396
Net changes in prices and production costs	-281,352		-7,355		13,647
Changes in estimated future development costs	-57,348		-261,591		-391,318
Sales and transfers of oil and gas produced during the period	-166,611		-190,151		-179,384
Net changes due to extensions, discoveries, and improved recovery	332,684		12,829		60,468
Net changes due to revisions of previous quantity estimates (1)	-55,176	[1]	341,003	[1]	290,500	[1]
Previously estimated development costs incurred during the period	269,017		283,736		245,168
Accretion of discount	95,547		90,153		85,377
Purchase of minerals in place	0		218		217,791
Sale of minerals in place	-141,847		-236,885		-354
Changes in timing and other (2)	-7,720	[2]	-91,088	[2]	22,436	[2]
Net change in income taxes	77,559		55,988		8,926
Standardized measure of discounted future net cash flows	$909,263		$844,510		$847,653
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)	-6,540		3,766		7,936
NGL
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Revisions of previous estimates (volume)	2,149		2,382		4,632
Natural Gas
Changes in standardized measure of discounted future net cash flow relating to proved oil and gas reserves
Revisions of previous estimates (volume)	-511		100,456		25,644
[1]	The Company's net changes due to revisions of previous quantity estimates primarily reflect upward revisions to recoverable quantities of oil and gas minerals assuming existing prices and technology. For the year ended December 31, 2014, the Company made downward revisions of 6,540 MBbl 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. For the year ended December 31, 2012, the Company made upward revisions of 7,936 MBbls of oil, 4,632 MBbl of natural gas liquids and 25,644 MMcf of natural gas.
[2]	The Company's changes in timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. The reserves as of December 31, 2012, reflect accelerated recovery of minerals due to purchases of minerals in place and capital expenditures incurred to develop properties.

OTHER_INFORMATION_Commodity_Pr

OTHER INFORMATION Commodity Prices Related to the Standardized Measure Calculation (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil (per bbl)
Average Sales Price and Production Costs Per Unit of Production
Commodity prices inclusive of adjustments for quality and location	85.21	93.13	88.37
Natural gas liquids (per bbl)
Average Sales Price and Production Costs Per Unit of Production
Commodity prices inclusive of adjustments for quality and location	50.64	43.79	53.94
Gas (per mcf)
Average Sales Price and Production Costs Per Unit of Production
Commodity prices inclusive of adjustments for quality and location	4.69	4.14	3.08

OTHER_INFORMATION_Narratives_D

OTHER INFORMATION Narratives (Details) (USD $)	3 Months Ended														12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information
Oil and gas sales															$268,501		$220,699		$133,728
Midstream natural gas gathering, processing, and marketing															97,916		61,178		13,040
Oilfield services															23,134		18,431		12,333
Other revenue															1,918		4,230		836
Total revenue	59,854	[1]	79,670	[1]	138,463	[1]	113,482	90,179		78,291		76,686		59,382	391,469		304,538		159,937
Production costs															47,857		46,689		30,119
Severance taxes and marketing															17,344		18,282		8,043
Exploration															118,509		100,389		80,375
Midstream natural gas gathering, processing, and marketing															84,764		52,099		8,028
Oilfield services															15,686		14,825		10,037
Impairment of proved oil and gas properties															301,276		50,011		3,839
Depreciation, depletion, amortization and accretion															146,868		107,385		72,438
Loss on sale of assets															-2,456		44,641		596
General and administrative (1)	32,600														108,687	[2]	82,461	[2]	62,347	[2]
Total expenses															881,827		539,331		286,597
OPERATING LOSS	-401,575	[3]	-57,576	[3]	1,555	[3]	-32,762	-39,070		-119,874	[4]	-34,412		-41,437	-490,358		-234,793		-126,660
Interest income															156		265		202
Gain (loss) on derivative contracts, net															-72,254		-25,274		22,239
Other income															2,561		15,897		4,014
Total other expense															352,525		-82,727		-27,362
Loss from continuing operations before income tax															-137,833		-317,520		-154,022
Income tax benefit															0		85,407		24,665
Income (loss) from continuing operations	103,320	[5]	-123,189	[5]	-61,407	[5]	-56,557	-14,382		-152,513		-3,634		-61,584	-137,833		-232,113		-129,357
Income (loss) from discontinued operations	0		0		1,192		3,369	-108		-75,573	[6]	-3,764		16,884	4,561		-62,561		-9,773
Gain (loss) on disposal of discontinued operations	128		-258		-5,212		-8,513	-31,421	[7]	-69,521	[7]	172,452	[7]	0	-13,855	[8],[9]	71,510	[8],[9]	2,409	[8],[9]
Net income (loss)															-147,127		-223,164		-136,721
Net loss attributable to non-controlling interests															3,653		988		4,013
Net loss attributable to Magnum Hunter Resources Corporation	103,448		-120,683		-64,647		-61,592	-46,537		-296,882		165,440		-44,197	-143,474		-222,176		-132,708
Dividends on preferred stock															-54,707		-56,705		-34,706
Net loss attributable to common shareholders	42,767		-136,175		-79,997		-76,468	-61,208		-311,299		151,311		-57,685	-249,873		-278,881		-167,414
Total segment assets	1,669,829							1,856,651							1,669,829		1,856,651		2,198,632
Segment capital expenditures															562,324		631,511		568,610
U.S. Upstream
Segment Reporting Information
Total revenue															270,615		225,498		134,339
Depreciation, depletion, amortization and accretion															127,607		92,713		65,040
Loss on sale of assets															-2,075		44,629		246
Total other expense															1,340		-656		-10,210
Loss from continuing operations before income tax															-409,662		-180,435		-108,580
Income tax benefit																	56,418		24,665
Net income (loss)															-416,817		35,208		-65,059
Total segment assets	1,162,732							1,373,041							1,162,732		1,373,041		1,602,022
Canadian Upstream
Segment Reporting Information
Total revenue															0		0		0
Depreciation, depletion, amortization and accretion															0		0		0
Loss on sale of assets															0		0		0
Total other expense															0		0		0
Loss from continuing operations before income tax															0		0		0
Income tax benefit																	0		0
Net income (loss)															10,636		-150,207		-25,021
Total segment assets	0							68,367							0		68,367		392,918
Midstream
Segment Reporting Information
Total revenue															109,658	[10]	69,306	[10]	15,692	[10]
Depreciation, depletion, amortization and accretion															15,737	[10]	12,318	[10]	5,963	[10]
Loss on sale of assets															-12	[10]	8	[10]	-250	[10]
Total other expense															-99,221	[10]	-22,358	[10]	7,388	[10]
Loss from continuing operations before income tax															-98,426	[10]	-25,875	[10]	5,661	[10]
Income tax benefit																	0	[10]	0	[10]
Net income (loss)															-98,426	[10]	-25,875	[10]	5,661	[10]
Total segment assets	454	[10]						296,739	[10]						454	[10]	296,739	[10]	245,207	[10]
Oil Field Services
Segment Reporting Information
Total revenue															31,392		21,527		13,552
Depreciation, depletion, amortization and accretion															3,524		2,354		967
Loss on sale of assets															-369		4		600
Total other expense															-813		-507		-482
Loss from continuing operations before income tax															782		-590		665
Income tax benefit																	0		0
Net income (loss)															782		-590		810
Total segment assets	46,995							44,193							46,995		44,193		23,810
Corporate Unallocated
Segment Reporting Information
Total revenue															0	[11]	0		0
Depreciation, depletion, amortization and accretion															0	[11]	0		0
Loss on sale of assets															0	[11]	0		0
Total other expense															454,921	[11]	-61,446		-24,121
Loss from continuing operations before income tax															373,175	[11]	-110,687		-51,258
Income tax benefit																	28,989		0
Net income (loss)															360,400	[11]	-81,698		-51,258
Total segment assets	462,025	[11]						77,684							462,025	[11]	77,684		93,612
Intersegment Eliminations
Segment Reporting Information
Total revenue															-20,196		-11,793		-3,646
Depreciation, depletion, amortization and accretion															0		0		468
Loss on sale of assets															0		0		0
Total other expense															-3,702		2,240		63
Loss from continuing operations before income tax															-3,702		67		-510
Income tax benefit																	0		0
Net income (loss)															-3,702		-2		-1,854
Total segment assets	($2,377)							($3,373)							($2,377)		($3,373)		($158,937)
[1]	(1) 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.
[2]	2014 includes the recognition of a $32.6 million non-cash loss related to the downward adjustment of the Companybs equity interest in Eureka Hunter Holdings related to excess capital expenditures in 2014. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb in the accompanying Notes to Consolidated Financial Statements.
[3]	(2) The quarter-ended June 30, 2014 income from operations 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 Companybs capital account with Eureka Hunter Holdings was adjusted down in order to take into account certain excess capital expenditures incurred by Eureka Hunter Pipeline in connection with certain of Eureka Hunter Pipelinebs fiscal year 2014 pipeline construction projects and planned fiscal year 2015 pipeline construction projects.
[4]	(4) The quarter-ended September 30, 2013 loss from operations was primarily driven by the loss on the sale of certain properties in Burke County, North Dakota of $38.1 million, and exploration expense. Management reviews leasehold acreage on a quarterly basis. During the quarter-ended September 30, 2013, management determined a significant portion of the non-core Williston Basin acreage would not be utilized as the Company planned to focus on assets that will provide a higher rate of return.
[5]	(3) 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 Hunter 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 $510 million from the deconsolidation of Eureka Hunter Holdings. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb.
[6]	(5)B The quarter-ended September 30, 2013 loss from discontinued operations was primarily driven by impairment expense of $72.5 million, as management determined a significant portion of the non-core acreage would not be utilized.
[7]	(6) The quarter-ended June 30, 2013 gain on disposal of discontinued operations was primarily due to the gain on sale of the Company's Eagle Ford Shale assets. The quarter-ended September 30, 2013 loss on disposal of discontinued operations was primarily due to an expense of $55.6 million, net of tax, to reflect the net assets of WHI Canada to their fair values as a result of the Company's decision to sell these assets. The quarter-ended December 31, 2013 loss on disposal of discontinued operations was primarily due to an expense of $18.2 million, net of tax, to reflect changes in the estimated fair values of the net assets of WHI Canada which the Company had decided to sell during the quarter ended September 30, 2013. See bNote 3 - Acquisitions, Divestitures, and Discontinued Operationsb.
[8]	(3)Income tax expense associated with gain/(loss) on sale of discontinued operations was none, $11.9 million, and $1.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[9]	(4)The Companybs 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.
[10]	Includes operations of Eureka Hunter Holdings, which represents approximately 38.6%, 40.7%, and 71.6% of Midstream and Marketing revenues for the years ended DecemberB 31, 2014, 2013, and 2012, respectively, and which was deconsolidated as of December 18, 2014. See bNote 2 - Deconsolidation of Eureka Hunter Holdingsb.
[11]	Includes the Companybs retained interest in Eureka Hunter Holdings which has a value of $347 million at December 31, 2014.